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, 2003

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ý No o

The aggregate market value of Registrant's voting stock held by non-affiliates of Registrant, on June 30, 2003 (based on the closing sale price of $6.35 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $3,932,416,062. The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on March 3, 2004, was 628,775,109.

Certain information from the registrant's Proxy Statement for the Annual Meeting of Stockholders to be held on April 28, 2004 is hereby incorporated by reference into Part III hereof.

The AES Corporation (including all its subsidiaries and affiliates, and collectively referred to herein as "AES", "the Company", "us" or "we") is a leading global power company. A Delaware corporation formed in 1981, AES is a holding company that, through its subsidiaries operates in four segments of the electricity industry: contract generation, competitive supply, large utilities and growth distribution. The Company's generating assets include interests in 114 facilities in 24 countries totaling over 38 gigawatts of capacity. AES's electricity distribution networks sell approximately 86,500 gigawatt hours per year.

Our principal offices are located at 1001 North 19th Street, Suite 2000, Arlington, Virginia 22209. Our telephone number is (703) 522-1315, and our web address is http://www.aes.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 are posted on our website at http://www.aes.com. After the reports are filed with the Securities and Exchange Commission, they are available from the Company free of charge. Material contained on our website is not part of and is not incorporated by reference in this report on Form 10-K.

We operate in four business segments: contract generation, competitive supply, large utilities and growth distribution. The following table shows the percentage of our revenues contributed by each of our business segments for fiscal year 2003:

The following table shows the percentage of current operating capacity by fuel for fiscal year 2003:

See Note 20 to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional financial information about our business segments as well as information about our foreign and domestic operations.

Our contract generation line of business is comprised of generation facilities that have contractually limited their exposure to commodity price risks, primarily electricity price volatility, by entering into longer term (originally five years or longer) power sales agreements for 75% or more of their output capacity. These power sales agreements are typically entered into with one major wholesale customer, but also may involve a series of unrelated customers. These facilities are better able to manage their expenses because they have contracted buyers for a majority of their anticipated output. They can project their fuel supply requirements and generally enter into long-term agreements for most of their fuel supply requirements, thereby limiting their exposure to short-term fuel price volatility. In addition, these facilities may enter into tolling or "pass through" arrangements in which the counter-party directly assumes the risks associated with providing the necessary fuel and then markets the generated power. Through these types of contractual agreements, our contract generation businesses generally produce more predictable cash flows and earnings. The degree of predictability varies from business to business based on the degree to which their exposure is limited by the contracts they have negotiated with their buyers.

Our contract generation segment is comprised of our interests in 61 power generating facilities totaling over 18 gigawatts of capacity located in 18 countries. It also includes minority interests in 7 power

generation facilities totaling over 4 gigawatts of capacity. Of the total 22 gigawatts of current operating capacity, 29% is derived from coal-fired facilities, 8% from oil-fired facilities, 49% from gas-fired facilities, 13% from hydro facilities and 1% from biomass facilities.

In most of our contract generating businesses, a single customer contracts for most or all of a particular facility's generated power. To reduce the resulting counter-party credit risk, we seek to contract with customers who have investment grade debt ratings, including regulated utilities that are regulated by state or local public utility commissions ("PUCs") which tend to have stable cash flows. We also may obtain sovereign government guarantees of the customer's obligations. However, we do not limit our business solely to customers with investment grade debt ratings or to those countries with investment grade sovereign credit ratings. We believe that locating our plants in different geographic areas helps to mitigate the effects of regional economic downturns, thereby offsetting some of the risks associated with operating in less developed countries.

Certain of our subsidiaries and affiliates (domestic and non-U.S.) are in various stages of developing and constructing greenfield power plants. Some have signed long-term contracts or made similar arrangements for the sale of electricity. We currently have one power generation facility under construction, totaling approximately 1,200 MW of capacity. We are also completing the construction of the second phase of the Ras Laffan combined cycle facility for an additional 346MW. As of December 31, 2003, capitalized costs for these projects under construction were approximately $584 million. We currently believe that these costs are recoverable but can provide no assurance that we will complete these individual projects and/or that these projects will reach commercial operation.

In the contract generation segment, we face most of our competition prior to the execution of a power sales agreement during the development phase of a project. Our competitors in this business include other independent power producers as well as various utilities and their affiliates. During the operational phase, we traditionally have faced limited competition in this segment due to the long-term nature of the generation contracts. However, since competitive power markets have been introduced and new market participants have been added, we will encounter increased competition in attracting new customers and maintaining our current customers as our existing contracts expire. In particular, over the past year, in the United States, traditional regulated utilities have reserved their interest in purchasing either existing or under construction merchant power plants or development rights to new greenfield power plants within their service areas or construct their own generation under some form of cost-based regulation directly or through merchant affiliates.

The facilities in our competitive supply segment sell electricity directly to wholesale customers in competitive markets. In contrast to the contract generation segment discussed above, these facilities generally sell less than 75% of their output under long-term contracts. They often sell into power pools under shorter-term contracts or into daily spot markets. The prices these facilities sell under short-term contracts and in the spot electricity markets are unpredictable and can be volatile. In addition, our operational results in this segment are more sensitive to the impact of market fluctuations in the price, natural gas, coal, oil and other fuels. These businesses also have more significant needs for working capital or credit to support their operations.

Our competitive supply segment is comprised of our interests in 35 power generation facilities totaling over 15 gigawatts of capacity located in 8 countries. Of the total 15 gigawatts of current operating capacity, 55% is derived from coal-fired facilities, 17% from gas-fired facilities, 25% from hydro facilities, 2% from oil facilities, 1% from petroleum coke facilities and less than 1% from biomass facilities. We are currently constructing one competitive supply facility totaling 185 MW. As of December 31, 2003, we were completing the rehabilitation of one of our units at the Bayano facility in

Panama for an additional 12 MW. This unit was completed and went into commercial operations in February 2004.

The absence of long-term contracts makes future production volumes uncertain, which in turn makes it difficult to forecast the amount of fuel needed to support those volumes. As a result, competitive supply businesses are exposed to volume risk in connection with their purchases of natural gas, coal and other raw materials. Where appropriate, we have hedged a portion of our financial performance against the effects of fluctuations in energy commodity prices using such strategies as commodity forward contracts, futures, swaps and options.

Although we maintain credit policies with regard to our counterparties, there can be no assurance that these ultimately will be able to fulfill their contractual obligations. One of the principal outcomes of recent volatility in electricity markets has been a substantial increase in credit risk, a decline in the number and quality of market participants with strong credit ratings, and considerably less liquidity in energy markets.

We compete in this segment with numerous other independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers, and retail energy suppliers. Competitive factors in this segment include price, contract terms, including credit requirements, and quality of service.

Our large utility segment consists of electric utilities that are of significant size and maintain a monopoly franchise within a defined service area. In most cases our large utilities combine generation, transmission and distribution capabilities. Currently, this segment is comprised of three utilities: IPALCO Enterprises, Inc. ("IPALCO"), Eletropaulo, and EDC. We have a 100% common equity interest in IPALCO, a 70% common equity interest in Eletropaulo (50.01% after the January 2004 restructuring) and an 86% common equity interest in EDC. Our large utilities aggregate 5,854 gross MW of generation capacity and serve over 6.5 million customers with annual sales of nearly 58,900 gigawatt hours. Our large utilities are subject to extensive local, state and national regulation relating to ownership, marketing, delivery and pricing of electricity and gas with a focus on protecting customers. Large utility revenues result primarily from retail electricity sales to customers under regulated tariff or concession agreements and to a lesser extent from contractual agreements of varying lengths and provisions.

IPALCO is a holding company and its principal subsidiary is Indianapolis Power & Light Company ("IPL"). IPL is engaged in generating, transmitting, distributing and selling electric energy to approximately 450,000 customers in the City of Indianapolis and neighboring areas within the state of Indiana. IPL owns and operates four generation facilities. Two generating facilities are primarily coal-fired plants. The third facility has a combination of units that use coal (base load capacity) and natural gas and/or oil (peaking capacity). The fourth facility is a small peaking station that uses gas-fired combustion turbine technology. IPL's net generation winter capability is 3,356 MW and net summer capability is 3,238 MW. We acquired IPALCO in March 2001. In connection with our acquisition of IPALCO, we were required under the U.S. Public Utility Holding Company Act ("PUHCA") to dispose of our 100% ownership interest in CILCORP, a utility holding company whose largest subsidiary is Central Illinois Light Company ("CILCO"), also a regulated utility. In January 2003, we sold CILCORP to Ameren Corporation in a transaction valued at $1.4 billion including the assumption of debt and preferred stock at the closing. As part of the transaction we also sold AES Medina Valley Cogen ("Medina Valley"), a gas-fired cogeneration facility located in CILCO's service territory on February 4, 2003. The CILCORP and Medina Valley sales generated net proceeds (after expenses) of approximately $500 million, subject to certain adjustments. CILCORP was previously reported in the large utilities segment.

Eletropaulo has served the São Paulo, Brazil area for over 100 years and is the largest electricity distribution company in Latin America in terms of revenues. Eletropaulo's concession contract with the Brazilian National Electric Energy Agency ("ANEEL"), the government agency responsible for regulating the Brazilian electric industry, entitles Eletropaulo to distribute electricity in its service area for 30 years. Eletropaulo's service territory consists of 24 municipalities in the greater São Paulo metropolitan area and adjacent regions that account for approximately 15% of Brazil's GDP, covering 5.0 million customers or 44% of the population in the State of São Paulo, Brazil.

We began consolidating Eletropaulo in February 2002 when we acquired a controlling interest in Eletropaulo by exchanging a minority interest in another large utility, Light Servicos de Eletricidade S.A. ("Light"), for an additional 31% common equity interest in Eletropaulo. In January 2004, we completed a restructuring of $1.3 billion (including interest) of indebtedness owed to the Brazilian National Development Bank, ("BNDES"), and its affiliate BNDESPAR Participações S.A. ("BNDESPAR") by some of our Brazilian holding companies. Pursuant to the restructuring, we and BNDES created a new company, Brasiliana Energia S.A ("Brasiliana Energia"), to which we contributed $90 million as well as our direct and indirect interests in Eletropaulo, Uruguaiana and Tiete. AES Sul may be contributed upon the successful completion of its financial restructuring. Pursuant to the shareholders agreement between us and BNDES, we control Brasiliana Energia through the ownership of a majority of the voting shares of the company. We own 50.01% of the common shares and BNDES owns 49.99% of the common shares plus non-voting preferred shares, giving BNDES approximately 53.84% of the total equity capital of Brasiliana Energia. The shareholders' agreement requires that we and BNDES act unanimously with respect to listed corporate events and actions. In return, Eletropaulo's debt owed to BNDES was reduced to $510 million, and is evidenced by convertible debentures of Brasiliana Energia, which are payable over an 11-year period (and remain non-recourse to us). The debentures are convertible into shares of Brasiliana Energia upon the occurrence of an event of default, which would give BNDES control of Brasiliana Energia.

EDC was founded in 1895 and is the largest private-sector electric utility in Venezuela serving approximately one million customers. EDC generates, transmits and distributes electricity primarily to metropolitan Caracas and its surrounding area. EDC's distribution area covers 5,176 square kilometers. EDC has an installed generating capacity of 2,616 MW.

Historically, energy utilities have operated within specific service territories where they were essentially the sole suppliers of electricity services. As a result, competition was limited to alternative means of energy such as gas and fuel. However, in certain locations, the large utilities business is currently facing significant challenges and increased competition as a result of changes in laws and regulations which allow wholesale and retail services to be provided on a competitive basis. We can provide no assurance that deregulation will not adversely affect our large utilities' future operations, cash flows and financial condition.

Our growth distribution segment is comprised of our interests in electricity distribution facilities located in developing countries where the demand for electricity is expected to grow at a higher rate than in more developed parts of the world. The conditions of the business environment in a developing nation also provide for significant opportunities to implement operating improvements that may stimulate growth in earnings and cash flow performance. These growth rates may be greater than those typically achievable in our other business segments. Often, however, these businesses face particular challenges associated with their presence in developing countries such as outdated equipment, significant electricity theft-related losses, cultural problems associated with customer safety and non-payment, emerging economies, and potentially less stable governments or regulatory regimes. Distribution facilities included in this segment may include generation, transmission, distribution or related services companies. The results of operations of our growth distribution business are sensitive to changes in

economic growth and regulation, abnormal weather conditions affecting each local market, as well as the success of the operational changes that have been implemented.

We derive growth distribution revenues from the distribution and sale of electricity 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. One of our distribution facilities, SONEL, is "integrated," in that it also owns electric power plants for the purpose of generating a portion of the electricity it sells. The facilities currently in this segment contribute approximately 850 gross MW of generation and serve nearly 4.7 million customers with sales exceeding 25,600 gigawatt hours in Argentina, Brazil, Cameroon, El Salvador, and Ukraine.

The facilities in the growth distribution segment face relatively little direct competition due to significant barriers to entry present in these markets. In this segment, we primarily face competition in our efforts to acquire businesses. We compete against a number of other participants, some of which have greater financial resources, have been engaged in growth distribution related businesses for periods longer than we have and have accumulated more significant portfolios. Relevant competitive factors include financial resources, governmental assistance, and access to non-recourse financing and regulatory factors.

The following tables present information with respect to the facilities in each of our four business segments. The amounts under "Gross MW" and "Approximate Gigawatt Hours" represent the gross amounts for each facility without regard to our percentage of equity interest in the facility.

We sell to a wide variety of customers. No individual customer accounted for more than 10% of our 2003 net sales.

Paul T. Hanrahan, 46 years old, is the President and Chief Executive Officer of the Company. Prior to assuming his current position, Mr. Hanrahan was the Chief Operating Officer and Executive Vice President of the Company. In this role he was responsible for business development activities and the operation of multiple electric utilities and generation facilities in Europe, Asia and Latin America. Mr. Hanrahan was previously the President and CEO of the AES China Generating Company, a public company listed on NASDAQ. Mr. Hanrahan also has managed other AES businesses in the United States, Europe and Asia. Prior to joining AES, Mr. Hanrahan served as a line officer on the U.S. fast attack nuclear submarine, USS Parche (SSN-683).

Joseph C. Brandt, 39 years old, is Executive Vice President, Chief Operating Officer of Integrated Utilities and Chief Restructuring Officer of the Company. From January 2002 to February 2003, Mr. Brandt was President and Group Manager for AES Andes, covering AES business interests in Argentina. From 1998 to 2002, Mr. Brandt held various corporate and development positions with the Company. Prior to joining the Company, Mr. Brandt was an Investment Analyst & Portfolio Manager at McGinnis Advisors in San Antonio, Texas. Mr. Brandt also held positions at the law firm, Latham & Watkins, and at the University of Santa Clara, California.

Robert F. Hemphill, Jr., 60 years old, was appointed Executive Vice President, Global Development on February 5, 2004. Mr. Hemphill served as a director of AES from June 1996 to February 2004 and was an Executive Vice President from 1982 to June 1996. Prior to this, Mr. Hemphill held various leadership positions since joining the Company in 1982. Mr. Hemphill also serves on the Boards of ServiceWare Inc., Trophogen Inc. and Chameleon Technologies.

William R. Luraschi, 40 years old, was appointed Executive Vice President in July 2003 and has been Vice President of the Company since January 1998, and General Counsel of the Company since January 1994. Mr. Luraschi also was Secretary from February 1996 until June 2002. Prior to that, Mr. Luraschi was an attorney with the law firm of Chadbourne & Park L.L.P.

John Ruggirello, 53 years old, was appointed Chief Operating Officer for Generation in February 2003. Mr. Ruggirello was appointed Executive Vice President of the Company in February 2000, was Senior Vice President until February 2000 and was appointed Vice President in January 1997. Mr. Ruggirello previously led the AES Enterprise Group, with responsibility for project development, construction and plant operations in the United States. Prior to joining the Company in 1987, Mr. Ruggirello was Operations Manager for a division of the Diamond Shamrock Corporation.

Barry J. Sharp, 44 years old, is Chief Financial Officer. Mr. Sharp is responsible for overseeing the finance function. Mr. Sharp was appointed Executive Vice President in February 2001. Mr. Sharp was appointed Senior Vice President in January 1998 and had been Vice President and Chief Financial Officer since 1987. He also served as Secretary of the Company until February 1996. From 1986 to 1987, Mr. Sharp served as the Company's Director of Finance and Administration. Mr. Sharp is a certified public accountant.

United States. The Federal Energy Regulatory Commission ("FERC") has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy under the Federal Power Act ("FPA") and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The Securities and Exchange Commission ("SEC") has regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935 ("PUHCA"). Holding companies that are registered with the SEC under PUHCA are subject to extensive regulation with respect to corporate structure and financial transactions. The enactment of the Public Utility Regulatory Policies Act of 1978 ("PURPA") and FERC's adoption of regulations under it provided incentives for the development of cogeneration facilities and small power production facilities utilizing alternative or renewable fuels by establishing certain exemptions from the FPA and PUHCA for the owners of qualifying facilities. The passage of Section 32 of PUHCA in 1992 further encouraged independent power production by providing exemptions from PUHCA for exempt wholesale generators. Exempt wholesale generators are entities determined by the FERC to be exclusively engaged, directly or indirectly in the business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a foreign country, at wholesale or retail. Section 33 of PUHCA, also passed in 1992, encouraged investment in foreign utilities by exempting such investments from regulation under PUHCA.

Over the past decade the United States has implemented a series of regulatory policies that encourage competition in wholesale and retail electricity markets. The United States has implemented these policies at the federal level and in many states, reflecting the federal structure of the U.S. system. The federal government regulates wholesale power markets and transmission facilities in most of the continental U.S., while each of the fifty states regulates retail electricity markets and distribution.

Beginning in the fall of 2001, regulatory officials both in the United States and abroad began to re-examine the nature and pace of deregulation of electricity markets. This re-examination was primarily a result of extreme price volatility and energy shortages in California and portions of the western markets during the period from May 2000 through June 2001. Allegations of price manipulation by some of the largest power suppliers as well as the bankruptcy of Enron, previously the largest U.S. electricity trading company, have in part led to this re-examination. The re-examination has not occurred in a uniform manner, but rather has differed from state to state and has differed between the federal government and the states themselves. Thus, over the last several years California and several other states have abandoned the framework for deregulation that had been adopted in the 1990s, while the FERC has continued its efforts to enhance "open access" electric transmission and enhance competition in bulk power markets, albeit at a somewhat slower pace.

The California state government has imposed emergency measures that have effectively repealed California electric market restructuring legislation in order to address volatility in the wholesale power markets in California, as well as structural flaws inherent in the state's deregulation law that shifted the risk of wholesale deregulation to the state's investor-owned utilities. While the confluence of events that occurred in California may not be repeated in other states pursuing restructuring programs, the problems experienced in California could be repeated elsewhere if other states adopt, or have adopted, policies similar to those of California; particularly, the use of "default" or regulated retail prices while the market sets wholesale prices.

The events in California and the growing financial problems among many industry participants have generally caused legislators and regulators in other states to postpone restructuring legislation or even to propose a return to more traditional regulated markets. A survey by the Energy Information Administration shows that 18 states (including the District of Columbia) are actively pursuing restructuring, 6 states have delayed or suspended such restructuring, and 27 states have no active

restructuring plans. We believe that over the next decade the United States will continue to resemble a "patchwork quilt" of differing regulatory policies at the retail level. Because we have sold our primary retail electric business in the United States, we expect the impact of these differing retail policies on us to be small in the near term.

The federal government, through regulations promulgated by the FERC, has primary jurisdiction over wholesale electricity markets and transmission services. Since 1990, the FERC has approved market-based rates for many providers of wholesale generation, and the mix of market players has shifted dramatically toward non-utility entities, referred to as independent power producers or wholesale generators whose rates are based on competitive conditions rather than on costs. The FERC has proposed new regulations to implement a "standard market design"("SMD") for wholesale electric markets. This proposed rule generally is intended to further promote non-discriminatory, open access wholesale transmission and workably competitive wholesale generation markets. Some states and members of Congress have expressed concerns regarding the affect of the SMD proposal on their jurisdiction over retail-related services and price levels within their jurisdictions. It is uncertain whether the FERC will issue a final rule and in what form the final rule will be.

The U.S. Congress over the past few years has considered various legislative proposals to restructure the electric industry that, among other things, would repeal PUHCA and provide for prospective, partial repeal of PURPA. In addition, proposals have been introduced in Congress that incorporate provisions related to restructuring electricity markets. Different versions of such legislation passed both houses of Congress late in the last session and included provisions related to PUHCA repeal. Such legislation will provide the FERC with new authority related to imposing reliability standards, but would delay FERC implementation of the SMD rule for several years. A joint Conference Committee produced a report that was acceptable to the House, but that was unable to obtain sufficient votes in the Senate to limit extended debate by opponents seeking to delay, or filibuster, final adoption of the bill. It is unclear at this time whether the Senate will be able to muster sufficient votes in the current session to overcome a filibuster and obtain the needed waivers from budgetary rules and pass the Conference report. While there are some pending efforts to enact portions of the comprehensive energy bill on an individual basis, the likelihood of success is uncertain. At this point, it is uncertain whether any of this legislation will be enacted and if so, what its effect will be on our business.

As a result of price volatility during 2000 and 2001, allegations of withholding of supply, gaming and other abuses by various market participants, a large number of complaints and lawsuits were filed seeking billions of dollars in refunds and other penalties. Much of this litigation is still pending before the FERC and the courts. The ultimate resolution of these issues may result in significant market or regulatory changes that cannot currently be determined or predicted. For example, there are currently major changes pending in the structure and rules governing the California wholesale energy market. The outcome of any significant market or regulatory changes will affect market conditions for all market participants, including AES. Among the outstanding commercial issues are the status of certain payables owed to generators and marketers for power delivered during 2000 and 2001. Although our overall exposure to this risk is largely mitigated as a result of our tolling agreement related to the Southland plants (see description below), at December 31, 2003, we had receivables of $4 million relating to this period from various California entities. We are actively pursuing recovery of these amounts. In addition, the State of California is seeking refunds from certain entities, including us, that supplied power within the state during 2000 and 2001. Because the pricing of the majority of power we sold during that period was determined under the tolling agreement, we do not anticipate that we will have material exposure to such refunds. Nonetheless, we have been named in a number of proceedings and lawsuits related to the refunds and we are not certain of their outcome. See Item 3—Legal Proceedings.

We are an exempt public utility holding company under Section 3(a)(5) of PUHCA, which exempts us from most regulation under PUHCA and also allows us to own 100 percent interests in qualifying

facilities under PURPA. IPALCO is an exempt public utility holding company under Section 3(a)(1) of PUHCA, which exempts it from most regulation under PUHCA.

Argentina. In January and February 2002, the Argentine government adopted many new economic measures as a result of the continuing political, social and economic crisis. These economic measures included the abandonment of the country's fixed dollar-to-peso exchange rate, the conversion of U.S. dollar-denominated loans into pesos and the placement of restrictions on the convertibility of the Argentine peso. The Argentine government also adopted new regulations in the energy sector which effectively repealed U.S. dollar-denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina, by fixing all prices to consumers in pesos. In 2003, the political and social situation in Argentina showed signs of stabilization, the Argentine peso appreciated to the U.S. dollar, and the economy and electricity demand started to recover. Presidential elections and the establishment of a new government regime occurred in May 2003.

The regulations adopted in 2002 and 2003 in the energy sector effectively overturned the U.S. dollar based nature of the electricity sector. Formerly, both the wholesale generation market and the distribution sector received payments that were linked to the U.S. dollar, not only because of the Convertibility Law that pegged the peso at a 1:1 exchange rate with the U.S. dollar, but also because the price paid for wholesale generation reflected the U.S. dollar-linked nature of the fuels used by the country's generating facilities.

In the wholesale power market, electricity generators declared their costs of generation (which reflected their fuel costs) on a semi-annual basis. For thermal generators, these fuel costs reflected the U.S. dollar costs of these commodities. Under the current regulations both the declaration of costs and the prices received as capacity and energy payments are denominated in pesos but are not permitted to reflect the devaluation of the peso against the U.S. dollar. As a result, thermal generator's fuel costs no longer reflect the true costs of producing or delivering that fuel. At the same time generation prices now reflect an artificially low fuel price and, as a result, the real price received for wholesale generation has been reduced by nearly 50% from 2001. In addition, during 2003 new regulations have fixed a cap to the wholesale power market prices and have changed the collections conditions for the energy and capacity sales to the wholesale power market.

Under the previous regulations, distribution companies were granted long-term concessions (up to 99 years) which provided, directly or indirectly, tariffs based upon U.S. dollars and adjusted by the U.S. consumer price index and producer price index. Under the new regulations, tariffs are no longer linked to the U.S. dollar and U.S. inflation indices. The tariffs of all distribution companies have been converted to pesos and are frozen at the peso notional rate as of December 31, 2001. In October 2003, Congress enacted Law No. 25,790 that established the procedure for renegotiations of the public utilities concessions and extended the period for that process until December 31, 2004. In combination, these circumstances create significant uncertainty surrounding the performance of the electricity industry in Argentina, including the Argentine subsidiaries of AES.

Brazil. Under the present regulatory structure, the power industry in Brazil is regulated by the Federal Government, acting through the Ministry of Mines and Energy ("MME") and the Electric Energy National Agency ("ANEEL"), which has exclusive authority over the Brazilian power industry.

ANEEL's main function is to ensure the efficient and economic supply of energy to consumers by monitoring prices and ensuring adherence to market rules by market participants. ANEEL supervises concessions for electricity generation, transmission, trading and distribution, including the approval of applications for the setting of tariff rates, and supervising and auditing the concessionaires. ANEEL's main core areas of responsibility that are directly related to AES's businesses are: economic regulation, technical regulation, and consumer affairs oversight.

Rationing Agreement. The electricity industry in Brazil reached a critical point in 2001, as the result of a series of regulatory, meteorological and market-driven problems. The Brazilian Wholesale Energy Market, or MAE, had a poor performance record due to an inability to resolve commercial disputes. In addition, the combined effects of growth in demand, decreased rainfall on the country's heavily hydro-electric dependent generating capacity and delays by the Brazilian energy regulatory authorities in developing an attractive regulatory structure (necessary to encourage new generation in the country) led to shortages of electricity compared to demand in certain regions of Brazil. As a result, the Brazilian government, effective as of June 2001, implemented a program for the rationing of electricity consumption.

Pursuant to the Rationing Program, consumers in the Northeast, Southeast and Midwest regions of Brazil were required to reduce their consumption by varied percentages, depending on the type of customer. The objective of the Rationing Program was to reduce aggregate consumption by 20% in those regions in which it was in force (including the AES Eletropaulo's service area). As a result of the mandatory consumption reduction in AES Eletropaulo's service area, the company experienced a 13% decrease in energy distributed in 2001, as compared to 2000. After the 2001-2002 rain season produced rainfall sufficient to replenish reservoir levels to an adequate level (as determined by the Federal Government) the Rationing Program was terminated in March 2002.

On December 21, 2001, in order to compensate electricity distributors and generators for losses incurred during the Rationing Program, the President of Brazil issued Provisional Measure #14/01. The provisional measure provided general authorization for: (i) the pass-through to consumers of costs incurred by generators for the purchase of energy at spot prices during the Rationing Program, (ii) the recovery of revenue losses sustained by distributors during the Rationing Period, through an Extraordinary Tariff Adjustment ("RTE"), (iii) the institution, by BNDES, of an emergency support program in order to compensate distributors, generators and independent power producers for the rationing impacts, which contemplates the disbursement of some loans to these companies.

In addition, the Federal Government provided a solution to a long-standing regulatory issue related to Parcel A costs (non-manageable costs relating to energy purchase and sector charges that each distribution company is permitted to pass through to customers). In the past, the Brazilian regulator had granted tariff increases that proved to be insufficient to fully recover Parcel A costs incurred by distribution companies. A tracking account mechanism (CVA) was established in order to mitigate risks relating to Parcel A costs not being passed-through to tariffs, and, as part of the agreement, Distribution companies would be allowed to recover Parcel A costs related to the period between January 1, 2001 and October 25, 2001. Parcel A costs incurred prior to January 1, 2001 were not allowed to be recovered under the Rationing Agreement and, as a result, the Company wrote-off approximately $160 million of Parcel A costs incurred prior to 2001.

Generators and distributors losses are recovered by the RTE, as calculated pursuant to Resolution #31 issued by ANEEL on January 24, 2002 and Resolution #91 issued by the Crisis Committee on December 21, 2001. As of January 2002, the Company was permitted to charge consumers the RTE over a 65-month period. However, as the market did not perform as expected after the rationing and the interest rate applied in order to adjust such regulatory asset (Selic—the Brazilian interbank interest rate) was higher than predicted, there was a need to review the figures previously determined by ANEEL. The Regulator reviewed the time over which RTE would be in place in order to allow the full recovery of the Rationing Agreement values and ANEEL's Normative Resolution # 001, issued on January 12 2004, established the extension of AES Eletropaulo's RTE recovery period (from the 65 to 70 months), and that Parcel A recovery will happen only after the RTE recovery, and along the period that is deemed necessary.

Under the Rationing Agreement, AES Sul was permitted to record additional revenue and a corresponding receivable from the spot market during 2001 and the first quarter of 2002. However,

ANEEL promulgated Order 288 in May 2002, which retroactively changed certain previously communicated methodologies, and resulted in a change in the calculation methods for electricity pricing in the MAE. We recorded a pretax provision of approximately $160 million, including the amounts for AES Sul against revenues during May 2002 to reflect the negative impacts of this retroactive regulatory decision.

AES Sul filed a motion for an administrative appeal with ANEEL challenging the legality of Order 288 and requested a preliminary injunction in the Brazilian federal courts to suspend the effect of Order 288 pending the determination of the administrative appeal. Both appeals were denied. In August 2002, AES Sul appealed and in October 2002, the court confirmed the preliminary injunction's validity. Its effect, however, was subsequently suspended pending an appeal by ANEEL and an appeal by AES Sul.

In December 2002, prior to any settlement of the MAE, Sul filed an incidental claim requesting, by way of a preliminary injunction, the suspension of our debts registered in the MAE. A Brazilian federal judge granted the injunction and ordered that an amount equal to one-half of the amount claimed by Sul from inter-market trading of energy purchased from Itaipu in 2001 be set aside by the MAE in an escrow account. The injunction was subsequently overturned. Sul has appealed that decision and requested the judge to reinstate the injunction and the escrow account.

The MAE partially settled its registered transactions between late December 2002 and early 2003. If the final settlement occurs with the effect of Order 288 in place, AES Sul will owe approximately $28 million, based upon the December 31, 2003 exchange rate. AES Sul does not believe it will have sufficient funds to make this payment and several creditors have filed lawsuits in an effort to collect amounts they claim are overdue. AES Sul is petitioning the courts to aggregate the individual lawsuits with payments until the matter is resolved. If AES Sul prevails and the MAE settlement occurs absent the effect of Order 288, the company will receive approximately $121 million, based upon the December 31, 2003 exchange rate. If AES Sul is unsuccessful and unable to pay any amount that may be due to MAE, penalties and fines could be imposed up to and including the termination of the concession contract by ANEEL. AES Sul is current on all MAE charges and costs incurred subsequent to the period in question in the order 288 matter. All amounts, including the debt in case the company loses the case, are provisioned in AES Sul's books.

We do not believe that the terms of the industry-wide Rationing Agreement as currently being implemented restored the economic equilibrium of all of the concession contracts because the agreement covered only the Rationing Period, the consumption never returned to the previous levels and previously communicated methodologies for implementing the terms of the Rationing Agreement were retroactively changed.

"Parcel A" tracking account (CVA). The CVA is a tracking account that records non-manageable costs monthly price variations (positive and negative) over the course of the year. At each tariff adjustment date, distribution companies would be allowed an additional tariff increase, for the following 12 months, in order to compensate for the accumulated value of the CVA, plus interest for the previous 12 months. Prior to the implementation of the tracking account mechanism (effective as of January, 2001), distribution companies were facing massive losses relating to these costs variations. In accordance with the regulation, the costs currently allowed to be recorded in the tracking account relate to energy purchase (Itaipu and the Initial Contracts) and System Charges.

On April 4, 2003, the Ministry of Mines and Energy ("MME") issued a decree postponing, for a 1-year period, the tracking account tariff increase. According to this decree, the pass-through to tariffs of the amounts accumulated in the tracking account for the distribution concessionaires that had been scheduled to occur from April 8, 2003 to April 7, 2004 will be postponed to the subsequent year's tariff adjustment. As a result, in the case of Sul and Eletropaulo, the pass-through of the tracking account balance for 2003, that should originally happen on April 19, 2003 and July 4, 2003 amount to approximately $12 million and $173 million, respectively. These amounts will be accumulated in the

next twelve months and shall be recovered over a 24-month period rather than the usual 12-month period.

In order to compensate for the deferral of the increase relating to the tracking account, BNDES will provide distribution companies with loans, which will be repaid during the recovery period. As the conditions precedents to closing the negotiations between AES and BNDES have been fulfilled, AES Eletropaulo and AES Sul are now eligible for such a loan.

Tariff Reset. In 2003, Brazil entered a major round of tariff revisions. On April 19, 2003, AES Sul was granted a rate increase by ANEEL, the regulatory body in Brazil responsible for tariff revisions, of 16.14%. On July 4, 2003, ANEEL granted a tariff revision for AES Eletropaulo of 10.95% plus 0.4% to be included in the tariff adjustment for the ensuing 12-month period, resulting in 11.35%. The tariff revisions are meant to re-establish a tariff level that would cover (i) costs for the energy purchased and other non-manageable costs, (ii) operations/maintenance costs of a "Reference Company," and (iii) capital remuneration on the Company's asset base using a "replacement cost" methodology. Each of these items is evaluated based on a "Test-Year," as defined by ANEEL, which encompasses the following 12 months after the tariff increase. There remain a number of critical issues that were either not adequately considered in the process or remain unresolved.

The operations and maintenance costs considered in the tariff are based on the concept of a Reference Company, not the actual costs of the Company. In many cases, the Reference Company may not be reflective of distribution companies operating in Brazil and thus underestimate true operating costs. For example, for all distribution companies in Brazil, a bad debt level of 0.5% of net revenues was used. Eletropaulo and Sul believe that this is neither an appropriate level of bad debts in Brazil nor in many developed countries. In response to a request by ANEEL, the companies, together with others in the industry, recently hired third party consultants to carry out a detailed study of this issue. In addition, with respect to Eletropaulo, the Reference Company fails to address certain costs associated with its defined benefit pension plan. In addition, certain taxes were not considered as costs applicable to the Reference Company. On July 18, 2003, ANEEL released the technical note on the tariff revision for Eletropaulo and Sul. The information provided in the technical note is not sufficient in defining the Reference Company costs. Eletropaulo and Sul intend to either file for an administrative appeal against the tariff revision process within 10 days after ANEEL publicly releases the information relating to the tariff revision processes to the public or file for judicial injunction prior to release.

The distribution companies are challenging certain methodologies used for the tariff revision. For example, the rate base calculation used for the tariff reset is defined by ANEEL Resolution 493 which takes into account the replacement value of the concessionaire's assets. Private investors are claiming that the minimum bid price established at the privatization process be used as the asset base determining remuneration. This claim is being pursued in the Brazilian courts but there is no assurance that it will be successful. In addition, under the replacement cost method used by the regulator, the asset base calculation has not been approved by ANEEL with many of the distribution companies, including AES Eletropaulo and AES Sul. ANEEL has used a provisional asset base number, based on a percentage of the fixed assets adjusted for inflation. In the case of Eletropaulo, the regulator has used 90% of the value of the adjusted fixed assets indexed by IGPM until June 2003. ANEEL has stated that once the final number pursuant to Resolution 493 is achieved, tariffs will be retroactively calculated and adjusted in the 2004 tariff adjustment, for the difference. There is no assurance at this point on what the final rate base amounts will be for AES Eletropaulo or AES Sul. ANEEL has released a technical note with changes to the original Resolution 493. In August, 2003, AES Eletropaulo and AES Sul filed an administrative appeal against the technical note, contesting the changes in the resolution as well as inconsistencies noted in the original version of Resolution 493. Finally, the companies believe that there is a timing mismatch in the parameters used in the respective formula. As the "Test-Year" assumes parameters for the following 12 months after the reset, it does not pick up the effects of the inflation on the unit costs adopted for the Reference Company or on the

value of the assets that comprise the regulatory Rate Base. There are discussions that are still ongoing at ANEEL in respect to such methodology.

Further, there is an uncertainty surrounding the application of an "X-factor," which is part of the tariff revision process. Annually after the 2003 tariff revision, the tariffs applicable to distribution companies are to be adjusted based on a formula that contains an X-factor. The X-factor is intended to permit the regulator to adjust tariffs so that consumers may share the distribution company's realization of increased operating efficiencies. The revision, however, is entirely at the regulator's discretion and there have been changes to the concept from what the X-factor was originally defined as in the concession contracts. Preliminary X-factor indexes of 2.54% and 1.82% were determined for AES Eletropaulo and AES Sul, respectively. However, the final methodology for the X-factor calculation still lacks definition. A public hearing was held on February 5, 2004 to discuss the methodology, but ANEEL's conclusions have yet to be released.

New Sector Model. The Brazilian Government announced on December 11, 2003, a proposed new model for the Brazilian power sector and enacted Provisional Measures # 144 and # 145, which set forth the basic rules that will govern the new model. Simultaneously, the Ministry of Mines and Energy published a document entitled the "Institutional Model for the Electricity Sector" with a more detailed description of the guidelines for the new model, which is a revised version of the working paper previously released for discussion on July 21, 2003 and reflects the 6-month discussions among the Government and relevant participants in the sector.

Although the final version of this document presents a series of improvements, it maintains the essence of the structure proposed in its original version. The basis of this institutional reform includes: (i) new rules concerning energy trade among market players, with the coexistence of two contracting environments—a free one and a fully regulated one (the "Pool"), (ii) obligations on the distribution companies to meet 100% of their energy requirements in the Pool, with no self-dealing, (iii) competition for the expansion of power generation through tenders, (iv) the creation of new entities that will be in charge of the centralized planning of generation and transmission expansion (mid and long-terms), as well as of the monitoring of the servicing conditions in a 5-year horizon, (v) changes in the governance of the Independent System Operator, and (vi) the creation of a new body to succeed the current Wholesale Energy Market.

Several issues still depend on legal regulation (decrees, orders, or resolutions). Therefore, it is still not possible to accurately assess the impact of the changes in the regulatory framework on AES companies in Brazil regarding their financial condition and operational results. Nonetheless, the Government's focus on the sector and its stated commitment to strengthening and improving the regulatory system seem encouraging (in particular, the MME has committed to honor all contracts executed and approved by ANEEL). Based on the information available to date, investors and market players expect a relatively smooth transition to the new regulatory environment and a preliminary assessment indicates that the proposed energy policies have overall neutral impact on our distribution and generation businesses in Brazil.

Chile. In Chile, the regulation of production schedules for electricity generation facilities is based on the marginal cost of production, which is the cost of the most expensive unit required by the system at the time. The spot price among generation companies for both electrical capacity (the amount of electricity available at any point in time) and electrical energy (the amount of electricity produced or consumed over a period of time) is also the marginal cost of production. Chile has four electricity systems. The major two interconnected electricity systems are the SIC and the SING, which cover almost 97% of the population of the country.

In order to meet demand for electricity at any point in time, the lowest marginal cost generating plant in an interconnected system is used before the next lowest marginal cost plant is dispatched. As a result, at any specific level of demand, the appropriate supply will be provided at the lowest possible

marginal cost of production available in the system. Generation companies are free to enter into sales contracts with distribution companies and other customers for the sale of capacity and energy. However, the electricity necessary to fulfill these contracts is provided by the contracting generation company only if the generation company's marginal cost of production is low enough for its generating capacity to be dispatched to meet demand. Otherwise, the generation company will purchase electricity from other generation companies at the marginal cost of production in the system, if the contracting generation company's marginal cost is above that of the last generator required to meet demand at the time.

According to existing law, during periods when production cannot meet system demands, regardless of whether the government has enacted a rationing decree, the price of energy exchanges among generation companies is valued at the "unserved energy cost" or "shortage cost" which is the cost to consumers for not having energy available. This law remained untested until November 1998 when generators in the SIC were unable to agree on the implementation of the shortage cost during the supply deficit and associated mandated rationing periods. The matter was referred to the Ministry of Economy, which in March 1999 ruled the application of the shortage cost. Based on this decision, generators with energy deficits at the time were required to pay companies with energy surpluses the shortage cost or corresponding spot price equal to the cost of unserved energy for energy purchases during that period. The prices paid to generation companies by distribution companies for capacity and energy to be resold to their retail customers are based on the expected average marginal cost of capacity or energy. In order to ensure price stability, however, the regulatory authorities in Chile establish prices, known as "node prices," every six months to be paid by distribution companies for the energy and capacity requirements of regulated consumers. Node prices for energy are calculated on the basis of the projections of the expected marginal costs within the system over the next 24 to 48 months, in the case of the SIC and the SING. The formula takes into account, among other things, assumptions regarding available supply and demand in the future. Node prices for capacity are based on the marginal investment required to meet peak demand, based on the cost of a diesel-fired turbine. Prices for capacity and energy sold to large customers (over 2 MW) and other generation companies purchasing on a contractual basis are unregulated and are often set with reference to node prices, alternative fuel prices, exchange rates and other factors. If average prices for capacity and energy sold to non-regulated customers differ from node prices by more than 10%, node prices are adjusted upward or downward, as the case may be, so that the difference between such prices equals 10%. In contrast, the spot price paid by one generation company to another for energy is referred to as the "system marginal cost," which is based on the actual marginal cost of the highest cost generator producing electricity in the system during the relevant period, as determined on an hourly basis.

Since the system marginal cost for energy is set weekly (but may in certain circumstances be changed on a daily basis) based on variables that can change on an instantaneous basis, and the node price for energy is set every six months based on projections of these variables over the next 24 to 48 months, in the case of the SIC and SING, the system marginal cost for energy of a system tends to be more volatile than the node price for energy of that system. In periods of low water conditions that require greater generation of energy by more costly thermoelectric plants, the system marginal cost typically exceeds the node price. In periods of high water conditions when lower cost hydroelectric facilities can meet the majority of demand, the system marginal cost is typically below the node price and may in fact decline to zero at some hours.

In May 2002, the Chilean Ministry of Economy and Energy sent to the Chilean Congress a bill known as the Ley Corta, or the Short Law, which was approved by the Chilean Chamber of Deputies on January 22, 2004 and is expected to be effective in the following months. The Short Law establishes amendments to the existing Electricity Law, principally in relation to tolls charged for the use of high voltage and transmission systems. The reduction of the minimum demand required to be considered as an unregulated customer is from 2 MW to 0.5 MW. In addition, other factors considered are the

reduction of the floating band for regulated price from 10% to 5%, the incorporation of elements to create an ancillary services market and the pricing mechanism for small and medium-sized electricity systems.

The modifications contained in the Short Law maintain or improve our position with regard to both our current status and projected development and, in particular, with regard to the issues related with transmission tolls. In addition, the Regulations to the Electricity Law, Supreme Decree No. 327, which was modified on October 9, 2003 with respect to the clarification of the methodology utilized to calculate transmission tolls and the procedures to be used during rationing periods, will be replaced by the Short Law.

Venezuela. The political and economic environment in Venezuela continues to be unstable. In September 1999, the Electric Service Law ("LSE"), which provides a framework for the deregulation of the electric utility industry in Venezuela, was enacted. On December 14, 2000, the Ministry of Energy and Mines enacted the Electric Law Regulations pursuant to the LSE. The LSE, as amended in December 2001, requires the restructuring of integrated electric companies by January 2003. On November 20, 2002, the Ministry of Energy and Mines extended the date for the restructuring of integrated utilities to January 2004. The Ministry of Energy and Mines has unofficially informed EDC that this date will be extended further. The restructuring involves legally dividing generation, transmission, distribution and commercialization businesses into new independent legal entities that are financially, operationally and administratively autonomous. Under the LSE, generation and commercialization will be deregulated and will be opened up to competition, whereas distribution and transmission will remain regulated businesses.

In addition, in January 1999, a joint resolution of the Ministry of Energy and Mines and the Ministry of Industry and Commerce (the "Joint Resolution") established the basic tariff rates applicable during the Four-Years Tariff Regime (1999-2002). The tariffs were established using a cost-plus return on investment methodology. Each company provides information about their business (assets and costs), and the tariffs are calculated by the regulator based on the expected return for a model company. Tariffs are adjusted: (i) semi-annually to reflect fluctuations in inflation and the currency exchange rate, and (ii) monthly to reflect fluctuations in fuel cost. During 2003 the Venezuelan Government issued a decree establishing price controls on a basket of basic goods and services including electricity. However, this decree included a clause allowing for electricity tariff adjustment in special circumstances.

In November 2003, the Ministry of Energy and Mines enacted the Distribution Service by-law and the Quality Standards for Distribution. The Distribution Service by-law covers the regulation of diverse aspects of the commercial service process and the contractual relationship with users. The Quality Standards for Distribution regulates the voltage signal, frequency and time of interruption, and commercial service. It considers its own progressive implementation from current quality levels to the target quality standards, over a four-year period, assuming that distribution companies will have the proper tariff levels to cover the costs of adapting their systems and networks.

We are subject to various federal, state, local and foreign environmental and land use laws and regulations. These laws and regulations primarily relate to:

In addition to such laws and regulations, projects funded by the World Bank are subject to World Bank environmental standards which tend to be more stringent than local country standards. The laws and regulations to which we are subject require a lengthy and complex process of obtaining licenses, permits and approvals from governmental agencies for our new, existing or modified facilities. If we violate or fail to comply with such laws, regulations, licenses, permits or approvals, we could be fined or otherwise sanctioned by regulators or be required to temporarily or permanently shutdown our plants. In addition, under certain environmental laws, we could be responsible for costs relating to contamination at our facilities or at third-party waste disposal sites. We have accrued liabilities for projected environmental remediation costs. See Note 12 of our consolidated financial statements for more detail. While we have at times been out of compliance with environmental laws, regulations, licenses, permits and approvals, no such instance has resulted in revocation of any material permit or license. We have incurred and will continue to incur significant capital and other expenditures to comply with environmental laws and regulations, in particular, with respect to the laws and regulations described below. See Item 7—Managements' Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Finance Position & Cash Flows for more detail.

Air Emissions. The U.S. Clean Air Act, state laws and implementing regulations require significant reductions in major pollutants, including sulfur dioxide ("SO₂"), nitrogen oxides ("NOx") and particulate matter ("PM").

In the 1990s, the United States Environmental Protection Agency ("EPA") commenced an industry-wide investigation of coal-fired electric 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" regulations which require companies to obtain permits prior to making major modifications to their facilities and if required, install control equipment to reduce air emissions. See Item 3—Legal Proceedings for a description of certain related litigation affecting AES.

The EPA's NOx state implementation plan call requires operators of coal-fired electric generating facilities in 22 U.S. states and the District of Columbia to reduce NOx emissions by May 31, 2004. Pursuant to this law, we are installing selective catalytic reduction and other NOx control technologies at three facilities of Indianapolis Power and Light ("IPL"), a regulated electric utility wholly owned by AES. After the projects have been placed in service, we expect to fully recover these costs pursuant to the approved ratemaking procedures for these projects.

In December 2003, the EPA issued two proposed rules that, if implemented, will affect many of our U.S. facilities. The first, the "Utility Mercury Reductions Rule," sets forth approaches to regulating mercury emissions from electric generating units. Two of the approaches would involve a "cap and trade" program that would take effect in 2010 and result in a 70% reduction in mercury emissions. The third approach would require subject plants to meet traditional unit-specific maximum achievable control technology ("MACT") standards which would result in a 30% reduction in mercury emissions by December 2007. The EPA is expected to issue its final rule in 2005. The second proposed rule, referred to as the "Interstate Air Quality Rule," is intended to address the impact of interstate transport of air pollutants on downwind states that are not attaining the national ambient air quality standards ("NAAQS") for PM and ozone. If adopted, this rule would require additional reductions of SO₂ and NOx from certain of our plants by 2010. We are analyzing the potential effects of these proposed regulations. We will likely be required to install control technology at some of our U.S. facilities. Based on currently available information and the preliminary status of these regulations, we cannot estimate these costs, but they could be material, particularly if we are required to comply with MACT standards with respect to our mercury emissions.

The New York State Department of Environmental Conservation ("NYSDEC") recently adopted regulations requiring electric generators to reduce SO₂ emissions by 50% below current Clean Air Act standards. The SO₂ regulations will be phased in beginning on January 1, 2005 with implementation completed by January 1, 2008. These regulations would also require electric generators to meet stringent NOx reduction requirements year-round, rather than just during the summertime ozone season. These new NOx regulations will take effect on October 1, 2004. A number of entities have started legal actions to overturn these rules.

If these regulations are implemented, our four generation facilities in New York may be required to incur significant costs to install additional environmental pollution control technology. We cannot estimate the costs based on currently available information.

Our businesses may be required to further reduce emissions of NOx, SO₂, PM and carbon dioxide ("CO₂") as a result of various other current or pending laws, regulations or rules including, in particular:

Based on currently available information, we cannot estimate our costs to comply with these regulatory and legislative developments, but they could be material.

In Europe we are, and will continue to be, required to reduce air emissions from our facilities to meet compliance with applicable European Union ("EU") Directives. In Hungary, as part of the life extension projects, we have already taken steps to meet some of the provisions under certain of these directives, with an overall capital expenditure of approximately $10.2 million.

Global Warming. Global warming continues to be a concern and remains a policy issue that is regularly considered for possible government regulation. U.S. state and regional CO₂ reductions rules are being developed in addition to those proposed rules pending before Congress and referenced above. For example, in July 2003 ten northeastern U.S. states announced an agreement to develop a regional market-based emissions trading system to reduce CO₂ emissions from power plants. The goal is to develop a proposal by April 2005 for a regional market-based cap and trade program. If implemented, our plants in New York and Connecticut may be affected by these rules. Until such time as the rules are developed, the Company cannot determine its impact on the Company's financial position or results from operations.

In addition, the European Union ("EU") Directive on Greenhouse Gas ("GHG") Emission Allowance Trading was adopted in July 2003. The policy outlines the basic rules that will govern the EU GHG market. Under the directive, power plants greater than 20 megawatts must limit GHG emissions to allocated levels within two periods, from 2005 to 2007 and from 2008 to 2012. Member states and EU ascension countries must submit their proposed national allowance allocation plans by March 31, 2004 and finalize their plans by September 2004. Under this directive, all subject plants will be allocated emission credits which will allow each plant to emit a percentage of their current emissions. Credits would need to be purchased to achieve emissions consistent with current levels. While our estimated exposure will depend on the various national allocation plans, ultimate costs could be material.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change, if ratified by the requisite number of signatory countries, would require the signatory countries to make substantial

reductions in "greenhouse gas" emissions, including CO₂. In 2002, the fifteen Member Nations of the EU and Canada agreed to ratify the Kyoto Protocol. If the Kyoto Protocol is ratified by the United States and/or the Russian Federation, the Protocol will enter into force for all countries that have ratified it and our facilities in those countries will be required to incur significant costs to reduce CO₂emissions. Their operating characteristics may also be affected. These costs may be in addition to costs to comply with any other foreign regulations governing greenhouse gas emissions, including those already in effect and those described above.

Water Emissions. Our facilities are subject to a variety of rules governing water discharges. In particular, we are evaluating the impact of the new EPA final rules promulgated on February 16, 2004 pursuant to Section 316 of the United States Federal Water Pollution Control Act. These regulations, which are designed to protect aquatic life affected by cooling water intake systems, will require our subject facilities to demonstrate that their water intake systems meet best technology available for minimizing adverse environmental impacts ("BTA") and if not, install retrofit technologies. We believe that many of our US facilities will be affected by this law and that compliance costs may need to be incurred through 2010. Because capital expenditure and each facility's design, location, existing control equipment and results of impact assessments must be taken into consideration, costs will likely vary. Actual costs to comply could be material.

Members of Congress have introduced new legislation which, if passed into law, would require reduction in power plant air emissions beyond the requirements described above. In particular, various bills sponsored by members of Congress would require significant reductions for CO₂, NOx, SO₂ and mercury. In addition, President Bush's "Clear Skies" legislation, which would cap emissions of three pollutants (NOx, SO₂ and mercury), with voluntary reductions of CO₂, was introduced in Congress in July 2002 and reintroduced in February 2003.

In February 2002, the New York State Department of Environmental Conservation ("NYSDEC") issued proposed regulations requiring electric generators to reduce SO₂ emissions by 50% below current Clean Air Act standards. The state environmental authorities are scheduled to vote on this regulation on March 26, 2003. If adopted, the SO₂ regulation would be phased in beginning on January 1, 2005 with implementation completed by January 1, 2008. NYSDEC's proposed regulations would also require electric generators to meet stringent NOx reduction requirements year-round, rather than just during the summertime ozone season. These new NOx regulations, if adopted, would take effect on October 1, 2004. If any of these and/or other similar rules or legislation are passed into law, our generation facilities would likely be required to incur additional significant costs to install additional environmental pollution control technology.

We have ownership interests in power plants and projects in many countries outside the United States. Each of these countries (and the localities therein) have separate laws and regulations governing the siting, construction, permitting, ownership, operation, decommissioning and remediation of, and power sales from, such power plants. These countries also have laws governing waste disposal, the discharge of pollutants into the air, water or ground and noise pollution. These laws and regulations 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. These standards may be more stringent than local country standards but are typically not as strict as corresponding standards in the United States. We have incurred and will continue to incur capital and other expenditures to comply with these laws and regulations, in particular, laws governing air emissions. Whenever feasible, we attempt to use advanced environmental technologies (such as CFB coal technology or advanced gas turbines) in our non-U.S. businesses in order to minimize environmental impacts.

Environmental laws and regulations affecting power generation and distribution are complex, change frequently and have tended to become more stringent over time. Based on current trends, we expect that environmental and land use regulations affecting our 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 change in the future, we may be required to make significant capital or other expenditures. There can be no assurance that we would be able to recover from our customers all or any increased costs to comply with current or future environmental or land use regulations or that its business, financial condition or results of operations would not be materially and adversely affected by such foreign environmental and land use regulations.

We maintain offices 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. With a few exceptions, our facilities, which are described in Item 1 of this Form 10-K, 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 our 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, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.

In September 1999, a judge in the Brazilian appellate state court of Minas Gerais granted a temporary injunction suspending the effectiveness of a shareholders' agreement between Southern Electric Brasil Participacoes Ltda. ("SEB") and the state of Minas Gerais concerning CEMIG. AES's investment in CEMIG is through SEB. This shareholders' agreement granted SEB certain rights and powers in respect of CEMIG (the "Special Rights"). The temporary injunction was granted pending determination by the lower state court of whether the shareholders' agreement could grant SEB the Special Rights. In October 1999, the full state appellate court upheld the temporary injunction. In March 2000, the lower state court in Minas Gerais ruled on the merits of the case, holding that the shareholders' agreement was invalid where it purported to grant SEB the Special Rights. In August 2001, the state appellate court denied an appeal of the merits decision, and extended the injunction. In October 2001, SEB filed two appeals against the decision on the merits of the state appellate court, one to the Federal Superior Court and the other to the Supreme Court of Justice. The state appellate court denied access of these two appeals to the higher courts, and in August 2002, SEB filed two interlocutory appeals against such decision, one directed to the Federal Superior Court and the other to the Supreme Court of Justice. These appeals continue to be pending. SEB intends to vigorously pursue by all legal means a restoration of the value of its investment in CEMIG. However, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit the SEB's influence on the daily operation of CEMIG.

similar claims against other defendants. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which asserted the claims asserted in the earlier action and names AES, AES Redondo Beach, L.L.C., AES Alamitos, L.L.C., and AES Huntington Beach, L.L.C. as defendants. In May 2002, the case was removed by certain cross-defendants from the San Diego County Superior Court to the United States District Court for the Southern District of California. Plaintiffs filed a motion to remand the case to state court, which was granted on December 13, 2002. Certain defendants have appealed that decision to the United States Court of Appeals for the Ninth Circuit. That appeal is pending before the Ninth Circuit. We believe that we have meritorious defenses to any actions asserted against us and expect that we will defend ourselves 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 our businesses in California. Each of our businesses in California (AES Placerita and AES Southland, which is comprised of AES Redondo Beach, AES Alamitos, and AES Huntington Beach) have received subpoenas and/or requests for information in connection with overlapping state investigations by the California Attorney General's Office, the Market Oversight and Monitoring Committee of the California Independent System Operator ("ISO"), the California Public Utility Commission and a subcommittee of the California Senate. These businesses have cooperated with the investigation and 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 California wholesale electricity market in order to determine whether rates were just and reasonable. Further investigations have involved alleged market manipulation. The FERC has requested documents from each of the AES Southland plants and AES Placerita. AES Southland and AES Placerita have cooperated fully with the FERC investigation.

In a separate investigation that spun out of the initial California investigation, the FERC Staff is investigating physical withholding by generators. AES Southland and AES Placerita have received data requests from the FERC Staff, have responded to those data requests, and have cooperated fully with the investigation. The physical withholding investigation is ongoing.

The FERC also initiated an investigation into economic withholding. AES Placerita has received data requests from the FERC Staff, has responded to those data requests, and has cooperated fully with the investigation. The economic withholding investigation is ongoing.

In November 2002, we were served with a grand jury subpoena issued on application of the United States Attorney for the Northern District of California. The subpoena sought, inter alia, certain categories of documents related to the generation and sale of electricity in California from January 1998 to the date of the subpoena. We cooperated in providing documents in response to the subpoena.

advised the OERC that the Company is not subject to the OERC proceedings. Gridco also has asserted that a Letter of Comfort issued by the Company in connection with the Company's investment in CESCO obligates the Company to provide additional financial support to cover CESCO's financial obligations. In December 2001, a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 was served on the Company by Gridco pursuant to the terms of the CESCO Shareholder's Agreement ("SHA"), between Gridco, the Company, AES ODPL, and Jyoti Structures. The notice to arbitrate failed to detail the disputes under the SHA for which the Arbitration had been initiated. After both parties had appointed arbitrators, and those two arbitrators appointed the third neutral arbitrator, Gridco filed a motion with the India Supreme Court seeking the removal of AES's arbitrator and the neutral chairman arbitrator. In the fall of 2002, the Supreme Court rejected Gridco's motion to remove the arbitrators. Gridco has dropped the challenge of the appointment of neutral chairman arbitrator; however, it retained the challenge of removal of AES' arbitrator. Although that motion remains pending, the parties have filed their respective statement of claims, counter claims and defenses. On or about July 26, 2003, Gridco filed a motion in the District Court of Bhubaneshwar, India, seeking a stay of the arbitration and requesting that the District Court terminate the mandate of the neutral chairman arbitrator. The District Court gave a stay order, and the case was scheduled to be heard in mid November 2003. Thereafter, pursuant to a separate motion filed with the Court in India, a further temporary stay of the arbitration proceedings was granted until the India Court issued a decision on whether or not to grant a permanent stay of the arbitration. In the interim, and pending a decision by the Court as to whether to grant a permanent stay, arbitration proceedings have been tentatively scheduled for April 2004. The Company believes that it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations.

In April 2002, IPALCO and certain former officers and directors of IPALCO were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana. On May 28, 2002, an amended complaint was filed in the lawsuit. The amended complaint asserts that IPALCO and former members of the pension committee for the Indianapolis Power & Light Company thrift plan breached their fiduciary duties to the plaintiffs under the Employees Retirement Income Security Act by investing assets of the thrift plan in the common stock of IPALCO prior to the acquisition of IPALCO by the Company. In December 2002, plaintiffs moved to certify this case as a class action. The Court granted the motion for class certification on September 30, 2003. On October 31, 2003 the parties filed cross-motions for summary judgment on liability. Those motions currently are pending before the Court. IPALCO believes it has meritorious defenses to the claims asserted against it and intends to defend this lawsuit vigorously.

purported claims in the original complaint, purports to allege against the newly added defendants violations of Sections 10(b) and 14(a) of the Securities Exchange Act of 1934 and Rules 10b-5 and 14a-9 promulgated thereunder. The amended complaint also purports to add a claim based on alleged misstatements or omissions concerning an alleged breach by AES of alleged obligations AES owed to Williams Energy Services Co. under an agreement between the two companies in connection with the California energy market. By Order dated August 25, 2003, the court consolidated these three actions with an action captioned Cole et al. v. IPALCO Enterprises, Inc. et al, 1:02-cv-01470-DFH-TAB (the "Cole Action"), which is discussed immediately below. On September 26, 2003, defendants filed a motion to dismiss the amended complaint. The motion to dismiss is sub judice. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend these lawsuits vigorously.

In September 2002, IPALCO and certain of its former officers and directors were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana (the "Cole Action"). The lawsuit purports to be filed on behalf of the class of all persons who exchanged shares of IPALCO common stock for shares of AES common stock pursuant to the Registration Statement dated and filed with the SEC on August 16, 2000. The complaint purports to allege violations of Sections 11 of the Securities Act of 1933 and Sections 10(a), 14(a) and 20(a) of the Securities Exchange Act of 1934, and Rules 10b-5 and 14a-9 promulgated there under based on statements in or omissions from the Registration Statement covering certain secured equity-linked loans by AES subsidiaries; the supposedly volatile nature of the price of AES stock; and AES's allegedly unhedged operations in the United Kingdom. By Order dated August 25, 2003, the court consolidated this action with three previously filed actions, discussed immediately above. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

In October 2002, the Company, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp were named as defendants in purported class actions filed in the United States District Court for the Eastern District of Virginia. Between October 29, 2002 and December 11, 2002, seven virtually identical lawsuits were filed against the same defendants in the same court. The lawsuits purport to be filed on behalf of a class of all persons who purchased the Company's common stock and certain of its bonds between April 26, 2001 and February 14, 2002. The complaints purport to allege violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder based on statements or omissions concerning the Company's United Kingdom operations and the alleged effect of the New Electrical Trading Agreements ("NETA") on those operations. On December 4, 2002 defendants moved to transfer the actions to the United States District Court for the Southern District of Indiana. By stipulation dated December 9, 2002, the parties agreed to consolidate these actions into one action. On December 12, 2002 the Court entered an order consolidating the cases under the caption In re AES Corporation Securities Litigation, Master File No. 02-CV-1485. On January 16, 2003, the Court granted defendants' motion to transfer the consolidated action to the United States District Court for the Southern District of Indiana. On September 26, 2003, plaintiffs filed a consolidated amended class action complaint on behalf of a purported class of all persons who purchased the Company's common stock and certain of its bonds between July 27, 2000 and November 8, 2002. The consolidated amended class action complaint, in addition to asserting the same claims asserted in the original complaints, also purports to allege that AES and the individual defendants failed to disclose information concerning AES's role in purported manipulation of the California electricity market, the effect thereof on AES's reported revenues, and AES's purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. Defendants filed a motion to dismiss on November 17, 2003. The motion to dismiss is sub judice. The Company and the individuals believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

On December 11, 2002, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action lawsuit filed in the United States District Court for the Eastern District of Virginia captioned AFI LP and Naomi Tessler v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp, 02-CV-1811 (the "AFI Action"). The lawsuit purports to be filed on behalf of a class of all persons who purchased AES securities between July 27, 2000 and September 17, 2002. The complaint alleges that AES and the individual defendants failed to disclose information concerning purported manipulation of the California electricity market, the effect thereof on AES's reported revenues, and AES's purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. On May 14, 2003, the Court ordered that the action be transferred to the United States District Court for the Southern District of Indiana. By Order dated August 25, 2003, the Southern District of Indiana consolidated this action with another action captioned Stanley L. Moskal and Barbara A. Moskal v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp, 1:03-CV-0284 (the "Moskal Action"), discussed immediately below. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

On February 26, 2003, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana captioned Stanley L. Moskal and Barbara A. Moskal v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp, 1:03-CV-0284 (Southern District of Indiana). The lawsuit purports to be filed on behalf of a class of all persons who engaged in "option transactions" concerning AES securities between July 27, 2000 and November 8, 2002. The complaint alleges that AES and the individual defendants failed to disclose information concerning purported manipulation of the California electricity market, the effect thereof on AES's reported revenues, and AES's purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. By Order dated August 25, 2003, the Southern District of Indiana consolidated this action with the AFI Action, discussed immediately above. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

Beginning in September 2002, El Salvador tax and commercial authorities initiated investigations involving four of the Company's subsidiaries in El Salvador, Compañia de Luz Electrica de Santa Ana S.A. de C.V. ("CLESA"), Compañía de Alumbrado Electrico de San Salvador, S.A. de C.V. ("CAESS"), Empresa Electrica del Oriente, S.A. de C.V. ("EEO"), and Distribuidora Electrica de Usultan S.A. de C.V. ("DEUSEM"), in relation to two financial transactions closed in June 2000 and December 2001, respectively. The authorities have issued document requests and the Company and its subsidiaries are cooperating fully in the investigations. As of March 18, 2003, certain of these investigations have been successfully concluded, with no fines or penalties imposed on the Company's subsidiaries. The tax authorities' and attorney general's investigations are pending conclusion.

The U.S. Department of Justice is conducting an investigation into allegations that persons and/or entities involved with the Bujagali hydroelectric power project which the Company was constructing and developing in Uganda, have made or have agreed to make certain improper payments in violation of the Foreign Corrupt Practices Act. The Company has been conducting its own internal investigation and has been cooperating with the Department of Justice in this investigation.

rebates assessed for associated delays. As part of the initial complaint, S&W also sought to enjoin AESWH and AESF from drawing down on Letters of Credit provided by S&W. The Court refused to issue the injunction. S&W has since amended its complaint three times and joined additional parties, including the Company. In addition to the claims already mentioned, the current claims by S&W include claims for breach of warranty, wrongful liquidated damages, foreclosure of lien, fraud and negligent misrepresentation. In January 2004, the Company filed a counterclaim against S&W and its parent, the Shaw Group, Inc. ("Shaw"). In February 2004, Shaw filed an answer to the counterclaim. The Company and its subsidiaries AESWH and AESF believe that each have meritorious defenses to the claims asserted against it by S&W, and intend to defend the lawsuit vigorously. Trial in this matter is set for March 7, 2005.

In March 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil notified Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgas and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers and requested various documents from Eletropaulo relating to these matters. The Company is still in the process of collecting some of the requested documents concerning the real estate sales to provide to the Public Prosecutor. Also in March 2003, the Commission for Public Works and Services of the Sao Paulo Congress requested Eletropaulo to appear at a hearing concerning the default by AES Elpa and AES Transgas on the BNDES financings and the quality of service rendered by Eletropaulo. This hearing was postponed indefinitely. In addition, in April 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil notified Eletropaulo that it is conducting an inquiry into possible errors related to the collection by Eletropaulo of customers' unpaid past-due debt and requesting the company to justify its procedures.

In May 2003, there were press reports of allegations that in April 1998 Light Serviços de Eletricidade S.A. ("Light") colluded with Enron in connection with the auction of the Brazilian group Eletropaulo Electricidade de Sao Paulo S.A. Enron and Light, of which AES was a shareholder, were among three potential bidders for Eletropaulo. At the time of the transaction in 1998, AES owned less than 15% of the stock of Light and shared representation in Light's management and Board with three other shareholders. In June 2003, the Secretariat of Economic Law for the Brazilian Department of Economic Protection and Defense ("SDE") issued a notice of preliminary investigation seeking information from a number of entities, including AES Brasil Energia, with respect to certain allegations arising out of the privatization of Eletropaulo.

On August 1, 2003, AES Elpa S.A. responded on behalf of AES-affiliated companies and denied knowledge of these allegations. The SDE has begun a follow-up administrative proceeding as reported in a notice published on October 31, 2003.

In December 2002, Enron filed a lawsuit in the Bankruptcy Court for the Southern District Court of New York against the Company, NewEnergy, and CILCO. Pursuant to the complaint, Enron seeks to recover approximately $13 million (plus interest) from NewEnergy (and the Company as guarantor of the obligations of NewEnergy). Enron contends that NewEnergy and the Company are liable to Enron based upon certain accounts receivables purportedly owing from NewEnergy and an alleged payment arising from the purported termination by NewEnergy of a "Master Energy Purchase and Sale Agreement." In the complaint, Enron seeks to recover from CILCO the approximate amount of $31.5 million (plus interest) arising from the termination by CILCO of a "Master Energy Purchase and Sale Agreement" and certain accounts receivables that Enron claims are due and owing from CILCO to Enron. On February 13, 2003 the Company, NewEnergy and CILCO filed a motion to dismiss certain portions of the action and compel arbitration of the disputes with Enron. Also in February 2003, the Bankruptcy Court ordered the parties to mediate the disputes. The mediation process is currently continuing. The Company believes it has meritorious defenses to the claims asserted against it and intends to defend the lawsuits vigorously.

Commencing on May 2, 2003, the Indiana Securities Commissioner of Indiana's Office of the Secretary of State, Securities Division, pursuant to Indiana Code 23-2-1, served subpoenas on 30 former officers and directors of IPALCO Enterprises, Inc. ("IPALCO"), AES, and others, requesting the production of documents in connection with the March 27, 2001 share exchange between the Company and IPALCO pursuant to which stockholders exchanged shares of IPALCO common stock for shares of the Company's common stock and IPALCO became a wholly-owned subsidiary of the Company. IPALCO and the Company have produced documents pursuant to the subpoenas served on them. In addition, the Indiana Securities Commissioner's office has taken testimony from various individuals. On January 27, 2004, Indiana's Secretary of State issued a statement which provided that the investigative staff had determined that there did not appear to be a justifiable reason to focus further specific attention upon six non-employee former members of IPALCO's board of directors. The investigation otherwise remains pending. In addition, although the press release characterized the investigation as criminal, the Company and IPALCO do not believe that the Indiana Securities Commissioner has criminal jurisdiction, and the Company and IPALCO are unaware at this time of any participation by anyone with such criminal jurisdiction.

AES Florestal, Ltda. ("Florestal") a wholly-owned subsidiary of AES Sul, is a wooden electric utility poles factory located in Triunfo, in the state of Rio Grande do Sul, Brazil. In October 1997 AES Sul acquired Florestal as part of the original privatization transaction by the Government of the State of Rio Grande do Sul, Brazil, that created AES Sul. From 1997 to the present, the chemical compound chromated copper arsenate has been used by Florestal to chemically treat the poles under an operating license issued by the Brazilian government. Prior to the acquisition of Florestal by AES Sul, another chemical creosote was used to treat the poles. After acquiring Florestal AES Sul discovered approximately 200 barrels of solid creosote waste on the Florestal property. In 2002 (i) a civil inquiry (Civil Inquiry No. 02/02) was initiated and (ii) a criminal lawsuit was filed in the city of Triunfo's Judiciary both by the Public Prosecutors office of the city of Triunfo. The civil inquiry was settled in 2003. The criminal lawsuit has been suspended for a period of two years pending a certification of environmental compliance for Florestal and the occurrence of no further violations of environmental regulations. Florestal has hired an independent environmental assessment company to perform an environmental audit of the entire operational cycle at Florestal and to recommend remedial actions if necessary. Pending the outcome of the environmental audit, AES Sul is not able to estimate the potential financial impact, if any, on AES Sul.

On February 18, 2004, AES Gener S.A. ("Gener SA"), a subsidiary of the Company, filed a lawsuit in the Federal District Court for the Southern District of New York (the "Lawsuit"). Gener SA is co-venturer with Coastal Itabu, Ltd ("Coastal") in Empressa Generadors de Electricidad Itabu, S.A. ("Itabu"), a Dominican Republic electric generation Company. The lawsuit sought to enjoin the efforts initiated by Coastal to hire an alleged "independent expert", purportedly pursuant to the Shareholder Agreement between the parties, to perform a valuation of Gener SA's aggregate interests in Itabu. Coastal asserts that Gener SA has committed a material breach under the parties' Shareholder Agreement and, therefore, Gener SA is required if requested by Coastal to sell its aggregate interests in Itabu to Coastal at price equal to 75% of the independent expert's valuation. Coastal claims a breach occurred based on alleged violations by Gener SA purported antitrust laws of the Dominican Republic. Gener SA disputes that any default has occurred. On March 11, 2004, upon motion by Gener SA, the court in the Lawsuit enjoined the evaluation being performed by the "expert" and ordered the parties to arbitration. On March 11, 2004, Gener SA commenced arbitration proceedings.

indirect ownership of the mine, as provided in Kazakhstan's bankruptcy legislation. That acquisition was later disputed by several creditors of the mine. After litigation, AES Ekibastusz was successful in having the creditor's claims dismissed by the Kazakhstan courts. In 2003, a new party filed a lawsuit in the local courts of Kazakhstan, claiming that it had succeeded to the rights of one of the creditors whose claims had been dismissed. The plaintiff in the pending lawsuit seeks to have ownership of the coal mine transferred from AES Ekibastusz to the plaintiff.

Pursuant to the pesification established by the Public Emergency Law and related decrees in Argentina, since the beginning of 2002, the Company's subsidiary Termoandes has converted its obligations under its gas supply and gas transportation contracts into pesos, while its income from its electricity exports remains accounted for in U.S. dollars. In accordance with the Argentine regulations, payments must be made in Argentine pesos at a 1:1 exchange rate. The gas suppliers have objected to the payment in pesos. On January 30, 2004, the consortium of gas suppliers, comprised of Tecpetrol S.A., Mobil Argentina S.A. and Compania General de Combustibles S.A., presented a demand for arbitration at the ICC (International Chamber of Commerce) requesting the re-dollarization of the gas price. The arbitration seeks approximately $10,000,000 for past gas supplies. On March 11, 2004, TermoAndes filed with the ICC a response to the arbitration demand. The arbitration is ongoing.

The Company is also involved in certain claims, suits and legal proceedings in the normal course of business.

No matters were submitted to a vote of security holders during the fourth quarter of 2003.

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

During the fourth quarter of 2003, AES issued an aggregated of 20.2 million shares of its common stock in exchange for $20 million aggregate principal amount of its senior notes. The shares were issued without registration in reliance upon Section 3(a)(9) under the Securities Act of 1933.

Our common stock 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 our common stock as reported by the NYSE for the periods indicated.

As of March 3, 2004, there were 9,026 record holders of our common stock, par value $0.01 per share.

Under the terms of our senior secured credit facilities, which we entered into with a commercial bank syndicate, we are not allowed to pay cash dividends. In addition, under the terms of a guaranty we provided to the utility customer in connection with the AES Thames project, we are precluded from paying cash dividends on our common stock if we do not meet certain net worth and liquidity tests.

Our project subsidiaries' ability to declare and pay cash dividends to us is subject to certain limitations contained in the project loans, governmental provisions and other agreements that our project subsidiaries are subject to.

See Item 12 (d) of this Form 10-K for information regarding Securities Authorized for Issuance under Equity Compensation Plans.

Our acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the consolidated financial statements for further explanation of the effect of such activities.

ITEM 7. MANAGEMENTS' DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

AES is a global power company managed to profitably meet the growing demand for electricity. AES is a holding company that through its subsidiaries operates a geographically diversified portfolio of electricity generation and distribution businesses. We seek to capture the benefits of our global expertise and the economies of scale in our operations. Predictable cash flow, an efficient capital structure and world-class operating performance are the focus of our management efforts.

We report our financial results in four business segments: contract generation, competitive supply, large utilities and growth distribution. These segments are grouped further to report our regulated and non-regulated businesses. Regulated revenues include our large utilities and growth distribution segments. Our large utility and growth distribution segments consist of 17 distribution companies with over 11 million end-user customers, most significantly representing three large utilities located in the U.S. (IPL), Brazil (Eletropaulo) and Venezuela (EDC). All three of these utilities are of significant size and all maintain a monopoly franchise within a defined service area. Our contract generation and competitive supply segments consist of multiple power plants located around the world. AES has over 38 gigawatts of generating capacity from 103 power plants on 5 continents. In most cases, these facilities are contract generation plants that have contractually limited their exposure to commodity price risks and electricity price volatility by entering into long-term (five years or longer) power sales agreements for 75% or more of their output capacity. Through these contractual agreements, the businesses generally reduce the commodity and electricity price volatility and thereby increase the predictability of their cash flows and earnings. Competitive supply consists primarily of power plants selling electricity to wholesale customers through competitive markets and, as a result, the cash flows and earnings of such businesses are more sensitive to fluctuations in the market price of electricity, natural gas and coal.

Beginning in 2002 and continuing through 2003, we also have concentrated on several key strategic initiatives that have and will continue to have a material impact on our business. These include:

Our financial results for 2003 reflect the impacts of these strategic initiatives with improvements in sales and operating margins (revenues less cost of sales) across each of our four business segments for 2003. Our results also include the impacts of selling and discontinuing several businesses. Accordingly, we experienced significant losses from discontinued operations in 2002 and 2003 as well as impairment charges related to assets held for sale and terminated development and construction projects. The proceeds from these sales were used to improve our liquidity and reduce outstanding debt. We reduced

parent company debt over the year by $1.2 billion (including the secured equity-linked loan previously issued by AES New York Funding L.L.C.).

Overall our revenues from continuing operations increased 14% to $8.4 billion from 2002 to 2003 and our operating margin increased 25% over 2002 to $2.4 billion for 2003. The operating margin percentage (representing operating margin relative to revenues) increased to 29% of revenues for 2003 as compared to 26% for 2002. Revenues and operating margins also increased during 2002 in each of our five geographic segments—North America, South America, Europe/Africa, Asia and the Caribbean.

Contract generation and large utilities, our two most significant segments, represent 37% and 39%, respectively of our revenues and 52% and 31%, respectively, of our operating margin. Revenues and operating margin contribution continued to be most significant in the contract generation segment. In 2003, recently completed contract generation power plants in the Caribbean and Asia contributed to an overall increase in revenues and also contributed better than average segment operating margin percentages compared to the total portfolio of generating plants. Improvements in contract generation operating margins at existing facilities occurred in Chile, Brazil and Pakistan while our Shady Point plant in the U.S. experienced lower operating margins due to an expected step-down in contract rates. Competitive supply power plants experienced higher operating margins during 2003 due to higher electricity prices in New York and the stronger currency relative to the U.S. dollar in Argentina.

The large utility segment revenues and the operating margin percentage improved from 2002 to 2003 primarily due to higher adjusted tariffs and improved currency conditions in Brazil. Large utility operating margin also increased as a result of an $82 million bad debt impairment at Eletropaulo in Brazil during 2002. Our growth distribution segment experienced higher revenues and operating margins as a result of improvements in the results of our distribution companies in El Salvador and Cameroon. Regulatory asset impairment charges taken by Sul in Brazil during 2002 also contributed to the increase in operating margins. These improvements were partially offset by declines in the operating margins in our Argentine growth distribution businesses in 2003.

During 2003, our contract generation and competitive supply businesses continued to improve their operating performance. The twelve month rolling average availability factor for our generation fleet improved from 85% at the beginning of 2003 to 88% at the end of the year. Some of the major performance improvement initiatives undertaken during 2003 include; implementing a fleet-wide approach to optimizing gas turbine maintenance costs, improving our businesses' heat rates where it was economical to do so and implementing a reliability-centered maintenance program to improve the reliability while reducing the maintenance costs at our businesses.

With respect to our large utilities and growth distribution businesses, our management focus is to capture economies of scale and leverage expertise and skills to maintain our position as a low-cost, efficient producer and distributor of electricity. Supplier relationships and distribution system planning and design benefit from our economies of scale and the depth of our expertise. One important key performance indicator for these businesses is the level of losses. Losses are an expense and are generally defined as the difference between energy purchased or generated and energy billed. Losses can result from several factors. Some losses are the result of physics as energy is lost when converted into heat, referred to as technical losses. Our overall loss rate for non-U.S. utilities reduced by the end of 2003.

Other performance initiatives include the launch in March 2003 of a strategic sourcing initiative that captured cost reductions through the implementation of improved purchasing practices throughout the Company. We also have redeployed talent developed from our restructuring efforts to manage complex

transaction and commercial issues in many of our businesses. These skills are a valuable resource as we monitor regulatory and tariff schemes to determine our capital budgeting needs and integrate acquisitions. The Company expects to realize cost reduction and performance improvement benefits in both earnings and cash flows; however, there can be no assurance that the reductions and improvements will continue and our inability to sustain the reductions and improvements may result in less than expected earnings and cash flows in 2004 and beyond.

During 2003, we continued the initiative to sell all or part of certain of the Company's subsidiaries. This initiative was designed to decrease the Company's dependence on access to capital markets and improve the strength of our balance sheet by reducing financial leverage and improving liquidity. The following chart details the asset sales that were closed during 2003.

Project Name	Date Completed	Sales Proceeds (in millions)	Location
CILCORP/Medina Valley	January 2003	$495	United States
AES Ecogen/AES Mt. Stuart	January 2003	$59	Australia
Mountainview	March 2003	$30	United States
Kelvin	March 2003	$29	South Africa
Songas	April 2003	$94	Tanzania
AES Barry Limited	July 2003	£40/$62	United Kingdom
AES Haripur Private Ltd/AES Meghnaghat Ltd	December 2003	$145	Bangladesh
AES MtKvari/AES Khrami/AES Telasi	August 2003	$23	Republic of Georgia
Medway Power Limited/AES Medway Operations Limited	November 2003	£47/$78	United Kingdom
AES Oasis Limited	December 2003	$150	Pakistan/Oman

The Company continues to evaluate its portfolio and business performance and may decide to dispose of additional businesses in the future. However given the improvements in our liquidity there will be a lower emphasis placed on asset sales in the future for purposes of improving liquidity and strengthening the balance sheet. For any sales that happen in the future, there can be no guarantee that the proceeds from such sale transactions will cover the entire investment in the subsidiaries. Depending on which businesses are eventually sold, the entire or partial sale of any business may change the current financial characteristics of the Company's portfolio and results of operations. Furthermore future sales may impact the amount of recurring earnings and cash flows the Company would expect to achieve.

During 2003, we completed and initiated restructuring transactions for several of our South American businesses. The efforts are focused on improving the businesses long-term prospects for generating acceptable returns on invested capital or extending short-term debt maturities. Businesses impacted include Eletropaulo, Tiete, Uruguaiana and Sul in Brazil and Gener in Chile.

Eletropaulo. AES has owned an interest in Eletropaulo since April 1998, when the company was privatized. In February 2002 AES acquired a controlling interest in the business and as a consequence started to consolidate it. AES financed a significant portion of the acquisition of Eletropaulo, including both common and preferred shares, through loans and deferred purchase price financing arrangements provided by the Brazilian National Development Bank—("BNDES"), and its wholly-owned subsidiary, BNDES Participações S.A. ("BNDESPAR"), to AES's subsidiaries, AES Elpa S.A. ("AES Elpa") and AES Transgas Empreendimentos, S.A. ("AES Transgas").

Despite an interim restructuring in 2002, AES Elpa and AES Transgas were unable to meet scheduled maturities in 2003. On January 30, 2003 and March 3, 2003 these loans entered into default. BNDES did not exercise its right to accelerate those loan amounts after the defaults. BNDES also elected not to exercise its cross-default rights with respect to Eletropaulo's rationing loans. Further, these defaults also gave certain lenders to Eletropaulo acceleration rights that were not exercised.

After several months of negotiations with BNDES, we were able to execute a restructuring agreement, which included the following major terms.

The transaction became effective on January 30, 2004 after approval from ANEEL and the Central Bank of Brazil as well as payment of $90 million by AES.

Additionally, in December 2003, Eletropaulo reached an agreement with its commercial lenders with respect to the terms and conditions of a new transaction to reprofile this outstanding debt over the next five years. This new transaction will resolve all outstanding defaults and accelerations with Eletropaulo's commercial lenders. As the result of this transaction approximately 70% of the reprofiled debt will be denominated in Brazilian Reais. Closing of the Eletropaulo reprofiling transaction is subject to definitive documentation that is expected to be entered into on or shortly after March 15, 2004.

Tiete. Due to dividend restrictions under Brazilian corporate law, Tiete's dividends may not be sufficient to make payments due in 2004 and 2005 on approximately $295 million of debt due by AES IHB Cayman, Ltd., an affiliate of Tiete. Consequently AES Tiete Holdings, Ltd., Tiete's parent company, entered into restructuring discussions with the certificate holders in August 2003. These negotiations were successfully concluded with the receipt of consents on December 15, 2003 from 100% of the certificate holders to restructure the certificates. The transaction closed on January 30, 2004. The restructuring, among other things, adjusted the repayment schedule, extended the final maturity date, changed the payment dates, eliminated the OPIC coverages, increased the debt service reserve account (related to which AES funded $15 million) and permitted the change of ownership of AES Tiete Holdings, Ltd. in order to effect the transfer related to the broader restructuring agreement with BNDES.

Additionally, Energia Paulista Participações S.A., an indirect subsidiary of AES, has outstanding local non-recourse debentures in the amount of $53 million, which were due on August 11, 2003. These debentures were issued to acquire 19% of Tiete's preferred shares and are guaranteed by such shares. On August 7, 2003, approximately 91% of the debenture holders approved a change to certain terms and conditions of the debentures. The debentures are now due on August 11, 2005, interest on the debentures will be increased from 12% to 14% per annum but no interest payment will be made until August 11, 2004 and if no interest payment is made at that time the debenture holder will be entitled to convert the debentures held into the preferred shares used to secure the guarantee. The remaining

9% of debenture holders that did not accept the offer received shares in lieu of payment which reduced the Company's interest in the preferred shares from 19% to 17%.

Sul. The efforts to restructure the debt at Sul and AES Cayman Guaiba, a subsidiary of the Company that owns the Company's interest in Sul, are in process and have been focused in the following areas:

Sul and AES Cayman Guaiba will continue to face shorter-term debt maturities in 2004 and 2005 but, given that a bankruptcy proceeding would generally be an unattractive remedy for each of its lenders as it could result in an intervention by ANEEL or a termination of Sul's concession, we think such an outcome is unlikely. However, we can not be assured that future negotiations will be successful and AES may have to write-off some or all of the assets of Sul or AES Cayman Guaiba. The Company's total investment associated with Sul as of December 31, 2003 was approximately $266 million.

Chile. On February 23, 2004 AES Gener S.A. ("Gener") announced details relating to the restructuring of Gener. Pursuant to the restructuring, which is expected to be completed by the end of April, the Company will settle an intercompany loan between our indirect subsidiary, Inversiones Cachagua Ltda. ("Cachagua"), and Gener (this part of the transaction was completed on February 27, 2004). The details of the restructuring are as follows:

We cannot assure you that the Gener restructuring will be completed or that the terms thereof will not be changed materially. In addition, Gener is in the process of restructuring the debt of its subsidiaries, TermoAndes S.A. ("TermoAndes") and InterAndes, S.A. ("InterAndes"), and expects that the maturities of these obligations will be extended.

During 2003 we sold or discontinued under-performing businesses and construction projects that did not meet our investment criteria or did not provide reasonable opportunities to restructure. It is anticipated that there will be less ongoing activity related to write-offs of development or construction projects and impairment charges in the future. The businesses, which were affected in 2003, are listed below.

Project Name	Project Type	Date	Location	Impairment (in millions)
Ede Este (1)	Operating	December 2003	Dominican Republic	$	60
Wolf Hollow	Operating	December 2003	United States	$	120
Granite Ridge	Operating	December 2003	United States	$	201
Colombia I	Operating	November 2003	Colombia	$	19
Zeg	Construction	December 2003	Poland	$	23
Bujagali	Construction	August 2003	Uganda	$	76
El Faro	Construction	April 2003	Honduras	$	20

Our de-leveraging efforts reduced parent level debt by $1.2 billion in 2003 (including the secured equity-linked loan previously issued by AES New York Funding L.L.C.). We refinanced and paid down near-term maturities by $3.5 billion and enhanced our year-end liquidity to over $1 billion. Our average debt maturity was extended from 2009 to 2012. At the subsidiary level we continue to pursue limited recourse financing to reduce parent credit risk. These factors resulted in an overall reduced cost of capital, improved credit statistics and expanded access to credit at both AES and our subsidiaries.

Liquidity at the AES parent level is an important factor for the rating agencies in determining whether the Company's credit quality should improve. Currency and political risk tend to be biggest variables to sustaining predictable cash flow. The nature of our large contractual and concession-based cash flow from these businesses serves to mitigate these variables. In 2003, over 81% of cash distributions to the parent company were from U.S. large utilities and worldwide contract generation.

On February 4, 2004, we called for redemption of $155,049,000 aggregate principal amount of outstanding 8% Senior Notes due 2008, which represents the entire outstanding principal amount of the 8% Senior Notes due 2008, and $34,174,000 aggregate principal amount of outstanding 10% secured Senior Notes due 2005. The 8% Senior Notes due 2008 and the 10% secured Senior Notes due 2005 were redeemed on March 8, 2004 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date. The mandatory redemption of the 10% secured Senior Notes due 2005 was being made with a portion of our "Adjusted Free Cash Flow" (as defined in the indenture pursuant to which the notes were issued) for the fiscal year ended December 31, 2003 as required by the indenture and was made on a pro rata basis.

On February 13, 2004 we issued $500 million of unsecured senior notes. The unsecured senior notes mature on March 1, 2014 and are callable at our option at any time at a redemption price equal to 100% of the principal amount of the unsecured senior notes plus a make-whole premium. The unsecured senior notes were issued at a price of 98.288% and pay interest semi-annually at an annual

coupon rate of 7.75%. We used the net proceeds of the offering to repay approximately $500 million of our term loan under our senior secured credit facilities.

The Company's significant accounting policies are discussed in Note 1 of the consolidated financial statements. The preparation of the financial statements requires that management make subjective estimates, assumptions and judgments in applying these accounting policies. Those judgments are normally based on knowledge and experience about past and current events and on assumptions about future events. Critical accounting estimates require management to make assumptions about matters that are highly uncertain at the time of the estimate and a change in these estimates may have a material impact on the presentation of the Company's financial position or results of operations. The following critical accounting policies have and will have an impact on our business:

Property, Plant, and Equipment. We record property, plant and equipment at cost and depreciate property, plant and equipment over its estimated useful life. We may be required to decrease the estimated useful life of our impacted generation facilities if we lose a long-term contract at one of our contract generation businesses and cannot replace it or we experience a significant overabundance of supply and a sustained, significant decline in market prices in the regions served by our competitive supply businesses. We may also decrease the estimated useful life of our impacted distribution facilities if we lose a long-term concession agreement at one of our growth distribution businesses or large utilities and cannot replace it. Additionally, we may decrease the estimated useful life of the affected property, plant and equipment if we incur significant physical damage or a significant mechanical failure. If we change the useful life of any of our property, plant and equipment, we plan to base the new life on engineering studies and our expected usage of the property, plant and equipment. The estimated remaining useful life of our property, plant and equipment is approximately 28 years. If we were to decrease the estimated average remaining useful life of our property, plant and equipment by 5 years, our annual depreciation expense would increase by $159 million. A significant decrease in the estimated useful life of a material amount of property, plant and equipment could have a material adverse impact on our operating results in the period in which the estimate is revised and in subsequent periods.

Long-Lived Assets. We assess long-lived assets for impairment when indicators of impairment exist. We use estimates of future cash flows based on expected cash flows from the use and eventual disposition of the assets to test the recoverability of specific long-lived assets. We have $9.2 billion of long-lived contract generation assets and our expected cash flows for businesses within the contract generation segment are based on the expected output of our generation facilities as well as the terms of our contractual agreements. We have $1.6 billion of long-lived competitive supply assets and our expected cash flows for our businesses within the competitive supply segment are based on the expected output of the generation facilities as well as expected future market prices published on industry forward curves and other market price studies. We have $7.1 billion of large utility long-lived assets and $1.6 billion of growth distribution long-lived assets. We consider historical experience as well as future expectations and the expected future cash flows are based on expected future tariffs and expected future customer demand in order to determine expected cash flows for businesses within our large utilities and growth distribution segments. A significant reduction in actual cash flows and estimated cash flows may have a material adverse impact on our operating results and financial condition.

Regulatory Assets. At each reporting date, the Company reviews current regulatory trends in the markets in which it operates. This review involves judgment and is critical in assessing the recoverability of regulatory assets as well as the ability to continue to account for its activities based on the criteria set forth in SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). Based on the Company's current review, it believes its regulatory assets are probable of recovery. If all or part

of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. We recorded deferred regulatory assets of $741 million, and $627 million at December 31, 2003 and 2002 respectively, that we expect to pass through to our customers in accordance with and subject to regulatory provisions. These amounts include $29 million and $105 million of assets classified as discontinued operations at December 31, 2003 and 2002 respectively. We record the deferred regulatory assets at entities that are controlled and consolidated by us in other assets on the consolidated balance sheets. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets. In the event the regulator prevents us from including a material amount of capitalized costs in future tariffs and we therefore write-off all or a portion of these assets, our operating results may be materially and negatively impacted.

The table below illustrates the businesses that contain these regulatory assets (in millions):

		December 31,
		2003		2002
BUSINESSES:
Eletropaulo		$	629	$	456
Sul			35		23
IPALCO (1)			48		44

	Sub Total		712		523

DISCONTINUED BUSINESSES:
CILCORP			—		11
Telasi			—		64
Ede Este			29		29

	Sub Total		29		104

	Total	$	741	$	627

Functional Currency Determination. A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. If facts and circumstances require a change in the functional currency of a significant subsidiary, the change in functional currency could have a material impact on our operating results and financial condition. A change in the commercial contracts of a business which results in indexation of revenues and expenses to a currency other than the local currency of the business would require us to evaluate the appropriate functional currency for that respective business. Additionally, we would also be required to evaluate the appropriate functional currency for a respective business upon a significant change in the denomination of the financing and the availability of cash flows for remittance to the parent.

Pension and Postretirement Obligations. Certain of our foreign and domestic subsidiaries maintain defined benefit pension plans, which we refer to as the pension plans, or the plans, covering substantially all of their respective employees. Pension benefits are generally based on years of credited service, age of the participant and average earnings. Of the thirteen pension plans existing at December 31, 2003, two exist at domestic subsidiaries and eleven exist at foreign subsidiaries.

Two defined benefit pension plans constitute 95% of pension cost for the year ended December 31, 2003, 89% of the benefit obligation at December 31, 2003 and 87% of the fair value at December 31,

2003. One plan is a plan administered in the United States, which we refer to as the U.S. plan, and the other plan is administered in Brazil, which we refer to as the Brazilian plan. Of the remaining plans, no one plan represents a significant portion of the pension cost, benefit obligation or fair value at December 31, 2003.

Pension cost for the U.S. plan is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on plan assets of 9% in 2003, 2002 and 2001. In developing our expected long-term rate of return assumption, we evaluated input from our actuaries, including their review of asset class return expectations by several respected consultants and economists, as well as long-term inflation assumptions. Projected returns by such consultants and economists are selected from within the "best estimate range," which is the smallest range which the actuary reasonably anticipates that the actual results, compounded over the measurement period, are more likely to fall than not. The best estimate of this range is based on asset class return expectations which reflect historical data as well as the opinion of several consultants and economists about the forecasted returns of each class. The best estimate range is a probability distribution of returns that spans the 25^th to 75^th percentiles of 20-year returns. We anticipate that our investment managers will continue to generate long-term returns of at least 9%. We base our expected long-term rate of return on plan assets on an asset allocation assumption of 45% U.S. equities, 10% non-U.S. equities, 40% fixed income and 5% real estate which is equal to our actual asset allocation. We continue to believe that 9% is a reasonable long-term rate of return on our plan assets. We continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually, and will adjust these assumptions as necessary.

We determine the pension expense or income for the U.S. plan based on the fair value of assets on the measurement date. As of November 30, 2003, the U.S. plan has generated cumulative unrecognized net actuarial losses of approximately $88 million which we have not yet recognized as pension cost. These unrecognized net actuarial losses may result in decreases in future pension income depending on several factors, including whether such losses at each measurement date exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets in accordance with SFAS No. 87, "Employers Accounting for Pensions."

The discount rate we use to determine future pension obligations for the U.S. plan is based upon the Aa rated annual yield as of the measurement date as published in the Moody's Daily Long-term Corporate Bond Yields based on bonds with maturities of 20 years and above. Using this basis, we determined the discount rate to be 6.75% in 2003, 6.75% in 2002, and 7.25% in 2001.

Lowering the expected long-term rate of return on the U.S. Plan assets by 1% would have increased our 2003 pension cost by approximately $2.6 million. Lowering the discount rate by 100 basis points would increase our 2003 pension cost by approximately $2.7 million.

The fair value of the U.S. plan's assets has increased to $330 million at December 31, 2003 from $224 million at December 31, 2002. The investment performance returns and benefits paid during 2003 has decreased the underfunded position, net of benefit obligations, of the U.S. Plan from $187 million at December 31, 2002 to $113 million at December 31, 2003.

We began to report the Brazilian plan on a consolidated basis when we acquired an additional ownership interest in Eletropaulo in February 2002. We calculate the pension cost for the Brazilian plan based upon a number of actuarial assumptions, including an expected long-term rate of return on plan assets of 14% in 2003. In developing our expected long-term rate of return assumption, we evaluated input from our actuaries, including their review of asset class return expectations which are based on studies of historical data series as well as the opinion of several respected consultants and economists about forecasts, long-term inflation assumptions, dollar spot assumptions and local interest rate assumptions. We based each asset class return expectation upon historical returns for assets with similar maturities and risk. We anticipate that our investment managers will continue to generate long-term returns of at least 12%. Over the past seven years, the Brazilian plan has had actual returns

of 18%. Our expected long-term rate of return on plan assets is based on an asset allocation assumption of 76% fixed income investments, 20% equities and 4% real estate. Our assumed asset allocation uses a lower exposure to equities to more closely match market conditions and near-term forecasts. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually, and will adjust as necessary.

We base our determination of the Brazilian plan pension expense or income on the fair value of assets on the measurement date. As of December 31, 2003, the Brazilian plan has generated cumulative unrecognized net actuarial losses of approximately $461 million which we have not yet recognized as pension cost. These unrecognized net actuarial losses result in decreases in future pension income depending on several factors, including whether such losses at each measurement date exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets in accordance with SFAS No. 87, "Employers Accounting for Pensions."

We use a discount rate based on long-term annuity contracts to determine future pension obligations for the Brazilian plan since there is no active corporate bond market in Brazil. On this basis, we determined the discount rate to be 12% for 2003.

If we lowered the expected long-term rate of return on our plan assets by 1.0%, our 2003 pension cost would have increased by approximately $8.0 million. If we lowered the discount rate by 100 basis points, our 2003 pension cost would increase by approximately $22.8 million.

The fair value of the Brazilian plan assets is $980 million at December 31, 2003. The Brazilian plan has an underfunded position, net of benefit obligations, of $1,114 million at December 31, 2003.

Annually, we review all pension plans to determine if the plans' accumulated benefit obligations exceed the fair value of the plans' assets. If the accumulated benefit obligations exceed the fair value of plan assets, we record an additional minimum pension liability on the balance sheet, with a corresponding charge to other comprehensive income. We may incur additional minimum pension liabilities in future periods and they could be material.

On an ongoing basis, the Company's evaluates its estimates, including those related to the value of goodwill and intangible assets, inventories, bad debts, income taxes and contingencies and litigation. The Company's estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

Variable Interest Entities. On December 24, 2003 the FASB issued Interpretation No. 46 (Revised 2003), Consolidation of Variable Interest Entities ("FIN 46(R)"). FIN 46(R) partially deferred the effective date of FIN 46 for certain entities, and makes several other major changes to FIN 46 which include, an improved definition of variable interest, and an exemption for many entities defined as businesses in the Interpretation. FIN 46(R) also eliminated bias against decision maker fees and certain guarantee fees which were previously treated as variable interests in a variable interest entity, the effect of which is that decision makers and certain guarantors are less likely to become primary beneficiaries. The Company applied FIN 46 in its financial statements relating to its interest in variable interest entities or potential variable interest entities commonly referred to as special-purpose entities as of December 31, 2003. The Company is required to apply FIN 46(R) for all other types of entities in its financial statements for the quarter ending March 31, 2004. The effects FIN 46(R) will have on results of operations and financial position are currently being evaluated. The Company does not believe that the adoption and application of FIN 46(R) will result in the consolidation of any previously unconsolidated entities or material additional disclosure. Application of FIN 46(R) may cause the Company to discontinue consolidation of certain subsidiaries.

Revenues increased approximately $1.0 billion, or 14%, to $8.4 billion in 2003 from $7.4 billion in 2002. The increase in revenues is due to new operations from greenfield projects and improvements from existing operations. Excluding businesses that commenced commercial operations in 2003 or 2002, revenues increased 8% to $8.0 billion in 2003.

Revenues increased approximately $1.1 billion, or 16%, to $7.4 billion in 2002 from $6.3 billion in 2001. The increase in revenues is due to the acquisition of new businesses and new operations from greenfield projects. Excluding businesses that we acquired or that commenced commercial operations in 2002 or 2001, revenues decreased 19% to $4.9 billion in 2002.

Regulated revenues increased 10% or $409 million, to $4.4 billion in 2003 compared to 2002. This increase is the result of a $151 million increase in our large utilities segment, and a $258 million increase in growth distribution segment. We did not acquire or commence operations of any business in 2003 or 2002 that had an impact on our regulated revenues.

Regulated revenues increased 39% or $1.1 billion, to $4 billion in 2002 compared to 2001. This increase is the result of $1.5 billion increase in our large utilities segment, which is offset by a $378 million reduction in our growth distribution segment. Excluding businesses acquired or that commenced operation in 2002 or 2001, regulated revenues decreased 29% to $2.0 billion during 2002.

The increase in large utility segment revenue in 2003 of $151 million is primarily due to the consolidation of Eletropaulo for a full fiscal year compared to 11 months in 2002, where revenues increased $163 million compared to 2002. Total sales volume at Eletropualo increased year over year by approximately 1%, although this was more than offset by a decline in the average customer tariff in 2003 resulting from a decrease in residential consumption. This net increase at Eletropaulo as well as an increase of 2% ($14 million) in revenues at IPALCO, were partially offset by a 4% ($26 million) decline in revenues at EDC.

The large utility segment revenue increase in 2002 is due to the consolidation of Eletropaulo in Brazil, which is partially offset by an $18 million decrease at IPALCO and a $171 million decrease at EDC compared to 2001. Lower revenues at IPALCO resulted from lower wholesale electricity prices in 2002. The decline at EDC was primarily caused by the devaluation of the Venezuelan Bolivar during the year. We began consolidating Eletropaulo in February 2002 when we obtained control of the business. Please see Note 2 to the Consolidated Financial Statements for a complete description of the Eletropaulo swap transaction. If Eletropaulo had been consolidated during the comparable period in 2001, revenues compared to the prior period would have been lower due to electricity rationing in Brazil in early 2002. Although rationing ended in February 2002 customer demand did not return to the level it was prior to rationing.

Revenue from the growth distribution segment in 2003 increased $258 million as compared to 2002. The most significant component of the increase was due to the impact of the $146 million provision recorded at Sul in 2002 discussed below. The most significant additional contributions to the 2003 increase included an increase of $57 million at Sonel in Cameroon resulting from higher customer tariffs in 2003 and increased sales volumes, an increase of $30 million in our El Salvador distribution businesses because of higher sales volumes and increased tariffs and an increase in our Argentine distribution businesses primarily arising from the appreciation of the Argentine peso in 2003.

Revenue from the growth distribution segment decreased $378 million in 2002 compared to 2001 due to the economic and regulatory impacts of the devaluation of the Argentine peso at Eden, Edes and Edelap where aggregate revenues decreased $228 million. Additionally, during the second quarter of 2002, ANEEL, the Brazilian electricity regulator, announced an order to retroactively change the calculation methods of the Wholesale Energy Markets ("MAE"). As a result the Company recorded a provision for the Brazilian regulatory decision at Sul of approximately $146 million against revenues. Increases in Europe/Africa are primarily due to the acquisitions of Sonel and Kievoblenergo and Rivnooblenergo in the Ukraine.

Non-regulated revenues increased 19%, or $626 million, to $4.0 billion in 2003 compared to 2002. This increase is the result of a $558 million increase in our contract generation segment, and a $68 million increase in our competitive supply segment. Excluding businesses that commenced operations in 2003 or 2002, non-regulated revenues increased 6% to $3.5 billion in 2003.

Non-regulated revenues decreased 1%, or $50 million, to $3.4 billion in 2002 compared to 2001. This decrease is the result of a $22 million decrease in our contract generation segment, and a $28 million

decrease in our competitive supply segment. Excluding businesses acquired or that commenced operations in 2002 or 2001, non-regulated revenues decreased 11% to $3.0 billion in 2002.

Revenue from the contract generation segment for 2003 increased $558 million over 2002 primarily due to the addition of recently completed businesses including Red Oak in New Jersey (which reported results from operations for a full year), Puerto Rico L.P. in Puerto Rico, Kelanitissa in Sri Lanka, Barka in Oman, Ras Laffan in Qatar and Andres in the Dominican Republic. Together, these businesses contributed $407 million, or 73%, of the increase for 2003. Revenues also improved over the same time period at Los Mina in the Domincan Republic, Merida III in Mexico, Tisza in Hungary, Gener in Chile, and Tiete in Brazil. These improvements were offset by declines at Shady Point in Oklahoma, due to a scheduled decrease in the contracted capacity payment, and at Lal Pir and Pak Gen in Pakistan, because of lower energy dispatch in 2003.

Revenue from our contract generation segment for 2002 decreased $22 million from 2001 due to declines at Southland in California, the Gener plants in Chile, Tiete and Uruguaiana in Brazil, Los Mina in the Dominican Republic, and Merida III in Mexico. The reductions at these businesses were offset, in part by improvements resulting from the start of operations at Ironwood in Pennsylvania and Red Oak in New Jersey during 2002, as well as increased revenues from Warrior Run in Maryland, the acquisition of Mendota in California, Hemphill in New Hampshire, Ebute in Nigeria and Bohemia in the Czech Republic.

Revenue from our competitive supply segment for 2003 increased $68 million over 2002 due primarily to an increase of $54 million in the revenues at our New York plants, where average competitive market prices for electricity sold by those plants increased approximately 29% over 2002. The remaining net increase resulted from improvements at several other plants including Alicura and

Parana in Argentina, Panama in the Caribbean and Ekibastuz in Asia. These increases were partially offset by decreased revenues from Deepwater in Texas due to an extended outage in 2003 and the termination of a small retail electricity business in the U.K. in early 2003.

Revenue from our competitive supply segment for 2002 decreased $28 million over 2001 due to a reduction in average competitive market prices in New York of approximately 11% during the year,as well as a decline in demand in California due to mild weather. Revenues decreased additionally due to the devaluation of the Argentine peso in February 2002. These declines were offset slightly by the completion of construction and the start of operations at Parana in Argentina and the acquisition of Ottana in Italy.

Gross margin increased $483 million, or 25%, to $2.4 billion in 2003 from $2.0 billion in 2002. Gross margin as a percentage of revenues increased to 29% in 2003 from 26% in 2002. The increase is primarily due to new operations from greenfield projects. Excluding businesses that commenced commercial operations in 2003 or 2002, gross margin increased 16% to $2.2 billion in 2003. We expect that our gross margin will be negatively impacted in future periods by the expensing of stock options and other long-term incentive compensation.

Gross margin decreased less than $50 million, or less than 3%, to approximately $2.0 billion in 2002 compared to 2001. Gross margin as a percentage of revenues decreased to 26% in 2002 from 32% in 2001. The decrease in gross margin is due to lower market prices in the United States and was partially offset by the acquisition of new businesses and new operations from greenfield projects. Excluding businesses acquired or that commenced commercial operations in 2002 or 2001, gross margin decreased 23% to $1.6 billion in 2002.

Regulated gross margin increased 35% or $244 million in 2003 compared to 2002. The increase is due to a $75 million increase in our large utilities segment, and $169 million increase in our growth distribution segment. Regulated gross margin as a percentage of revenues increased to 21% in 2003 from 17% in 2002. Excluding businesses that commenced operations in 2003 or 2002, regulated gross margin increased 35% to $946 million in 2003.

Regulated gross margin decreased 22% or $201 million in 2002 compared to 2001. The decrease is primarily due to weakening margins in our South American growth distribution businesses and our Caribbean large utility business offset by increases at our North and South American large utilities and Europe/Africa growth distribution businesses. Regulated gross margin as a percentage of revenues

decreased to 17% in 2002 from 31% in 2001. Excluding businesses acquired or that commenced operations in 2002 or 2001, regulated gross margin decreased 54% to $427 million in 2002.

Gross margin from our large utilities segment increased in 2003 due to higher gross margins in South America, which was due to an $82 million bad debt impairment at Eletropaulo in 2002. EDC's gross margin increased due to higher demand and increased tariffs in 2003 compared to 2002. IPALCO experienced a lower margin and margin percentage due to milder weather and higher operating and maintenance cost in 2003. The large utilities segment gross margin as a percentage of large utility segment revenue increased to 23% for 2003 from 22% in 2002.

Gross margin from our large utilities segment increased in 2002 due to increases in North and South America offset in part by a decrease in the Caribbean. North America increased due to increased contributions from IPALCO. South America increased due to the consolidation of Eletropaulo. The decrease in the Caribbean is due to the devaluation of the Venezuelan Bolivar and its impacts on EDC. EDC's tariff is adjusted semi-annually to reflect fluctuations in inflation and the currency exchange rate. However, a failure to receive such an adjustment to reflect changes in the exchange rate and inflation could adversely affect their results of operations in the future. The large utilities gross margin as a percentage of large utility segment revenues decreased to 22% for 2002 from 37% in 2001. Eletropaulo's 2002 gross margin was negatively impacted by the write off of approximately $80 million of other receivables. Our distribution concession contracts in Brazil provide for annual tariff adjustments based upon changes in the local inflation rates and, generally, significant devaluations are followed by increased local currency inflation. However, because of the lack of adjustment to the current exchange rate, the in arrears nature of the respective tariff adjustment, or the potential delays or magnitude of the resulting local currency inflation of the tariff, the future results of operations of Eletropaulo could be adversely affected by the continued devaluation of the Brazilian Real.

Gross margin from our growth distribution segment increased in 2003 due to increases at Sonel in Cameroon and Caess in El Salvador. Additionally, there was a nonrecurring charge taken in 2002 for the write-off of $141 million related to MAE settlements at Sul in Brazil that did not occur in 2003. These increases were partially offset by decreased gross margins at Eden, Edes and Edelap in Argentina. The growth distribution gross margin as a percentage of growth distribution segment revenues increased to 16% in 2003 from 2% in 2002.

Gross margin from our growth distribution segment decreased in 2002 due to a decline of $310 million in South America gross margin, which was offset in part by increases in Europe/Africa and the Caribbean, respectively. South America gross margin declined primarily due to devaluation of the Argentine peso and the reduction in gross margin from Sul due to the $146 million provision for the Brazilian regulatory decision. Europe/Africa gross margin increased due to the acquisitions of Kievoblenergo and Rivnooblenergo in the Ukraine. The growth distribution gross margin as a percentage of growth distribution segment revenues decreased to 2% in 2002 from 23% in 2001.

Non-regulated gross margin increased 16% or $239 million in 2003 compared to 2002. This increase is due to a $37 million increase in our competitive supply segment, and a $202 million increase in our contract generation segment. Non-regulated gross margin as a percentage of revenues remained relatively constant at 37% in 2003 and in 2002. Excluding businesses that commenced operations in 2003 or 2002, non-regulated gross margin increased 6% to $1.3 billion in 2003.

Non-regulated gross margin increased 12% or $151 million in 2002 compared to 2001. This increase is due to a $172 million increase in our contract generation segment, which is offset by a $24 million decrease in our competitive supply segment. Non-regulated gross margin as a percentage of revenues increased to 37% in 2002 from 32% in 2001. Excluding businesses acquired or that commenced operations in 2002 or 2001, non-regulated gross margin increased 4% to $1.1 billion in 2002.

Gross margin from our contract generation segment increased in 2003 because of improvements at Tiete in Brazil, and Ebute in Nigeria compared to 2002. Additionally, new plants came online and contributed to the increase. These new plants include Red Oak in New Jersey, Puerto Rico L.P. in Puerto Rico, Kelanitissa in Sri Lanka, Barka in Oman, Ras Laffan in Qatar and Andres in the Dominican Republic. These increases were partially offset by declines in gross margin at Beaver Valley and Ironwood in Pennsylvania, Shady Point in Oklahoma, Kilroot in Northern Ireland and the Chigen plants in China. The contract generation gross margin as a percentage of contract generation revenues slightly decreased to 41% in 2003 from 42% in 2001.

Gross margin from our contract generation segment increased in 2002 compared to 2001 due to improvements at existing businesses and operations from new businesses. The contract generation gross margin as a percentage of revenues increased to 42% in 2002 from 35% in 2001. Gross margin increased in all geographic regions. North America gross margin increased due to the start of commercial operations at Ironwood in Pennsylvania, Red Oak in New Jersey and improvements at Warrior Run in Maryland and Beaver Valley in Pennsylvania. South America gross margin increased due to increases at Gener, Tiete and Uruguaiana. Europe/Africa gross margin increased $53 million mainly due to the acquisition of Ebute in Nigeria and improvements at Kilroot in Northern Ireland and Tisza II in Hungary. Asia gross margin increased due to increased contributions from Jiaozuo and Hefei in China.

Gross margin from our competitive supply segment increased in 2003 due to improvements at the NY Plants, CTSN and Parana in South America and Altai in Asia. These increases were partially offset by lower margins and margin percentages at Deepwater in Texas and Borsod in Europe/Africa. The

competitive supply gross margin as a percentage of competitive supply revenues increased to 25% in 2003 from 23% in 2002.

Gross margin from our competitive supply segment decreased in 2002 compared to 2001 due to reductions in North America, South America, Europe and Africa gross margins that were offset slightly by increases from the Caribbean and Asia. North America gross margin decreased mainly due to the lower energy prices in New York and milder weather in California. South America gross margin decreased mainly due to the devaluation of the peso in Argentina. Caribbean gross margin increased due to increases from Panama and Chivor in Colombia. The competitive supply gross margin as a percentage of revenues decreased to 23% in 2002 from 25% in 2001.

Corporate and business development office expense increased $45 million, or 29%, to $157 million in 2003 from $112 million in 2002. Corporate and business development office expense as a percentage of total revenues remained approximately 2% in 2003 and in 2002. The increase in dollar amounts is a result of additional personnel, infrastructure and consulting associated with the implementation of several corporate initiatives, new government compliance regulations, expensing of stock options and other long-term incentive compensation.

Corporate and business development expense decreased $8 million, or 7%, to $112 million in 2002 from $120 million in 2001. Corporate and business development expense as a percentage of total revenues remained approximately 2% in 2002 and in 2001. The overall decrease in corporate and business development expense was due to the Company's increased focus on cost cutting.

During 2001, the Company incurred approximately $131 million of transaction and contractual severance costs related to the acquisition of IPALCO.

Interest expense increased $242 million, or 24%, to $2 billion in 2003 from $1.7 billion in 2002. Interest expense as a percentage of revenues was 24% in 2003 and 24% in 2002. Eletropaulo accrued $194 million of interest expense regarding their defaulted debts in 2003, which comprises 80% of the increase in interest expense for the year ended December 31, 2003 over the year ended December 31, 2002. In December 2003, we reached an agreement with BNDES and BNDESPAR to restructure those defaulted debts through a partial ownership of a new company, which will hold our direct and indirect interests in Eletropaulo, Uruguaiana and Tiete, and a payable which will be paid over an eleven year period. Also, during December 2002, we refinanced a significant amount of debt with debt containing less favorable terms than those in the original debt. Of this debt $852 million was retired in 2003, and approximately $500 million during the first quarter of 2004. In 2003, several projects were abandoned and all capitalized interest related to those projects was written-off.

Interest expense increased $417 million, or 31%, to $1.7 billion in 2002 from $1.3 billion in 2001. Interest expense as a percentage of revenues was 24% in 2002 and 21% in 2001. Overall interest expense increased primarily due to the consolidation of Eletropaulo in February 2002, issuance of senior secured notes at IPALCO, interest expense from new businesses, as well as additional corporate interest costs arising from a higher outstanding balance during 2002 on our revolving loan.

Interest income increased $21 million, or 8%, to $280 million in 2003 from $259 million in 2002. Interest income as a percentage of revenues was 3% in 2003, and 4% in 2002. The increase in interest

income during 2003 is due primarily to a $58 million increase in interest earnings in Eletropaulo related to its regulatory asset and accounts receivable. We consolidated Eletropaulo in February 2002, therefore the results for 2003 included 12 months compared to 11 months in 2002. The increase in Eletropaulo in 2003 over 2002 was partially offset by a general decline in interest earnings due to a decline in the interest rates.

Interest income increased $100 million, or 63%, to $259 million in 2002 from $159 million in 2001. Interest income as a percentage of revenues was 4% in 2002, and 3% in 2001. The increase in interest income during 2002 is due primarily to the consolidation of Eletropaulo partially offset by a decline in interest income from Thames, in the U.S., due to the collection of its contract receivable.

Other income increased $38 million, or 29%, to $171 million in 2003 from $133 million in 2002. Approximately $141 million of other income recorded in 2003 is attributable to gains on the extinguishment of liabilities. See Note 17 to our consolidated financial statements for an analysis of other income.

Other income increased $20 million, or 18%, to $133 million in 2002 from $113 million in 2001. Approximately $90 million of the amount recorded in 2002 is attributable to gains on the extinguishment of liabilities and mark-to-market gains on commodity derivatives. See Note 17 to the consolidated financial statements for an analysis of other income.

Other expense increased $27 million, or 31%, to $110 million in 2003 from $83 million in 2002. Approximately $57 million of other expense recorded in 2003 is attributable to mark-to-market loss on commodity derivatives and debt refinancing costs. See Note 17 to the consolidated financial statements for an analysis of other expense.

Other expense increased $22 million, or 36%, to $83 million in 2002 from $61 million in 2001. Approximately $76 million of the amount recorded in 2002 is attributable to losses on the extinguishment of liabilities and other non-operating expenses. See Note 17 to the consolidated financial statements for an analysis of other expense.

Foreign currency transaction gains increased $586 million to $127 million in 2003 from a loss of $459 million in 2002. Foreign currency transaction gains increased primarily due to an appreciation of the Brazil Real during 2003 from 3.53 at December 31, 2002 to 2.89 at December 31, 2003. This appreciation resulted in a gain of approximately $130 million for the year ended December 31, 2003. Additionally, the Argentine peso appreciated from 3.32 at December 31, 2002 to 2.93 at December 31, 2003. This appreciation resulted in approximately $37 million of foreign currency transaction gains for the year ended December 31, 2003. These gains were offset by $12 million of foreign currency transaction losses recorded at EDC during 2003 due to a 12% devaluation of the Venezuelan Bolivar from 1,403 at December 31, 2002 to 1,600 at December 31, 2003. EDC uses the U.S. dollar as its functional currency but a portion of its debt is denominated in the Venezuelan Bolivar.

Foreign currency transaction losses increased $447 million to $459 million in 2002 from $12 million in 2001. Foreign currency transaction losses increased primarily due to 50% devaluation in the Argentine peso from 1.65 at December 31, 2001 to 3.32 at December 31, 2002, which resulted in $143 million of foreign currency transaction losses for the year ended December 31, 2002. Additionally, 32% devaluation occurred in the Brazilian Real during 2002 from 2.41 at December 31, 2001 to 3.53 at December 31, 2002. Furthermore, we recorded more foreign currency losses due to the consolidation of

Eletropaulo, and since there was less allocation to the minority partners because their investment has been reduced to zero. As a result, we recorded net Brazilian foreign currency losses of $357 million during 2002, of which approximately $83 million is included in equity in pre-tax (losses) earnings of affiliates. These decreases were offset by $39 million of foreign currency transaction gains recorded at EDC during 2002 due to a 46% devaluation of the Venezuelan Bolivar from 758 at December 31, 2001 to 1,403 at December 31, 2002. EDC uses the U.S. dollar as its functional currency but a portion of its debt is denominated in the Venezuelan Bolivar.

Equity in (losses) earnings of affiliates increased by $297 million to income of $94 million in 2003 compared to a loss of $203 million in 2002. The overall increase is due primarily to the change of control in February 2002 of Eletropaulo, and an impairment charge taken for an other than temporary decline in value at CEMIG in 2002.

Equity in earnings of contract generation affiliated increased to $94 million in 2003 from $75 million in 2002. The increase is due to improvements from Chigen and OPGC in Asia, Elsta in Europe/Africa, and income realized from the gain on the sale of our ownership interest in Medway Power Ltd.

Equity in (losses) earnings of affiliates declined by $378 million to a loss of $203 million in 2002 compared to income of $175 million in 2001. The overall decrease is primarily due to declines in equity in earnings of Brazilian large utility affiliates, including the impairment charge associated with the other than temporary decline in value of CEMIG in 2002.

Additionally, a share swap was completed during February 2002, which gave us control of Eletropaulo. In 2001, the Company recorded $134 million of equity in Eletropaulo's earnings; however, this amount decreased to $18 million due to consolidation of Eletropaulo's results subsequent to the share swap and the ongoing devaluation of the Brazilian Real. Equity in (losses) earnings of our large utilities included non-cash Brazilian foreign currency transaction losses of $83 million and $210 million during 2002 and 2001, respectively, due to the devaluation of the Brazilian Real during both periods.

Equity in (losses) earnings of growth distribution affiliates improved from a loss of $14 million in 2001 to $0 in 2002. The improvement is primarily due to a change in accounting for our investment in CESCO, a distribution facility in India.

Equity in earnings of contract generation affiliates increased to $75 million in 2002 from $54 million in 2001. The increase is due primarily to contributions from several Chinese equity affiliates and from Elsta offset by a decrease from OPGC.

Equity in earnings of competitive supply affiliates improved from a loss of $9 million in 2001 to a loss of $3 million in 2002. The improvement is primarily due to the sale of Infovias, a Brazilian company, during the second quarter of 2002.

Loss on sale of investments and asset impairment expense decreased to a loss of $201 million in 2003 compared to a loss of $473 million in 2002 primarily from fewer impairment charges being taken in 2003.

In December 2003, we sold an approximate 39% ownership interest in AES Oasis Limited ("AES Oasis") for cash proceeds of approximately $150 million. The loss realized on the transaction was approximately $36 million before income taxes. AES Oasis is an entity that owns an electric generation project in Oman (AES Barka) and two oil-fired generating facilities in Pakistan (AES Lal Pir and AES Pak Gen). AES Barka, AES Lal Pir, and AES Pak Gen are all contract generation businesses.

During the fourth quarter of 2003, we decided to discontinue the development of Zeg, a contract generation plant under construction in Poland. In connection with this decision, we wrote-off our investment in Zeg of approximately $23 million before income taxes.

On August 8, 2003, we decided to discontinue the construction and development of AES Nile Power in Uganda ("Bujagali"). In connection with this decision, we wrote-off our investment in Bujagali of approximately $76 million before income taxes in the third quarter of 2003. We are also working in conjunction with the Government of Uganda, the World Bank and the International Finance Corporation ("IFC") to evaluate ways to ensure an orderly transition for the project to continue without our participation.

In 1999 we initiated a development project in Honduras which consisted of a 580-MW combined-cycle power plant fueled by natural gas; a liquefied natural gas import terminal with storage capacity of one million barrels; and transmission lines and line upgrades (together "El Faro" or "the Project"). During April 2003, after consideration of existing business conditions and future opportunities, we elected to offer the Project for sale. While discussions have been ongoing, no formal agreements have been reached thus far. Upon review of the current circumstances surrounding the Project, we believe that, in accordance with Statement of Financial Accounting Standards No. 144,the Project is deemed to be impaired since the carrying amount of our investment in the Project exceeds its fair value. As a result during the second quarter of 2003, we wrote off capitalized costs of approximately $20 million associated with the Project. See Note 23—Subsequent Events.

Additionally, during 2003, we recorded $16 million of other losses which resulted from the sale of assets to third parties, and $29 million of other asset impairment charges taken to reflect the net realizable value of discontinued development projects and other non-recoverable assets.

(Loss) gain on sale of investments and asset impairment expense changed from a gain of $18 million for 2001 to a loss of $473 million in 2002 primarily resulting from impairment charges taken in 2002.

In the fourth quarter of 2002, we decided not to provide any further funding to Lake Worth and to sell the project. Subsequently the project entered into bankruptcy. As a result, the carrying amount of AES's investment in the Lake Worth project is not expected to be recovered. Therefore, in accordance with SFAS No. 144, a pre-tax impairment charge of $78 million was recorded to write-down the net assets of Lake Worth to their fair market value.

In September 2002, AES Greystone, L.L.C. and its subsidiary Haywood Power I, L.L.C., sold the Greystone gas-fired peaker assets then under construction in Tennessee to Tenaska Power Equipment for $36 million including cash and assumption of certain obligations. With this sale, AES and its subsidiaries have eliminated any future capital expenditures related to the facility, and also settled all major outstanding obligations with parties involved in this project. We recorded a loss of approximately $168 million associated with this sale. Greystone was previously recorded as a competitive supply business.

Additionally, during 2002, we recorded $116 million of other losses which resulted from the sale of assets to third parties, and $111 million of other asset impairment charges taken to reflect the net realizable value of discontinued development projects and other non-recoverable assets.

During 2003, we recorded a goodwill impairment charge of $11 million primarily related to all of the goodwill at Atlantis in the Caribbean. We recognize the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed as goodwill. We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. Our annual

impairment testing date is October 1^st. As of January 1, 2002, goodwill is no longer amortized in accordance with SFAS 142.

During 2002, we recorded a goodwill impairment charge of $612 million primarily related to all of the goodwill at Eletropaulo in Brazil. We recognize the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed as goodwill. We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. Our annual impairment testing date is October 1^st.

Prior to January 1, 2002, we amortized goodwill on a straight-line basis over the estimated benefit period, which ranged from 10 to 40 years. Total accumulated amortization amounted to $190 million at December 31, 2001.

Income tax expense (including income taxes on equity in earnings and minority interest) on continuing operations decreased from $285 million in 2002 to $194 million in 2003. The effective tax rate decreased from (21)% in 2002 (we had a tax expense on a loss from continuing operations) to 30% in 2003. The reduction in the 2003 effective tax rate is due, in part, to a reduction in the taxes on our foreign earnings. In addition, the 2002 effective tax rate is not in line with our historic effective tax rate trend as it was the result of significant book write offs that were not deductible for tax purposes.

The 2002 income tax expense (including income taxes on equity in earnings and minority interest) on continuing operations decreased to $285 million from $310 million in 2001. The 2002 effective tax rate increased to (21)% (we had a tax expense on a loss from continuing operations) from 38% in 2001. The reason for this increase was primarily the result of significant book write offs that were not deductible for tax purposes.

Loss from operations of discontinued businesses, net of tax, were $780 million in 2003 and $1,554 million in 2002. During 2003, we discontinued certain of our operations including Haripur, Meghnaghat, Barry, Telasi, Mtkvari, Khrami, Drax, Whitefield, AES Communications Bolivia, Granite Ridge, Ede Este, Wolf Hollow and Colombia I. We closed the sale of Barry in September 2003, Telasi, Mtkvari and Khrami in August 2003 and Haripur and Meghnaghat in December 2003.

Loss from operations of discontinued businesses, net of tax, were $1,554 million and $133 million, respectively, in 2002 and 2001. During 2002, we discontinued certain of our operations including Fifoots, CILCORP, NewEnergy, Eletronet, Mt. Stuart, Ecogen, two Altai businesses, Mountainview and Kelvin. We closed the sale of both CILCORP and Mt. Stuart in January 2003 and the sale of Ecogen in February 2003. During 2001, we discontinued certain of its operations, including Power Direct, Ib Valley, Power Northern, Geoutilities, TermoCandelaria and several telecommunications businesses in the United States and Brazil. All of the operations for these businesses and the related write offs from dispositions in 2002 and 2001 are reported in this line item.

On October 1, 2003, we adopted Derivative Implementation Group ("DIG") Issue C-20 which superceded and clarified DIG Issue C-11 regarding the treatment of power sales contracts. As a result of this adoption, we had a Power Purchase Agreement ("PPA") that was previously treated as a "normal sales and purchase contract" that is now being recorded prospectively at fair value; and treated as a derivative instrument under SFAS No. 133. The prospective method of accounting for this PPA requires no further mark-to-market treatment, and will be subsequently amortized over the life of

the contract. The adoption of DIG Issue C-20, effective October 1, 2003 results in a cumulative increase to income of $43 million, net of income tax effects.

On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" which requires companies to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The items that are part of the scope of SFAS 143 for our business primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. The adoption of SFAS No. 143 resulted in a cumulative reduction to income of $2 million, net of income tax effects.

On April 1, 2002, we adopted Derivative Implementation Group ("DIG") Issue C-15 which established specific guidelines for certain contracts to be considered normal purchases and normal sales contracts under SFAS No. 133. As a result of this adoption, we had two contracts which no longer qualified as normal purchases and normal sales contracts and were required to be treated as derivative instruments under SFAS No. 133. The adoption of DIG Issue C-15, effective April 1, 2002, resulted in a cumulative increase to income of $127 million, net of income tax effects.

Effective January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible Assets" which establishes accounting and reporting standards for goodwill and other intangible assets. The adoption of SFAS No. 142 resulted in a cumulative reduction to income of $473 million, net of income tax effects. SFAS No. 142 adopts a fair value model for evaluating impairment of goodwill in place of the recoverability model used previously. We wrote-off the goodwill associated with certain acquisitions where the current fair market value of such businesses is less than the current carrying value of the business, primarily as a result of reductions in fair value associated with lower than expected growth in electricity consumption compared to the original estimates made at the date of acquisition. Our annual impairment testing date is October 1^st.

We are a holding company that conducts all of our operations through subsidiaries. We have, to the extent achievable, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. This type of financing is non-recourse to other subsidiaries and affiliates and to us (as parent company), and is generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. At December 31, 2003, we had $5.9 billion of recourse debt and $13.7 billion of non-recourse debt outstanding. For more information on our long-term debt see Note 9 of our consolidated financial statements.

In addition to the non-recourse debt, if available, we, as the parent company, provide 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. We generally obtain the funds for these investments from our cash flows from operations and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, we 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 our subsidiaries. In such circumstances, if a subsidiary defaults on its payment or supply obligation, we will be responsible for the subsidiary's obligations up to the amount provided for in the relevant guarantee or other credit support.

We intend to continue to seek where possible non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. However, depending on market conditions and the unique characteristics of individual businesses, non-recourse debt may not be

available or available on economically attractive terms. If we decide not to provide any additional funding or credit support to a subsidiary that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent and we may lose our investment in such subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to restructure the non-recourse debt financing. If such subsidiary is unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in such subsidiary.

As a result of our below-investment-grade rating of the parent, counter-parties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, we may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. We may not be able to provide adequate assurances to such counter-parties. In addition, to the extent we are required and able to provide letters of credit or other collateral to such counter-parties, this will reduce the amount of credit available to us to meet our other liquidity needs. At December 31, 2003, we had provided outstanding financial and performance related guarantees or other credit support commitments to or for the benefit of our subsidiaries, which were limited by the terms of the agreements, in an aggregate of approximately $515 million (excluding those collateralized by letters of credit and other obligations discussed below). We also are obligated under other commitments pursuant to which our obligations are limited to the amount, or a specified percentage of the amount, of distributions that we receive from our projects subsidiaries. In addition, we have commitments of $38 million to fund our equity in projects currently under development or in construction.

At December 31, 2003, we had $89 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. Of these letters of credit, $70 million were provided under our revolver. We pay letter of credit fees ranging from 0.5% to 5.0% per annum on the outstanding amounts. In addition, we had $4 million in surety bonds outstanding at December 31, 2003.

At December 31, 2003, we had a consolidated net working capital deficit of $1.6 billion compared to a net working capital deficit of $2.1 billion at the end of 2002. The improvement in net working capital is due to increased cash, increased net accounts receivable and reduced current portion of long-term debt. This is partially offset by a decrease in other current assets and the current assets of discontinued operations, and an increase in accounts payable and accrued interest. We had unrestricted cash and short-term investments of $1.9 billion at December 31, 2003. Included in the net working capital deficit is approximately $2.8 billion from the current portion of long-term debt, of which $2.3 billion is due to project level defaults. We expect to refinance a significant amount of the current portion of long-term debt in 2004. We can provide no guarantee that the refinanced debt will have terms as favorable as our debt currently in existence. Some of our subsidiaries issue short-term debt and commercial paper in the normal course of business and continually refinance these obligations.

Property, plant and equipment, net of accumulated depreciation, accounts for 62% of our total assets and was $18.5 billion at December 31, 2003. Net property, plant and equipment increased $1 billion, or 6%, during 2003. The increase was due primarily to construction activity during 2003.

We continuously monitor actual and potential changes to environmental regulations and plans for the associated costs. As a result, we expect to spend approximately $94 million in 2004 to comply with environmental laws and regulations and to raise our level of preparedness for future regulations that may be enacted. However, changes in environmental laws may require us to incur significant expenses that could exceed our estimates. We expect to obtain third party financing for a portion of these capital expenditures. In 2004 we plan to make capital expenditures for construction costs associated with new

environmental standards imposed by the EPA relating to NOx emission reductions, the installation of low NOx burners, additional monitoring equipment, and other environmental-related projects.

In total, our consolidated debt decreased by $464 million, or 2%, to $19.6 billion at December 31, 2003. The decrease is primarily due to scheduled amortization payments, optional debt redemptions, and the sale of certain businesses and the reclassification of certain businesses to discontinued operations.

At December 31, 2003, we had $1.7 billion of cash and cash equivalents representing an increase of $945 million from December 31, 2002. The $1.6 billion of cash provided by operating activities was used to fund the $383 and $353 million of Investing and Financing activities, respectively.

The increase in cash flows provided by operating activities totaled $1.6 billion during 2003, which is primarily due to an improvement in working capital. Net cash used in investing activities totaled $383 million during 2003. The cash used in investing activities includes $1.2 billion for property additions, proceeds from asset sales of $1.1 billion, and other cash outflows of $241 million. Net cash provided by financing activities was $353 million during 2003, which primarily consists of refinancing and principal payments cash outflow of $690 million offset by proceeds from issuance of stock $337 million.

Because of the non-recourse nature of most of our indebtedness, we believe that unconsolidated parent company liquidity is an important measure of liquidity. Our principal sources of liquidity at the parent company level are:

Our cash requirements at the parent company level through the end of 2004 are primarily to fund:

During 2002 and 2003, we undertook numerous actions designed to increase parent liquidity, lengthen parent debt maturities, and reduce parent debt and other contractual obligations, both contingent and non-contingent. These actions are consistent with our strategic goals of improving the credit profile of both the parent and the consolidated company in order to reduce our financial risk and improve our credit rating by the major rating agencies. As a result of these actions, our parent liquidity at year-end 2003 improved substantially compared to our parent company liquidity at year-end 2002. Our parent recourse debt was $5.9 billion at year-end 2003 compared with $6.8 billion at year-end 2002. Our contingent contractual obligations were $608 million at year-end 2003 compared with $871 million at year-end 2002.

The primary actions we undertook in 2003 to achieve these goals included: (i) selling assets, (ii) issuing common stock, (iii) refinancing parent company debt to mature at later maturity dates, and (iv) redeeming parent debt and other contractual obligations.

Our non-contingent contractual obligations at the parent company level are set forth below:

We also reduced our contingent contractual obligations at the parent company level to $608 million at year-end 2003, compared with $871 million at year-end 2002. Our contingent contractual obligations at

the parent company at year-end 2003 are set forth below (in millions, except for number of agreements):

We have a varied portfolio of performance related contingent contractual obligations. Amounts related to the balance sheet items represent credit enhancements made by us at the parent company level and by other third parties for the benefit of the lenders associated with the non-recourse debt recorded as liabilities in the accompanying consolidated balance sheets. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power sales agreements for projects in development, under construction and operating. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2004 or beyond that are not recorded on the balance sheet, many of the events which would give rise to such an obligation are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

While we believe that our sources of liquidity will be adequate to meet our needs through the end of 2004, this belief is based on a number of material assumptions, including, without limitation, assumptions about exchange rates, power market pool prices, the ability of our subsidiaries to pay dividends and the timing and amount of asset sale proceeds. In addition, our project subsidiaries' ability to declare and pay cash dividends to us (at the parent company level) is subject to certain limitations contained in project loans, governmental provisions and other agreements to which our project subsidiaries are subject. We can provide no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the parent company level with a secured revolving credit facility of $350 million, which is part of our $1.6 billion senior secured credit facilities. We did not have any outstanding borrowings under the revolving credit facility at December 31, 2003. We had $228 million of borrowings outstanding under the revolving credit facility as of December 31, 2002. At December 31, 2003, we had $70 million of letters of credit outstanding under the revolving and letters of credit outstanding outside the revolver amounted to $19 million. At December 31, 2002, we had $104 million of letters of credit outstanding under the revolver and letters of credit outstanding outside the revolver amounted to $109 million.

Various debt instruments at the parent company level, including our senior secured credit facilities, senior secured notes and senior subordinated notes contain certain restrictive covenants. The covenants provide for, among other items:

Our senior secured notes due 2005 are subject to mandatory redemption provisions including provisions that require us, on November 25, 2004, to redeem 40% of the aggregate principal amount of the approximately $258 million aggregate principal amount of senior secured notes issued on December 13, 2003 to the extent not previously redeemed (at our option or pursuant to the other mandatory redemption provisions), at a price equal to 100% of the principal amount of the senior secured notes to be redeemed plus accrued and unpaid interest. As of December 31, 2003, approximately $232 million aggregate principal amount of senior secured notes were outstanding.

While the lenders under our non-recourse debt financings generally do not have direct recourse to the parent company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:

Certain of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in the accompanying consolidated balance sheets related to such defaults was $2.3 billion at December 31, 2003, of which approximately $0.6 billion is held at discontinued operations and businesses held for sale.

None of the subsidiaries referred to above that are currently in default are owned by subsidiaries that currently meet the applicable definition of materiality in AES's corporate debt agreements in order for such defaults to trigger an event of default or permit an acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations, it is possible that one or more of these subsidiaries could fall within the definition of a "material subsidiary" and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the AES parent company's senior notes, senior subordinated notes and junior subordinated notes.

In May 1999, one of our subsidiaries acquired six electric generating plants from New York State Electric and Gas. Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. We have accounted for this transaction as a sale/leaseback transaction with operating lease treatment. Accordingly, we have not recorded these assets on our books and we expense periodic lease payments,

which amounted to $54 million in 2003, as incurred. The lease obligations bear an imputed interest rate of approximately 9% which approximates fair market value. We are not subject to any additional liabilities or contingencies if the arrangement terminates, and we believe that the dissolution of the off-balance sheet arrangement would have minimal effects on our operating cash flows. The terms of the lease include restrictive covenants such as the maintenance of certain coverage ratios. As of December 31, 2003, we fulfilled a lease requirement on the subsidiary's behalf by funding an additional liquidity account, as defined in the lease agreement, in the form of a $36 million letter of credit. However, the subsidiary is required to replenish or replace this letter of credit in the event it is drawn upon or requires replacement. Historically, the plants have satisfied the restrictive covenants of the lease, and there are no known trends or uncertainties that would indicate that the lease will be terminated early. See Note 11 to our consolidated financial statements for a more complete discussion of this transaction.

In 1996, IPL, one of our subsidiaries, formed IPL Funding Corporation ("IPL Funding") to purchase, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL in exchange for a note payable. IPL Funding is not consolidated by IPL or IPALCO since it meets requirements set forth in SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" to be considered a qualified special-purpose entity. IPL Funding has entered into a purchase facility with unrelated parties, whom we refer to as the purchasers. Under the purchase facility, the purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million of the receivables purchased from IPL. As of December 31, 2003, the aggregate amount of receivables purchased pursuant to this facility was $50 million. The net cash flows between IPL and IPL Funding are limited to cash payments made by IPL to IPL Funding for interest charges and processing fees. These payments totaled approximately $1 million for the year ended December 31, 2003, $1.1 million for the year ended December 31, 2002 and $2.3 million for the year ended December 31, 2001. IPL retains servicing responsibilities through its role as a collection agent for the amounts due on the purchased receivables, but may be replaced as servicing agent if IPL fails to meet certain financial covenants regarding interest coverage and debt-to-capital. The transfers of such retail accounts receivable from IPL to IPL Funding are recorded as sales; however, no gain or loss is recorded on the sale. See Note 9 to our consolidated financial statements for additional discussion about this arrangement.

We have investments in several equity method affiliates including CEMIG in Brazil, and do not consolidate the financial information of these equity method affiliates. Therefore, none of the assets or liabilities of our equity method affiliates are included on our consolidated balance sheets. See Note 7 to our consolidated financial statements for summarized financial information from our equity method affiliates.

A summary of the Company's contractual obligations and commitments as of December 31, 2003 is presented in the table below. Purchase "Take-or-Pay" obligations represent specified minimum payment amounts committed under legally enforceable contracts or purchase orders for fuel or electricity.

In addition to the contractual obligations noted above, some of our subsidiaries have various standing or renewable contracts with vendors. These contracts are cancelable with immaterial or no cancellation penalties.

Certain statements contained in this Form 10-K are forward-looking statements as that term is defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements speak only as of the date hereof. Forward-looking statements can be identified by the use of forward-looking terminology such as "believe," "expects," "may," "intends," "will," "should" or "anticipates" or the negative forms or other variations of these terms or comparable terminology, or by discussions of strategy. The results described in forward-looking statements may not be achieved. Forward-looking statements are subject to risks, uncertainties and other factors, which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements.

We wish to caution readers that the following important factors, among others, relate to areas affecting us, which involve risk and uncertainty. You should consider these factors when reviewing our business. We rely on these factors when issuing any forward-looking statements. These factors could affect our actual results and cause our actual results to differ materially from our current expectations expressed in any forward-looking statements we make. Some or all of these factors may apply to our businesses as currently maintained or to be maintained.

We utilize derivative financial instruments to manage interest rate risk, foreign exchange risk and commodity price risk. Although the majority of our derivative instruments qualify for hedge accounting, our adoption of SFAS No. 133 in 2001 has resulted in more variation in our results of operations from changes in interest rates, foreign exchange rates and commodity prices. For the year ended December 31, 2003, we recognized $40 million of losses, net of income taxes, primarily related to derivatives which did not qualify for hedge accounting. See Note 10 to our consolidated financial statements for a more complete discussion of our accounting for derivatives.

We do not engage in significant energy trading activities associated with our retail and wholesale supply businesses. We recorded net gains from energy trading activities of $0 million in the years ended December 31, 2003 and 2002, and $5 million in the year ended December 31, 2001.

We did not enter into any related party transactions that were material for financial reporting purposes during the years ended December 31, 2003, 2002 and 2001.

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

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable-rate debt, fixed-rate debt 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, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.

We are 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 our consolidated reporting currency, the U.S. dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in U.S. dollars or currencies other than their own functional currencies. Primarily, we are exposed to changes in the U.S. dollar/United Kingdom Pound Sterling exchange rate, the U.S. dollar/Brazilian Real exchange rate, the U.S. dollar/Venezuelan Bolivar exchange rate and the U.S. dollar/Argentine peso 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. We also use foreign currency forward and swap agreements, where possible, to manage our risk related to certain foreign currency fluctuations.

We are exposed to the impact of market fluctuations in the price of electricity, natural gas and coal. Although we primarily consist of businesses with long-term contracts or retail sales concessions, a portion of our current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These competitive supply businesses subject our results of operations to the volatility of electricity, coal and natural gas prices in competitive markets. Our 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 as well as long-term supply contracts for the supply of fuel and electricity.

In 2000, we adopted a value at risk ("VaR") approach to assess and manage our risk and our subsidiaries' risk. VaR measures the potential loss in a portfolio's value due to market volatility, over a specified time horizon, stated with a specific degree of probability. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. We adopted the VaR approach because we feel that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of our risk exposure. Our 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.

Our use of VaR allows us to aggregate risks across all of our 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 analytic VaR, in particular the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform stress and scenario analyses to estimate the economic impact of market changes on the value of our portfolios. We use these results to supplement the VaR methodology.

We have performed a company-wide VaR analysis of all of our material financial assets, liabilities and derivative instruments. The VaR calculation incorporates numerous variables that could impact the fair value of our instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. We perform our interest rate and foreign exchange analysis using VaRworks, a Financial Engineering Associates, Inc. risk management application, which utilizes three methods of VaR calculations; Analytic VaR, Monte Carlo Simulation and Historical Simulation. We express Analytic VaR herein 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 commodity analysis is an Analytic VaR utilizing a variance-covariance analysis within the commodity transaction management system.

During the year ended December 31, 2003, our average daily VaR for interest rate-sensitive instruments was $99.1 million. The daily VaR for interest rate- sensitive instruments was highest at the end of the third quarter, and equaled $126.9 million. The daily VaR for interest rate-sensitive instruments was lowest at the end of the second quarter, and equaled $82.2 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items.

During the year ended December 31, 2003, our average daily VaR for foreign exchange rate-sensitive instruments was $34.1 million. The daily VaR for foreign exchange rate-sensitive instruments was highest at the end of the first quarter, and equaled $44.1 million. The daily VaR for foreign exchange rate-sensitive instruments was lowest at the end of the fourth quarter, and equaled $19.7 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items.

During the year ended December 31, 2003, our average daily VaR for commodity price-sensitive instruments was $5.48 million. The daily VaR for commodity price-sensitive instruments was highest at the end of the second quarter, and equaled $6.76 million. The daily VaR for commodity price-sensitive instruments was lowest at the end of the third quarter, and equaled $4.0 million. These amounts include the financial instruments that serve as hedges and do not include the underlying physical assets or contracts that are not permitted to be settled in cash.

We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of operations, changes in stockholders' equity (deficit), and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedules on pages S-1 to S-7 of the Company's annual report on Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company'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, 2001, which statements reflect total revenues constituting 13% of consolidated total revenues and total income from continuing operations constituting 55% of consolidated total income from continuing operations for 2001. Those statements were audited by other auditors who have ceased operations and 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, and the report of the other auditors, provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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.

As discussed in Note 1 to the financial statements, in 2003 the Company changed its method of accounting for special purpose entities to conform to FASB Interpretation No. 46, Consolidation of Variable Interest Entities, and, retroactively, restated the 2002 financial statements for the change.

As discussed in Note 1 to the financial statements, the Company changed its method of accounting for a certain contract for the sale of electricity effective October 1, 2003 to conform to Derivative Implementation Group Issue C-20. Also, as discussed in Note 1 to the financial statements, the Company changed its method of accounting for certain contracts for the sale of electricity effective April 1, 2002 to conform to Derivative Implementation Group Issue C-15. As discussed in Note 1 to the financial statements, the Company changed its method of accounting for stock-based compensation effective January 1, 2003, to conform to the fair value recognition provision of Statement of Financial Accounting Standard No. 123, as amended by Statement of Financial Accounting Standard No. 148, prospectively to all employee awards granted, modified or settled after January 1, 2003. As discussed in Note 1 to the financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003 to conform to Statement of Financial Accounting Standard No. 143. As discussed in Note 6 to the financial statements, the Company changed its method of accounting for goodwill and other intangible assets effective January 1, 2002 to conform to Statement of Financial Accounting Standard No. 142. As discussed in Note 10 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001 to conform to Statement of Financial Accounting Standard No. 133.

Due to the Company's inability to obtain an accountants' report from Porta, Cachafeiro, Laría Y Asociados (a Member Firm of Andersen), we have included this copy of their latest signed and dated accountants' report on the financial position and results of operations of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their subsidiaries as of December 31, 2001 and 2000, the results of their operations and their cash flows for the year ended December 31, 2001, and the results of their operations and cash flows for the period from June 1 through December 31, 2000. This report is a copy of the original and has not been reissued by Porta, Cachafeiro, Laría Y Asociados. Porta, Cachafeiro, Laría Y Asociados has not provided a consent to the inclusion of its report in this Form 10-K. See Exhibit 23.2 for additional information regarding our inability to obtain this consent and the limitations imposed on investors as a result.

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

We have audited the accompanying combined balance sheets of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries (Venezuelan corporations), translated into U.S. dollars, as of December 31, 2001 and 2000, and the related translated combined statements of income, stockholders' investment and cash flows for the year ended December 31, 2001 and 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 audits.

We conducted our audits 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 as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

These translated combined financial statements have been prepared for use in the preparation of the consolidated financial statements of AES Corporation and, accordingly, they translate the assets, liabilities, stockholders' investment, revenues and expenses of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries for that purpose. The translated combined 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 Corporación EDC, C.A. and their Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the year ended December 31, 2001 and for the period from June 1 through December 31, 2000, in conformity with accounting principles generally accepted in the United States.

Caracas, Venezuela
January 18, 2002 (except with respect
to the matter discussed in Note 18, as
to which the dates are February 20, 2002)

THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2003, 2002 AND 2001

The AES Corporation is a holding company that, through its subsidiaries and affiliates, (collectively, "AES" or "the Company," "us" or "we") is a global power company primarily engaged in owning and operating electric power generation and distribution businesses in many countries around the world. The revenues and cost of sales of our large utilities and growth distribution segments are reported as regulated, and the revenues and cost of sales of our contract generation and competitive supply segments are reported as non-regulated.

The consolidated financial statements have been prepared to give retroactive effect to the merger with IPALCO Enterprises, Inc. ("IPALCO"), which has been accounted for as a pooling of interests as more fully discussed in Note 3.

PRINCIPLES OF CONSOLIDATION—The consolidated financial statements of the Company include the accounts of The AES Corporation, its subsidiaries, and controlled affiliates. Investments, in 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. A loss in value of an equity method investment which is other than a temporary decline is recognized in earnings as an impairment.

As of December 31, 2003, the Company adopted and applied FASB Interpretation No. 46, Consolidation of Variable Interest Entities, ("FIN 46"), which addresses the consolidation of "variable interest entities" ("VIEs"), to its special-purpose entities. If an entity is determined to be a VIE, it must be consolidated by the enterprise that absorbs the majority of the entity's expected losses if they occur or receives a majority of the entity's expected residual returns if they occur. Application of FIN 46 as of December 31, 2003 has resulted in the special purpose business trusts that issued Term Convertible Preferred Securities no longer being consolidated (see Note 9). The Company has elected to restate the related amounts as of December 31, 2002 for the effects of adopting FIN 46. As of December 31, 2003, the Company had not adopted FIN46(R) (see Note 22).

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. Debt service reserves and other deposits are treated as non-current assets (see Note 8).

INVENTORY—Inventory, valued at the lower of cost or market (first in, first out method) consists of the following (in millions):

	December 31,
	2003			2002
Coal, fuel oil, and other raw materials	$	171		$	281
Spare parts and supplies		225			217

Total		396			498
Less: Inventory of discontinued operations		(20	)		(145	)

	$	376		$	353

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 and asset retirement obligations, 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, 3.60%, 4.00% and 3.68% for the years ended December 31, 2003, 2002 and 2001, 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 during the construction period. 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 $115 million, $234 million, and $280 million in 2003, 2002, and 2001, respectively. These amounts exclude $0 million, $53 million, and $3 million of capitalized interest related to discontinued operations for the years ended 2003, 2002, and 2001, respectively. Recoveries of liquidating damages from construction delays are recorded as a reduction in the related projects' construction costs.

GOODWILL—The Company recognizes as goodwill the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill for impairment on an annual basis and whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company's annual impairment testing date is October 1^st. Prior to January 1, 2002, goodwill was amortized on a straight-line basis over the estimated benefit period, which ranged from 10 to 40 years. As of January 1, 2002, goodwill is no longer amortized (see Note 6).

LONG-LIVED ASSETS—In accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets," the Company evaluates the

impairment of long-lived assets 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 5).

ASSET RETIREMENT OBLIGATIONS—Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the Company to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When a new liability is recorded the Company will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

The Company's retirement obligations covered by SFAS No. 143 include primarily active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. As of December 31, 2003 and 2002, the Company had recorded liabilities of approximately $29 million and $15 million, respectively, related to asset retirement obligations. There are no assets that are legally restricted for purposes of settling asset retirement obligations. Upon adoption of SFAS No. 143, the Company recorded an additional liability of approximately $13 million, a net asset of approximately $9 million, and a cumulative effect of a change in accounting principle of approximately $2 million, after income taxes. Amounts recorded related to asset retirement obligations during the years ended December 31, 2003 were as follows (in millions):

Balance at December 31, 2002	$	15
Additional liability recorded from cumulative effect of accounting change		13
Accretion expense		2
Change in the timing of estimated cash flows		(1	)

Balance at December 31, 2003	$	29

Proforma net (loss) income and (loss) earnings per share have not been presented for the years ended December 31, 2002 and 2001 because the proforma application of SFAS No. 143 to prior periods would result in proforma net (loss) income and (loss) earnings per share not materially different from the actual amounts reported for those periods in the accompanying consolidated statements of operations. Had SFAS 143 been applied during all periods presented the asset retirement obligation at January 1, 2001, December 31, 2001 and December 31, 2002 would have been approximately $21 million, $23 million and $28 million, respectively.

Included in other long-term liabilities is the accrual for the non-legal obligations for removal of assets in service at IPALCO amounting to $361 million and $339 million at December 31, 2003 and 2002, respectively.

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 $202 million and $173 million as of December 31, 2003 and 2002, respectively.

PROJECT DEVELOPMENT COSTS—The Company capitalizes the costs of developing new construction projects after achieving certain project-related milestones that indicate the project's completion is probable. These costs represent amounts incurred for professional services, permits, options, capitalized interest, and other costs directly related to construction. These costs are transferred to construction in progress when significant construction activity commences, or expensed at the time the Company determines that development of a particular project is no longer probable (see Note 5).

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.

GUARANTOR ACCOUNTING—The Company adopted the disclosure provisions of FASB Interpretation No. ("FIN") 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others," in the fourth quarter of 2002. Effective January 1, 2003, the Company began applying the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. Under FIN 45, at the inception of a guarantee, the Company will record the fair value of the guarantee as a liability, with the offsetting entry being recorded based on the circumstances in which the guarantee was issued.

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. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.

FOREIGN CURRENCY TRANSLATION—A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. 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 translation differences that result from this process, and gains and losses on intercompany 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 are included in determining net income. For subsidiaries operating in highly inflationary economies, the U.S. dollar is considered to be the functional currency.

In January and February 2002, many new economic measures were adopted by the Argentine government, including abandonment of the country's fixed dollar-to-peso exchange rate, converting U.S. dollar denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government also adopted new regulations in the energy sector that have the effect of repealing U.S. dollar denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos. Due to the changes, the Company changed the functional currency for its businesses in Argentina to the peso effective January 1, 2002.

EARLY EXTINGUISHMENT OF DEBT—During the second quarter of 2002, the Company adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Among other items, this Statement rescinds FASB Statement No. 4, "Reporting Gains and Losses from Extinguishments of Debt." As a result, early extinguishments of debt are no longer reported as extraordinary items but are included in income from continuing operations.

For the year ended December 31, 2003, the Company extinguished debt with a face value of approximately $2.4 billion for approximately $2.2 billion in cash, resulting in a gain of approximately $0.2 billion which is recorded in other income in the accompanying consolidated statement of operations. See Note 15 for details of debt extinguished by issuance of shares. There were no early extinguishments of debt during 2001.

EXIT OR DISPOSAL ACTIVITIES—In June 2002, the Financial Accounting Standards Board issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses financial accounting and reporting for costs associated with exit or disposal activities. This Statement requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Prior to issuance of SFAS No. 146, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. The provisions of this Statement were effective for exit or disposal activities that are initiated after December 31, 2002.

REVENUE RECOGNITION AND CONCENTRATION—Electricity distribution revenues are reported as regulated. Revenues from the sale of energy are recognized in the period during which the sale occurs. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the average price per customer class for that month. Revenues from the sale of electricity and steam generation are reported as non-regulated and are recorded based upon output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. Revenues from power sales contracts entered into after 1991 with decreasing 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 13). No single customer accounted for 10% or more of revenues in 2003, 2002 or 2001. 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.

Within our regulated businesses, sales of purchased power amounted to approximately $2.9 billion, $2.6 billion and $1.2 billion for the years ended December 31, 2003, 2002 and 2001, respectively. The related power purchased by the regulated businesses amounted to approximately $2.0 billion, $1.7 billion and $693 million for the years ended December 31, 2003, 2002 and 2001, respectively. Our non-regulated businesses consist primarily of generation businesses, and therefore, do not generally purchase power for resale.

REGULATION—The Company has investments in large utilities and growth distribution businesses located in the United States and certain foreign countries that are subject to regulation by the applicable regulatory authority. Our distribution businesses generally operate in markets that are subject to electricity price regulation as compared with regulation based solely on the cost of the electricity or the allowed rate of return on a specific distribution company's assets or net assets. 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 tariff set by the regulator or as permitted under the electricity sales concession for that business. The deferred regulatory asset is eliminated when the Company collects the related costs through billings to customers, or when recovery is no longer probable. 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. This accounting reflects the economic effects of regulation by matching expenses with their recovery through regulated revenues. The Company has recorded deferred regulatory assets of $741 million and $627 million at December 31, 2003, and 2002, respectively (excluding tax-related regulatory assets at IPALCO—see Note 2), that it expects to pass through to its customers in accordance with and subject to regulatory provisions. These amounts include $29 million and $105 million of assets classified as discontinued operations at December 31, 2003 and 2002, respectively. 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 does not enter into derivative transactions for trading

purposes. All derivative transactions are accounted for under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended and interpreted. SFAS No. 133 requires that an entity recognize all derivatives that are not exempted (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. If a derivative qualifies for the normal purchases and sales exemption, the Company generally has elected not to account for such instruments as derivatives.

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 accumulated 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. If a cash flow hedge is terminated because it is probable that the hedged transaction or forecasted transaction will not occur, the related balance in other comprehensive income as of such date is immediately recognized. If a cash flow hedge is terminated early for other reasons, the related balance in other comprehensive income as of the termination date is recognized concurrently with the related hedged transaction.

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 at fair value. The majority of these transactions are accounted for as cash flow hedges.

The Company enters into currency swaps and forwards to hedge against foreign currency risk on certain non-functional currency-denominated liabilities. These transactions are accounted for at fair value. A portion of these transactions are accounted for as either fair value hedges or cash flow hedges.

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. These transactions are accounted for at fair value. The majority of these transactions are accounted for as cash flow hedges, and as such, 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.

Derivative fair values are reflected at quoted or estimated market value. The values are adjusted to reflect the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions. In the absence of quoted market prices, other valuation techniques to estimate fair value are utilized. The use of these techniques requires the Company to make estimations of future prices and other variables, including market volatility, price correlation, and market liquidity.

On April 1, 2002 Derivatives Implementation Group ("DIG") Issue C-15, related to contracts involving the purchase or sale of electricity became effective. Contracts for the purchase or sale of electricity, both forward and option contracts, including capacity contracts, may qualify for the normal purchases and sales exemption and are not required to be accounted for as derivatives under SFAS No. 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. However, contracts that have a price based on an underlying index that

is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS No. 133.

The Company has two contracts that previously qualified for the normal purchases and normal sales exemption of SFAS No. 133, but no longer qualify for this exemption due to the effectiveness of DIG Issue C-15 on April 1, 2002. Accordingly, these contracts were required to be accounted for as derivatives at fair value. The contracts were valued as of April 1, 2002, and an asset and a corresponding gain of $127 million, net of income taxes, was recorded as a cumulative effect of a change in accounting principle. The contract valuations were performed using current forward electricity and gas price quotes and current market data for other contract variables. The forward curves used to value the contracts include certain assumptions, including projections of future electricity and gas prices in periods where future prices are not quoted.

In June 2003, the FASB issued DIG Issue C-20, that superceded DIG Issue C-11 and provided additional guidance related to the impact of certain price adjustment features on the ability of a contract to qualify for the normal purchases and sales exemption. In order for contracts to qualify for the exemption, they must first meet certain criteria. The criteria includes requirements that the underlying price adjustment may not be considered extraneous and that the magnitude and direction of the impact of the price adjustment is consistent with the relevancy of the underlying. Additionally, there are restrictions on certain contracts with an underlying associated with currency exchange rates qualifying for the exemption. Under the transition provisions of DIG Issue C-20 the Company was required to record a cumulative effect of change in accounting principle adjustment of $43 million, net of income taxes on October 1, 2003 for the fair value of a power sales contract. This contract subsequently qualified for the normal purchases and sales exemption and the contract's carrying value is being amortized on a straight-line basis over the remaining life of the contract.

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 16). 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 the if-converted method, as applicable.

USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant items subject to such estimates and assumptions include the carrying value and estimated useful lives of long-lived assets; impairment of goodwill and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of deferred regulatory assets and the valuation of certain financial instruments, pension liabilities, environmental liabilities and potential litigation claims and settlements (see Note 12).

STOCK OPTIONS—As of January 1, 2003 the Company had three stock-based compensation plans. Prior to 2003, the Company accounted for those plans under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. No stock-based employee compensation cost is reflected in the net income (loss) for the years ended December 31, 2002 or 2001, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, the Company adopted the fair value recognition provision of SFAS No. 123, as amended by SFAS No. 148, prospectively to all employee awards granted, modified or settled after

January 1, 2003. Awards under the Company's plans generally vest over two years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for the year ended December 31, 2003, is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. However, if SFAS No. 123 had been applied to all grants since the original effective date the impact on net income would have been minimal since there were very few grants that would have had expense carried over to 2003. During the year ended December 31, 2003, the Company recorded compensation expense of approximately $7 million as a result of adopting the fair value recognition provisions of SFAS No. 123.

For SFAS No. 123 disclosure purposes, the weighted average fair value of each option grant has been estimated as of the date of grant primarily using the Black-Scholes option-pricing model with the following weighted average assumptions:

Using these assumptions, and an expected option life of approximately 10 years, the weighted average fair value of each stock option granted was $2.65, $1.98 and $14.87, for the years ended December 31, 2003, 2002 and 2001, respectively.

The following table illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period (in millions, except per share amounts):

RECLASSIFICATIONS—Certain reclassifications have been made to prior-period amounts to conform to the 2003 presentation.

BRAZIL—The Brazilian electricity industry is regulated by ANEEL, the Brazilian National Electric Energy Agency. The electricity industry in Brazil reached a critical point in 2001 as a result of a series of regulatory, meteorological and market driven problems. The Brazilian government implemented a program for the rationing of electricity consumption effective as of June 2001. In December 2001, an industry-wide agreement was reached with the Brazilian government that applies to Eletropaulo, Tiete,

CEMIG, and Sul. There were three parts of the agreement that specifically affected AES. The terms of the agreement were implemented during 2002.

Recovery of costs related to rationing. On a consolidated basis, AES had recorded accounts receivable of approximately $60 million related to regulatory provisions in effect during the Rationing Period. As a result of the settlement, the AES Brazilian subsidiaries were allowed to recover costs incurred associated with the rationing in lieu of recovering the receivables for approximately the same amount. As a result, the impact of the settlement was a reclassification from accounts receivable to regulatory assets. The regulator granted a specific tariff to allow for the cost recovery. The tariff will remain in effect for the lesser of 70 months or until all incurred costs are recovered. The Company believes that it will recover all deferred costs within this time period.

Recovery of Parcel A costs. Parcel A costs consist primarily of the costs of purchased power, transmission and certain taxes incurred by Brazilian distribution companies. Parcel A costs are permitted to be passed on to customers via tariff adjustments. The Brazilian regulator had granted tariff increases to recover a portion of previously deferred Parcel A costs. However, due to uncertainty surrounding the Brazilian economy, the regulator had delayed approval of some Parcel A tariff increases. As part of the agreement, a tracking account that was previously established was officially defined (see discussion of the Tracking Account). Parcel A costs incurred previous to January 1, 2001 were not allowed under the definition of the tracking account. As a result, in 2001, the Company wrote-off approximately $160 million ($101 million representing the Company's portion from equity affiliates), of Parcel A costs incurred prior to 2001 that will not be recovered. Tariff adjustments were implemented to allow recovery for these costs.

Sul. Under the third part of the agreement, AES's subsidiary Sul was permitted to record additional revenue and a corresponding receivable from sales to the Brazilian Wholesale Electricity Market (MAE) of energy purchased from the government owned Itaipu generation facility in 2001 and through May 2002. In May 2002, the regulator issued Order 288 as a retroactive regulatory decision that changed the methodology for recording the amount derived from sales to MAE. As a result, the Company recorded a pretax provision of approximately $160 million against revenues in May 2002 to reflect the negative impacts of this retroactive regulatory decision. Sul filed an injunction in October 2002, which was upheld in December 2002, forcing MAE to keep its original values and required MAE to place 50% of the amount claimed in escrow. The injunction was reversed in the beginning of February 2003. AES Sul continues to pursue judicial options to address this situation.

The MAE has settled its registered transactions for the period from late December 2002 through early 2003. Without considering the effect of Order 288, Sul owes approximately $28 million, based upon the December 31, 2003 exchange rate. Sul does not have sufficient funds to make this payment, and several creditors have filed lawsuits in an effort to collect amounts they claim are due. Sul is petitioning the courts to aggregate the individual lawsuits with the Order 288 actions filed by Sul in order to postpone payment until the matter is resolved. If Sul prevails and the MAE settlement occurs absent the effect of Order 288, Sul will receive approximately $121 million, based upon the December 31, 2003 exchange rate. If Sul is unsuccessful and if Sul is unable to pay any amount that may be due to MAE, penalties and fines could be imposed up to and including the termination of the concession contract by ANEEL. Sul is current on all MAE charges and costs incurred subsequent to the period in question in the Order 288 matter.

Tiete. The MAE settlement for AES's subsidiary Tiete for the period from September 2000 to December 2002 totals an obligation of approximately $80 million, at the December 31, 2003 exchange rate. Fifty percent of the amount was due on December 26, 2002, and the remainder was due July 3, 2003 after MAE's numbers were audited. According to the industry-wide agreement reached in

December 2001, Brazilian National Development Bank ("BNDES") was required to provide Tiete with a credit facility in the amount of approximately $41 million at the December 31, 2003 exchange rate to pay off a part of the liability. This credit facility has not yet been provided but in the meantime, a Brazilian federal court has granted Tiete a temporary injunction suspending the payment of the obligation until BNDES makes this credit facility available. As a result, Tiete paid MAE the difference from the total liability and the credit facility in the amount of approximately $39 million on July 3, 2003. In the absence of the BNDES credit facility, in January 2004 Tiete was able to close an agreement with 96.5% of creditors under the MAE settlement in order to coordinate payment of Tiete's MAE settlement liabilities with the same terms of the BNDES credit facility. Simultaneously, Tiete released from the injunction all creditors, ANEEL and MAE and will continue to have legal disputes with the creditors that did not participate in the agreement. Tiete has started to receive from the distribution companies the extraordinary tariff revenue in order to recover $50 million from the total loss in respect of the MAE, and the total recovery is expected to be completed over a six-year period. As of December 31, 2003, Tiete had collected approximately $3 million of extraordinary tariff revenue from the distribution companies.

Uruguaiana. The MAE settlement for the period from September 2000 to December 2002 for Uruguaiana totals an obligation of approximately $15 million at the December 31, 2003, exchange rate. Fifty percent of the outstanding liability was due on December 26, 2002. Uruguaiana disagreed with the liability for the period from December 2000 to March 2002, which represents approximately $12 million at the December 31, 2003, exchange rate, and on December 18, 2002, Uruguaiana obtained an injunction from the Federal Court suspending the payment of the liability under dispute. On February 25, 2003, ANEEL and MAE filed an appeal against the injunction. On March 12, 2003, the judge responsible for the case did not accept the appeal and maintained the injunction for Uruguaiana. Uruguaiana believes that under the terms of its ANEEL Independent Power Producer Operational Permit, power purchase and regulatory contracts, it is not liable for replacement power costs arising directly out of the electric system's instability. Furthermore, the civil action also discusses the power prices changed by ANEEL in August 2002 related to energy sold at the spot market in June 2001. Uruguaiana does not expect to have sufficient resources to pay the MAE settlement, and if the legal challenge of this obligation is not successful, penalties and fines could be imposed, up to and including the termination of the ANEEL Independent Power Producer Operational Permit. The Company's total investment associated with Uruguaiana as of December 31, 2003 was approximately $325 million, which is net of foreign currency translation losses.

Power purchase costs, transmission charges, and certain taxes (Parcel A costs) are based on current prices for volumes forecasted for the coming year. Differences between actual power costs incurred and tariff recoveries over the course of the year due to the exchange rate impact on the price of Itaipu power (which is priced in U.S. dollars) and other Parcel A costs are tracked in the "CVA" account (tracking account), which is required to be remunerated in the subsequent year. At the annual tariff adjustment date, the distribution company is granted an automatic tariff increase sufficient to recover the unrecovered balance in the tracking account over a 12-month period. If there are over-recoveries, there is an automatic tariff reduction to refund to customers the over-recovery over the next 12-month period.

On April 4, 2003, the Ministry of Mines and Energy ("MME") issued a decree postponing, for a 1-year period, the tracking account tariff increase. According to this decree, the pass-through to tariffs of the amounts accumulated in the tracking account for the distribution concessionaires that had been scheduled to occur from April 8, 2003 to April 7, 2004 will be postponed to the subsequent year's tariff adjustment. As a result, in the case of Sul and Eletropaulo, the pass-through of the tracking account balance for 2003, that should have originally happened on April 19, 2003 and July 4, 2003 amounts to

approximately $12 million and $173 million, respectively. These amounts will be accumulated in the next twelve months and shall be recovered over a 24-month period rather than the usual 12-month period.

In order to compensate for the deferral of the increase relating to the tracking account, BNDES will provide distribution companies with loans, which will be repaid during the recovery period. As the conditions precedents to closing the negotiations between AES and BNDES have been fulfilled (see Note 23), Eletropaulo and Sul are now eligible for such loans.

ARGENTINA—In 2002, Argentina continued to experience a political, social and economic crisis that has resulted in significant changes in general economic policies and regulations as well as specific changes in the energy sector. In January and February 2002, many new economic measures were adopted by the Argentine government, including abandonment of the country's fixed dollar-to-peso exchange rate, converting U.S. dollar denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government also adopted new regulations in the energy sector that have the effect of repealing U.S. dollar denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos. There are no regulatory assets or liabilities recorded in the Argentina entities.

VENEZUELA—The political and economic environment in Venezuela continues to be unstable. The electricity tariffs at EDC are adjusted semi-annually to reflect fluctuations in inflation and the currency exchange rate compared to the U.S. dollar. Failure to receive such adjustment to reflect changes in the currency exchange rate and inflation could adversely affect the Company's results of operations.

In January 1999, a joint resolution of the Ministry of Energy and Mines and the Ministry of Industry and Commerce established the basic tariff rates applicable during the four year tariff regime from 1999 through 2003. The tariffs were established using a combination of two methodologies: cost-plus and return on investment. The regulation that establishes basic tariff rates is expected to change in 2004, and this change may have an impact on the amount and timing of the cash flows and earnings reported by EDC.

IPALCO—IPALCO is subject to regulation by the Indiana Utility Regulatory Commission (the "IURC") as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of public utility properties or securities and certain other matters.

Regulatory assets represent deferred costs that have been included as allowable costs for ratemaking purposes. IPL has recorded regulatory assets at IPL relating to certain costs as authorized by the IURC of $201 million and $141 million for the years ended December 31, 2003 and 2002, respectively. IPL is amortizing non tax-related regulatory assets of $48 million and $44 million as of December 31, 2003 and 2002, respectively, to expense over periods ranging from 1 to 30 years. Tax-related regulatory assets of $153 million and $97 million as of December 31, 2003 and 2002, respectively, represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

On March 27, 2001, AES completed its merger with IPALCO through a share exchange transaction in accordance with the Agreement and Plan of Share Exchange dated July 15, 2000, between AES and IPALCO, and IPALCO became a wholly-owned subsidiary of AES. The Company accounted for the combination as a pooling of interests. Each of the outstanding shares of IPALCO common stock was converted into the right to receive 0.463 shares of AES common stock. The Company issued

approximately 41.5 million shares of AES common stock. The consideration consisted of newly issued shares of AES common stock. IPALCO is a utility business based in Indianapolis with approximately 3,400 MW of gross generation capacity and 450,000 customers in and around Indianapolis.

The Company issued approximately 346,000 options for the purchase of AES common stock in exchange for IPALCO outstanding options using the same exchange ratio. All unvested IPALCO options became vested pursuant to the existing stock option plan upon the change in control.

In connection with the merger with IPALCO, the Company incurred contractual liabilities associated with existing termination benefit agreements and other merger related costs for investment banking, legal and other fees. These costs, which were $131 million in 2001, are shown separately in the accompanying consolidated statements of operations. All of the amounts for the plan were expensed as incurred. As a result of the plan, the work force was reduced by 480 people.

The table below sets forth revenues, net income and comprehensive loss for AES and IPALCO for the period from January 1, 2001 through the date of the merger (amounts in millions).

Revenues:
AES	$	1,407
IPALCO		215

Consolidated Revenues	$	1,622

Net Income:
AES	$	129
IPALCO		(18	)

Consolidated Net Income	$	111

	AES			IPALCO			Combined
Comprehensive Loss:
Net Income (Loss)	$	129		$	(18	)	$	111
Foreign currency translation adjustment		(236	)		—			(236	)
Change in derivative fair value		(50	)		—			(50	)
Minimum pension liability		—			(2	)		(2	)
Cumulative effect of adopting SFAS No. 133 on Jan. 1, 2001		(93	)		—			(93	)

Comprehensive Loss	$	(250	)	$	(20	)	$	(270	)

There have been no changes to the significant accounting policies of AES or IPALCO due to the merger. Both AES and IPALCO have the same fiscal years. There were no intercompany transactions between the two companies prior to the merger date.

The Company has accounted for the following transactions, completed in 2001, using the purchase method of accounting. 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, if any, reflected as goodwill. The results of operations of the acquired companies have been included in the consolidated results of operations since the date of each acquisition.

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 ("ADS") of Gener for AES common stock, AES issued 9.1 million shares of common stock with a value of approximately

$511 million in exchange for Gener ADS's 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. Subsequently, the Company's total ownership reached approximately 99% due to a stock buyback program initiated by Gener in February 2001. The purchase price for the acquisition of Gener was approximately $1.4 billion before asset sales of $318 million, plus the assumption of approximately $700 million of non-recourse debt. Approximately $865 million of goodwill was recorded as part of the purchase and was being amortized over 40 years until January 1, 2002 when the Company adopted SFAS No. 142. See Note 6 for further disclosure of the financial statement impact of this accounting pronouncement. In conjunction with its tender offer, the Company agreed to sell two of Gener's generating assets (Central Puerto and Hidronequen) to TotalFinaElf. In March 2001, Gener and TotalFinaElf executed a purchase and sale agreement which granted to TotalFinaElf the option to purchase three of Gener's generating assets in Argentina: Central Puerto, Hidronequen and TermoAndes. Pursuant to this agreement, in August, 2001, AES sold Gener's interest in Central Puerto to a TotalFinaElf subsidiary for $255 million. In addition, in September TotalFinaElf purchased Gener's interest in Hidronequen for $72.5 million as well as subordinated debt related to Hidronequen held by Gener for approximately $50 million. The option to purchase TermoAndes expired unexercised. Upon completion of the purchase, Gener implemented an employee severance plan. As of December 31, 2001, the severance plan was completed and the work force was reduced by 187 people. All of the approximately $9 million cost related to the plan was recorded in 2001 and all cash payments were made in 2001. The purchase price allocation for Gener was finalized during 2001.

In April 2001, the Company acquired a 75% controlling interest in Kievoblenergo, a distribution company that serves the region that surrounds Kiev, the capital city of Ukraine, for approximately $46 million in cash. The remaining 25% interest is either publicly-owned or owned by the employees of the distribution company.

In May 2001, the Company acquired a 75% controlling interest in Rivnooblenergo, a distribution company that serves the Rivno region in Ukraine, for approximately $23 million in cash. The remaining 25% interest is either publicly-owned or owned by the employees of the distribution company.

In July 2001, a subsidiary of the Company completed the final phase of its acquisition of the energy assets of Thermo Ecotek Corporation, a wholly-owned subsidiary of Thermo Electron Corporation of Waltham, Massachusetts. The transaction was consummated in two phases. The initial phase of the transaction, which occurred on June 29, 2001, was closed at a price of $242 million in cash. The purchase price for the second and final phase was $18 million in cash. This resulted in a total purchase price for the two phases of the Thermo Ecotek acquisition of $260 million. No material long-term liabilities were assumed at the acquisition date. The portfolio of assets acquired by the Company included approximately 500 MW of gas-fired, biomass-fired (agricultural and wood waste) and coal-fired 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.

In July 2001, a subsidiary of the Company acquired a 56% interest in SONEL, an integrated electricity utility in Cameroon, with a 20-year concession on generation, transmission and distribution country-wide. The purchase price was approximately $70 million in cash, plus the assumption of approximately $260 million of long-term liabilities. The other 44% will remain with the government. SONEL is one of the largest African electricity utilities with approximately 800 MW of installed capacity and 452,000 customers.

The purchase price allocations for Thermo Ecotek, SONEL, Kievoblenergo and Rivnooblenergo were finalized during 2002 with no material adjustments to the preliminary purchase accounting.

Effective January 1, 2001, AES adopted SFAS No. 144. This Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that either has been disposed of or is classified as held for sale to be reported as discontinued operations if certain conditions are met.

Consistent with one of the Company's strategic initiatives during 2003, the Company continued its efforts to sell certain subsidiaries. For several of the subsidiary businesses classified as held for sale, impairment losses were recorded to reflect the fact that the estimated sales value was less than the carrying cost.

On December 22, 2003, AES classified its investment in Wolf Hollow, a competitive supply business located in the United States, as held for sale. In the fourth quarter of 2003, the Company recorded a pre-tax impairment charge of approximately $120 million to reduce the carrying value of Wolf Hollow's assets to estimated fair value in accordance with SFAS No. 144.

On December 22, 2003, the Company decided to sell the holding company that owns 50% of Empresa Distribuidora de Electricidad de Este ("EDE Este"), a regional growth distribution company located in Santo Domingo, Dominican Republic, and has reported this business as an asset held for sale. The remaining shares of EDE Este are owned by Corporación Dominicana de Empresas Eléctricas Estatales ("CDEEE") (49%) and former employees (1%). As a result of the decision to sell its shares in the business, the Company recorded a pre-tax impairment charge of approximately $60 million during the fourth quarter of 2003 to reduce the carrying value of the assets to their estimated fair value in accordance with SFAS No. 144. A pre-tax goodwill impairment expense of approximately $68 million was also recorded. The goodwill was considered impaired since the current fair market value of the business was less than its carrying value. The decline in fair value during 2003 was due, in part, to continuing devaluation of the Dominican Peso and operating losses. During 2003, the devaluation of the Dominican Peso resulted in foreign currency transaction losses of $48 million at EDE Este. AES expects to complete the sale during 2004. Los Mina and Andres, contract generation facilities of AES also in the Dominican Republic, are contracted to sell electricity to EDE Este. EDE Este was previously reported in the growth distribution segment.

On December 22, 2003, AES Granite Ridge, a competitive supply business located in the United States, was classified as held for sale. As a result, AES has recorded a pre-tax impairment charge of approximately $201 million.

In December 2003, AES classified its interest in Colombia I, a competitive supply business located in Colombia, as held for sale. In the fourth quarter of 2003, the Company recorded a pre-tax impairment charge of $19 million to reduce the carrying value of Colombia I's assets to its estimated fair value in accordance with SFAS No. 144.

In September 2003, AES reached an agreement to sell 100% of its ownership interest in AES Whitefield, a generation business located in the United States. The sale is structured as a stock purchase agreement. At December 31, 2003 this business was classified as held for sale in accordance with SFAS No. 144. AES Whitefield was previously reported in the competitive supply segment.

On August 8, 2003, the Company decided to sell AES Communications Bolivia, located in La Paz, Bolivia and has reported this business as an asset held for sale. On August 25, 2003, AES signed a Stock Purchase Agreement with a buyer to sell AES Communications Bolivia. As a result of this decision, the Company recorded a pre-tax impairment charge of $29 million during the third quarter of 2003 to reduce the carrying value of the assets to their estimated fair value in accordance with SFAS No. 144. AES expects to complete the sale during the first half of 2004. AES Communications Bolivia was previously reported in the competitive supply segment.

In July 2003, AES reached an agreement to sell 100% of its ownership interest in AES Mtkvari, AES Khrami and AES Telasi for gross proceeds of $23 million. At June 30, 2003 these businesses were classified as held for sale and the Company recorded a pre-tax impairment charge of $204 million during the second quarter of 2003 to reduce the carrying value of the assets to their estimated fair value in accordance with SFAS No. 144. This transaction was completed in August 2003 and resulted in a total write-off of approximately $210 million. AES Mtkvari and AES Khrami were previously reported in the contract generation segment and AES Telasi was previously reported in the growth distribution segment.

On July 29, 2003, the Company sold substantially all the physical assets and operations of AES Barry to an unrelated third party for £40 million (or approximately $62 million). The sale proceeds were used to discharge part of AES Barry's debt and to pay certain transaction costs and fees. The results of operations of the plant assets sold, which constitute a component, have been included in discontinued operations. Interest expense on the debt, which was not part of the disposal group, has been included in income from continuing operations. AES Barry is pursuing a £60 million (or approximately $93 million) claim (the amount of which is disputed) against TXU Europe Energy Trading Limited (TXU EET), which is currently in bankruptcy administration. AES Barry will receive 20% of amounts recovered in excess of £7 million ($11 million) from the administrator. Under the amended credit agreement referred to below, AES Barry may pay any excess to its immediate holding company AES Electric. If the proceeds from TXU EET are not sufficient to repay the bank debt, the banks have recourse to the shares of AES Barry, but have no recourse to the Company for a default by AES Barry.

An amended credit agreement reflecting the sale of the AES Barry assets was signed in July 2003. As a result of the amended credit agreement, AES lost control of AES Barry and discontinued consolidating the business's results. AES Barry was previously reported in the competitive supply segment.

AES Drax Power Limited ("Drax") a former subsidiary of AES, was the operator of the Drax power plant in the United Kingdom. In November 2002, Drax terminated its Hedging Agreement with TXU EET. Also in November 2002, TXU EET and TXU Europe Group plc, the guarantor under the power supply hedging agreement between Drax and TXU EET, filed for bankruptcy administration. As a result of the termination of the Hedging Agreement, which had provided Drax above-market prices for the contracted output (equal to approximately 60 percent of the total output of the plant), Drax became fully exposed to electricity prices in the United Kingdom's competitive spot market. The termination of the Hedging Agreement constituted a change in circumstance that indicated that the carrying value of Drax's net assets may not be recoverable. Additionally, in the fourth quarter of 2002, the Company approved and committed to a plan to sell the business. Accordingly, in the fourth quarter of 2002, a pre-tax impairment charge of $1,170 million ($893 million after-tax) was recorded to write-down the net assets of Drax to their fair value. This charge includes a write off of $215 million of trade receivables and a $955 million write-down of the investment to net realizable value. The approximate fair value of net assets was determined by discounting projected future cash flows of the business.

Negotiations for the sale and restructuring of the business culminated in a restructuring proposal published on June 30, 2003. On August 5, 2003 AES withdrew its support for, and participation in, the June restructuring proposal. On September 30, 2003, the security trustee delivered enforcement notices to Drax, thereby affecting the revocation of voting rights in the shares in AES Drax Acquisition Limited, Drax's parent company. The shares were mortgaged in favor of the security trustee. As a result of the above, AES lost control of Drax and discontinued consolidating it. AES has no continuing involvement in Drax.

On December 11, 2003 AES sold 100% of its ownership interest in both AES Haripur Private Ltd. ("Haripur") and AES Meghnaghat Ltd. ("Meghnaghat"), both generation businesses in Bangladesh, to

CDC Globeleq Total proceeds of the sale were $145 million including working capital and purchase price adjustments of approximately $8 million. AES recognized a loss on the sale of approximately $59 million before and after taxes. These two businesses were previously reported in the contract generation segment.

During the second quarter of 2002, after exploring several strategic options related to Eletronet, a telecommunication business in Brazil, AES committed to a plan to sell its 51% ownership interest in this business. The estimated realizable value was less than the book value of AES's investment and as a result, the investment in Eletronet was written down to its estimated realizable value. The Eletronet sale will close in two parts, the first of which occurred on December 31, 2002. The total loss for Eletronet for 2002, including results of operations, write downs, and the effect of the first closing was $182 million before income taxes ($149 million after taxes). Eletronet was previously reported in the competitive supply segment.

As a result of a significant reduction in spot market electricity prices in the United Kingdom during the first quarter of 2002, operating revenues at the Company's Fifoots Point subsidiary were insufficient to cover operating expenses and debt service costs. Accordingly, the subsidiary was placed in administrative receivership by its project financing lenders and the Company's ownership of the subsidiary was terminated. This resulted in a write off of the Company's investment of $53 million before and after income taxes. The Company has no continuing involvement in the Fifoots Point subsidiary, which was previously reported in the competitive supply segment.

In April 2002, AES reached an agreement to sell 100% of its ownership interest in CILCORP, a utility holding company whose largest subsidiary is Central Illinois Light Company ("CILCO"), to Ameren Corporation in a transaction valued at $1.4 billion including the assumption of debt and preferred stock at the closing. During the year ended December 31, 2002, a pre-tax goodwill impairment expense of approximately $104 million was recorded to reduce the carrying amount of the Company's investment to its estimated fair market value. The goodwill was considered impaired because the current fair market value of the business was less than its carrying value. The fair market value of AES's investment in CILCORP was estimated using as a basis the expected sale price under the related sales agreement. The transaction also included an agreement to sell AES Medina Valley Cogen, a gas-fired cogeneration facility located in CILCO's service territory. The sale of CILCORP by AES was required under the Public Utility Holding Company Act ("PUHCA") when AES merged with IPALCO, a regulated utility in Indianapolis, Indiana in March 2001. The transaction closed in January 2003, and generated approximately $495 million in cash proceeds and resulted in a loss of approximately $24 million before and after income taxes. CILCORP was previously reported in the large utilities segment.

In September 2002, AES sold 100% of its ownership interest in AES NewEnergy a competitive supply business located in the United States to Constellation Energy Group for approximately $260 million. This sale resulted in a loss on sale of approximately $29 million.

In December 2002, AES reached an agreement to sell 100% of its ownership interest in both AES Mt. Stuart and AES Ecogen, both generation businesses in Australia, to Origin Energy Limited and to a consortium of Babcock & Brown and Prime Infrastructure Group, respectively. The total sales price for both businesses was approximately $171 million, which equated to an equity purchase price of approximately $59 million. The sale of AES Mt. Stuart closed in January 2003 and resulted in a loss on sale of approximately $2 million. The sale of AES Ecogen closed in February 2003 and resulted in a gain on sale of approximately $24 million. AES Mt. Stuart and AES Ecogen were previously reported in the contract generation segment.

In December 2002, AES reached an agreement to sell 100% of its ownership interests in Songas Limited ("Songas") a competitive supply business located in Tanzania and AES Kelvin Power (Pty.) Ltd. a contract generation business located in South Africa to CDC Globeleq for approximately $329 million, which includes the assumption of debt. The sales of AES Kelvin, which closed in March 2003, and the sale of Songas, which closed in April 2003 resulted in a total gain on sale of approximately $11 million.

In December 2002, AES classified its investment in Mountainview, a competitive supply business located in the United States, as held for sale. In the fourth quarter of 2002, the Company recorded a pre-tax impairment charge of $415 million ($270 million after-tax) to reduce the carrying value of Mountainview's assets to estimated realizable value in accordance with SFAS No. 144. The determination of the realizable value was based on available market information obtained through discussions with potential buyers. In January 2003, the Company entered into an agreement to sell Mountainview for $30 million with another $20 million payment contingent on the achievement of project specific milestones. The transaction closed in March 2003 and resulted in a gain of approximately $7 million before income taxes ($4 million after taxes). Mountainview was previously reported in the competitive supply segment.

During 2001, the Company decided to exit certain of its businesses. These businesses included Power Direct, Geoutilities, TermoCandelaria, Ib Valley and several telecommunications businesses in Brazil and the United States. For those businesses disposed of or abandoned, the Company determined that significant adverse changes in legal factors and/or the business climate, such as unfavorable market conditions and low tariffs, negatively affected the value of these assets. The Company had certain businesses that were held for sale as of December 31, 2001, including TermoCandelaria. The sales of these assets were completed prior to December 31, 2002, and the resulting gains or losses on these sales were not material.

All of the business components discussed above are classified as discontinued operations in the accompanying consolidated statements of operations. Previously issued statements of operations have been restated to reflect discontinued operations reported subsequent to the original issuance date.

Information for business components included in discontinued operations is as follows (in millions):

The assets and liabilities associated with the discontinued operations and assets held for sale are segregated on the consolidated balance sheets at December 31, 2003 and 2002. The carrying amount of

major asset and liability classifications for businesses recorded as discontinued operations and held for sale are as follows:

In December 2003, AES sold an approximate 39% ownership interest in AES Oasis Limited ("AES Oasis") for cash proceeds of approximately $150 million. The loss realized on the transaction was approximately $36 million before and after income taxes. AES Oasis is an entity that owns an electric generation project in Oman (AES Barka) and two oil-fired generating facilities in Pakistan (AES Lal Pir and AES Pak Gen). AES Barka, AES Lal Pir, and AES Pak Gen are all contract generation businesses.

During the fourth quarter of 2003, the Company decided to discontinue the development of Zeg, a contract generation plant under construction in Poland. In connection with this decision, the Company wrote off its investment in Zeg of approximately $23 million before income taxes ($21 million after tax).

On August 8, 2003, the Company decided to discontinue the construction and development of AES Nile Power in Uganda ("Bujagali"). In connection with this decision, the company wrote off its investment in Bujagali of approximately $76 million before income taxes ($67 million after tax) in the third quarter of 2003. Bujagali was a developing contract generation business.

During April 2003, after consideration of existing business conditions and future opportunities associated with a development project in Honduras (El Faro), the Company decided to offer El Faro for sale. The carrying amount of the investment in El Faro exceeded its fair value. As a result during the second quarter of 2003, AES wrote off its investment of approximately $20 million, before income taxes ($13 million after tax).

In the fourth quarter of 2002, circumstances surrounding Lake Worth project indicated that the carrying amount of the Company's investment in the project may not be recoverable. Therefore, in accordance with SFAS No. 144, a pre-tax impairment charge of $78 million ($51 million after tax) was recorded to write-down the net assets of the project to fair market value. The fair value of the net

assets was estimated by analyzing the discounted future cash flows of the business as well as indications from unrelated third parties regarding the value of the project. The timing of this charge was due to a decision by the Company not to provide any further funding for this project and to sell the project. Lake Worth was previously listed as a competitive supply business.

In September 2002, AES Greystone, L.L.C. and its subsidiary Haywood Power I, L.L.C., sold the Greystone gas-fired peaker assets then under construction in Tennessee to Tenaska Power Equipment for $36 million including cash and assumption of certain obligations. With this sale, AES and its subsidiaries have eliminated any future capital expenditures related to the facility, and also settled all major outstanding obligations with parties involved in this project. AES recorded a pre-tax loss of approximately $168 million ($110 million after tax) associated with this sale. Greystone was previously recorded as a competitive supply business.

In March 2002, AES's 87% owned subsidiary, Corporacion EDC, C.A., sold its remaining shares in Compania Anonima Nacional Telefonos de Venezuela ("CANTV") for cash proceeds of approximately $92 million. The loss realized on this transaction, before the effect of minority interest, was approximately $57 million. EDC is a large utility business.

In December 2001, AES's 87% owned subsidiary, Corporacion EDC, C.A., sold a portion of its shares in CANTV as part of a share buyback program to CANTV for cash proceeds of approximately $59 million. The gain realized on this transaction, before the effect of minority interest, was approximately $18 million.

Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" which establishes accounting and reporting standards for goodwill and other intangible assets. The standard eliminates goodwill amortization and requires an evaluation of goodwill for impairment upon adoption of the standard, as well as annual subsequent evaluations. The Company's annual impairment testing date is October 1st.

SFAS No. 142 requires that goodwill be evaluated for impairment at a level referred to as a reporting unit. A reporting unit is an operating segment as defined by SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," or one level below an operating segment, referred to as a component. Generally, each AES business constitutes a reporting unit.

Generally, reporting units have been acquired in separate transactions. In the event that more than one reporting unit is acquired in a single acquisition, the fair value of each reporting unit is determined, and that fair value is allocated to the assets and liabilities of that unit. If the determined fair value of the reporting unit exceeds the amount allocated to the net assets of the reporting unit, goodwill is assigned to that reporting unit.

As part of the annual testing, the Company wrote off $11 million and $612 million during 2003 and 2002, respectively, which is recorded in goodwill impairment expense in the accompanying consolidated statement of operations. In 2003, the total impairment expense related to a mining operation. The goodwill was considered impaired because the current fair market value of the business is less than the carrying value of the business, primarily as a result of a general slow down of the operations due to the termination of sales contracts that have not been replaced. The amount of the impairment charge represents the entire goodwill balance, which was required to reduce the carrying amount of the asset to its estimated fair value based on discounted cash flows of the business. During 2002, as a result of the unfavorable economic and regulatory environment in Brazil, AES determined the entire goodwill amount relating to Eletropaulo was impaired and recorded a charge of $607 million, after income taxes, at the October 1, 2002 exchange rate. The lower fair value was primarily the result of slower than anticipated recovery to pre-rationing electricity consumption levels and lower electricity prices due

in part to the devaluation of the Brazilian Real. The impairment charge represents the write off required to reduce the carrying amount of the asset to its estimated fair value based on the estimated discounted cash flows.

The adoption of SFAS No. 142 resulted in a reduction in income of $473 million, net of income tax effects, which was recorded as a cumulative effect of accounting change in the first quarter of 2002. The reduction resulted from the write off of goodwill related to certain of our businesses in Argentina ($190 million), Brazil ($231 million specifically related to Sul) and Colombia. The Company wrote off the goodwill associated with certain acquisitions where the current fair market value of such businesses were less than the current carrying values. This primarily resulted from reductions in fair value associated with lower than expected growth in electricity consumption and lower electricity prices due in part to the significant devaluation of the local currencies relative to the original estimates made at the date of acquisition. The fair value of these businesses was estimated using the expected present value of future cash flows and comparable sales, when available.

Changes in the carrying amount of goodwill, by segment, for the years ended December 31, 2003 and 2002 are as follows (in millions):

Reported net income and earnings per share adjusted to exclude goodwill amortization expense for 2003, 2002 and 2001 are as follows (in millions, except per share amounts):

For the years ended December 31, 2003 and 2002, included in other assets in the accompanying consolidated balance sheets are other intangibles with a gross carrying amount of $266 million and $178 million, respectively, and accumulated amortization of $47 million and $18 million, respectively. The other intangibles have a weighted average remaining amortization period of 17.3 years as of December 31, 2003, and 17.0 years as of December 31, 2002. For the years ended December 31, 2003 and 2002 the amortization expense was $14.4 million and $8.8 million, respectively. The estimated amortization expense for fiscal years 2004 through 2008 is $13 million each year.

Eletropaulo. The Company had been a party to a consortium agreement through which the Company had an equity investment in Eletropaulo Metropolitana Eletricidade de Sao Paulo S.A. ("Eletropaulo") and Light Servicos de Eletricidade S.A. ("Light"). The consortium partners, the Company and EDF Internationonal S.A. ("EDF"), shared operational control of Eletropaulo and Light.

During 2001, the Company had a total equity ownership interest of 50.43% and a voting interest of 17.35% in Eletropaulo; therefore, the Company accounted for this investment using the equity-method based on the related consortium agreement that allows the exercise of significant influence.

On February 6, 2002, a subsidiary of the Company exchanged with EDF, all its shares representing a 23.89% interest in Light for 88% of the shares of AES Elpa S.A. (formerly Lightgas Ltd.) (the "swap"). AES Elpa owns 77% of the voting capital (31% of the total capital) of Eletropaulo and 100% of AES Communications Rio. As a result of the swap, AES acquired a controlling interest in Eletropaulo and began consolidating the subsidiary.

In connection with the swap, AES Elpa assumed debt of $527 million of which approximately $85 million was due in October 2002 and approximately $442 million was due in 2003. Upon completion of the transaction, the consortium agreement between AES and EDF was terminated. The transaction did not result in a change in reporting entity.

The swap was accounted for at historical cost as a reorganization of entities under common control. Pre-existing goodwill of approximately $780 million was recorded in conjunction with the swap at the March 31, 2002 exchange rate.

CEMIG. The Company is a party to a joint venture/consortium agreement through which the Company has an equity investment in Companhia Energetica de Minas Gerais ("CEMIG"), an integrated utility in Minas Gerais, Brazil. The agreement prescribes ownership and voting percentages as well as other matters.

In the fourth quarter of 2002, a combination of events occurred related to the CEMIG investment. These events included consistent poor operating performance in part caused by continued depressed demand and poor asset management, the inability to adequately service or refinance operating company debt and acquisition debt, and a continued decline in the market price of CEMIG shares. Additionally, our partner in one of the holding companies in the CEMIG ownership structure sold its interest in this holding company to an unrelated third party in December 2002 for a nominal amount. Upon evaluating these events in conjunction with each other, the Company concluded that an other than temporary decline in value of the CEMIG investment had occurred. Therefore, in December 2002, AES recorded an impairment charge related to the other than temporary decline of the investment in CEMIG, and the shares in CEMIG were written-down to fair market value. Additionally, AES recorded a valuation allowance against a deferred tax asset related to the CEMIG investment. The total amount of these charges, net of tax, was $587 million, of which $264 million relates to the other than temporary impairment of the investment and $323 million relates to the valuation allowance against the deferred tax asset. As a result of these charges, the Company's investment in CEMIG, net of debt used to finance the CEMIG investment, is negative.

In the fourth quarter of 2002, AES lost voting control of one of the holding companies in the CEMIG ownership structure. This holding company indirectly owns the shares related to the CEMIG investment and indirectly holds the project financing debt related to CEMIG. As a result of the loss of voting control, AES stopped consolidating this holding company at December 31, 2002.

Other. During the fourth quarter of 2003, the Company sold its 25% ownership interest in Medway Power Limited ("MPL"), a 688 MW natural gas-fired combined cycle facility located in the United Kingdom, and AES Medway Operations Limited ("AESMO"), the operating company for the facility, in an aggregate transaction valued at approximately £47 million ($78 million). The sale resulted in a gain of $23 million which was recorded in continuing operations. MPL and AESMO were previously reported in the contract generation segment.

In the second quarter of 2002, the Company sold its investment in Empresa de Infovias S.A. ("Infovias"), a telecommunications company in Brazil, for proceeds of $31 million to CEMIG, an affiliated company. The loss recorded on the sale was approximately $14 million and is recorded as a loss on sale of assets and asset impairment expenses in the accompanying consolidated statements of operations.

In the second quarter of 2002, the Company recorded an impairment charge of approximately $40 million, after income taxes, on an equity method investment in a telecommunications company in Latin America held by EDC. The impairment charge resulted from sustained poor operating performance coupled with recent funding problems at the invested company.

During 2001, the Company lost operational control of Central Electricity Supply Corporation ("CESCO"), a distribution company located in the state of Orissa, India. The state of Orissa appointed an administrator to take operational control of CESCO. CESCO is accounted for as a cost method investment. AES's investment in CESCO is negative.

In August 2000, a subsidiary of the Company acquired a 49% interest in Songas for approximately $40 million. The Company acquired an additional 16.79% of Songas for approximately $12.5 million, and the Company began consolidating this entity in 2002. Songas owns the Songo Songo Gas-to-Electricity Project in Tanzania. In December 2002, the Company signed a Sales Purchase Agreement to sell 100% of our ownership interest in Songas. The sale of Songas closed in April 2003 (see Note 4 for further discussion of the transaction).

The following tables present summarized comparative financial information (in millions) of the entities in which the Company has the ability to exercise significant influence but does not control and that are accounted for using the equity method.

In 2002 and 2001, the results of operations and the financial position of CEMIG were negatively impacted by the devaluation of the Brazilian Real and the impairment charge recorded in 2002. The Brazilian Real devalued 32% and 19% for the years ended December 31, 2002 and 2001, respectively.

The Company recorded $83 million and $210 million of pre-tax non-cash foreign currency transaction losses on its investments in Brazilian equity method affiliates during 2002 and 2001, respectively.

Affiliate	Country	2003	2002	2001
CEMIG	Brazil	21.62	21.62	21.62
Chigen affiliates	China	30.00	30.00	30.00
EDC affiliates	Venezuela	45.00	45.00	45.00
Eletropaulo (1)	Brazil	—	—	50.43
Elsta	Netherlands	50.00	50.00	50.00
Gener affiliates	Chile	50.00	50.00	50.00
Infovias	Brazil	—	—	50.00
Itabo	Dominican Republic	25.00	25.00	25.00
Kingston Cogen Ltd	Canada	50.00	50.00	50.00
Light (1)	Brazil	—	—	23.89
Medway Power, Ltd	United Kingdom	—	25.00	25.00
OPGC	India	49.00	49.00	49.00
Songas Limited	Tanzania	—	—	49.00

The Company's after-tax share of undistributed earnings of affiliates included in consolidated retained earnings were $201 million, $189 million and $462 million at December 31, 2003, 2002 and 2001, respectively. The Company charged and recognized construction revenues, management fees and interest on advances to its affiliates, which aggregated $8 million, $7 million and $12 million for each of the years ended December 31, 2003, 2002 and 2001, respectively.

	December 31,
	2003		2002
HELD-TO-MATURITY:
Certificates of deposit	$	156	$	135
Money market funds		30		40
Other		1		1

Subtotal		187		176

AVAILABLE-FOR-SALE:
Corporate Bonds		—		1

Subtotal		—		1

TRADING:
Money Market Funds		1		—
Commercial Paper		1		—

Subtotal		2		—

TOTAL	$	189	$	177

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 (other than the equity securities discussed below) were approximately the same. The trading investments are recorded at fair value. As of December 31, 2003 and 2002, approximately $176 million and $170 million, respectively, of investments classified as held-to-maturity, were restricted or pledged as collateral.

NON-RECOURSE DEBT—Non-recourse debt at December 31, 2003 and 2002 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 AES, the 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 interest rate swap and forward interest rate swap agreements for continuing operations, discontinued operations and businesses held for sale in an aggregate notional principal amount of approximately $2.9 billion at December 31, 2003. The interest rate swaps are accounted for at fair value (see Note 10). The swap agreements effectively change the variable interest rates on the portion of the debt covered by the notional amounts to fixed rates ranging from approximately 1.98% to 7.96%. The agreements expire at various dates from 2004 through 2023. In the event of nonperformance by the counter-parties, the Company may be exposed to increased interest rates; however, the Company does not anticipate nonperformance by the counter-parties, 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 these financial 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.

At December 31, 2003, the Eletropaulo operating company, AES Elpa (Eletropaulo holding company), AES Transgas (Eletropaulo holding company) and Sul in Brazil, Edelap, Eden/Edes, TermoAndes and Parana in Argentina, Wolf Hollow and AES Granite Ridge in the United States, and Los Mina and Andres in the Dominican Republic, were in default under certain of their outstanding project indebtedness.

As of December 31, 2003, the Eletropaulo operating company had approximately $1.3 billion (including interest) of outstanding indebtedness, and AES Elpa and AES Transgas had approximately $708 million and $641 million, respectively, of outstanding BNDES and BNDESPAR indebtedness (including accrued interest).

All of the common shares of Eletropaulo owned by AES Elpa are pledged to BNDES to secure the AES Elpa debt and all of the preferred shares of Eletropaulo owned by AES Transgas and AES CEMIG Empreendimentos II, Ltd. (which owns approximately 7.4% of Eletropaulo's preferred shares, representing 4.4% economic ownership of Eletropaulo) are pledged to BNDESPAR to secure AES Transgas debt. AES has pledged its share of the proceeds in the event of the sale of certain of its businesses in Brazil, including Sul, Uruguaiana, Eletronet and AES Communications Rio, to secure the indebtedness of AES Elpa to BNDES for the repayment of the debt of AES Elpa. The interests underlying the Company's investments in Uruguaiana, AES Communications Rio and Eletronet have also been pledged as collateral to BNDES under the AES Elpa loan.

As a result of AES Elpa's and AES Transgas's failures to pay amounts due under the financing arrangements, BNDES had the right to call due all of AES Elpa's outstanding debt with BNDES, and BNDESPAR had the right to call due all of AES Transgas's outstanding debt with BNDESPAR. On December 22, 2003, AES and BNDES reached an agreement to restructure approximately all of its outstanding debt, including accrued interest, owed to BNDES and BNDESPAR by AES Elpa and AES Transgas. The Company reclassified all the related outstanding debt, including interest, owed by AES Elpa and AES Transgas, approximating $1.3 billion, into long-term liabilities as of December 31, 2003 because of the Company's intent and ability to consummate the refinancing of the debt on a long-term basis. See Note 23 for information on the refinancing subsequent to December 31, 2003.

Due to financial covenant and other defaults under Eletropaulo loan agreements, Eletropaulo's commercial lenders have the right to call due approximately $787 million of indebtedness as of December 31, 2003. In December 2003, Eletropaulo reached an agreement with its private creditors to reschedule the repayment of the outstanding debt over the next five years. The related balance is still classified as current at December 31, 2003 because the Company has not yet closed the refinancing relating to the Eletropaulo debt (see Note 23).

Sul and AES Cayman Guaiba, a subsidiary of the Company that owns the Company's interest in Sul, are facing near-term debt payment obligations that must be extended, restructured, refinanced or repaid. Sul had outstanding debentures of approximately $71 million, including accrued interest, at December 31, 2003 relating to the debt that was restructured on December 1, 2002. The restructured debentures had a partial interest payment due December 2003 and principal payments due in 36 equal monthly installments commencing on December 1, 2003. The first installment was paid and the January 2004 and February 2004 payments were postponed under the mutual agreement considering the restructuring process. Additionally, Sul has an outstanding working capital loan of approximately $10 million, including accrued interest, which is to be repaid in 12 monthly installments commencing on January 30, 2004. Furthermore, on January 20, 2003, Sul and AES Cayman Guaiba signed a letter agreement with the agent for the banks under the $300 million AES Cayman Guaiba syndicated loan

for the restructuring of the loan. A $30 million principal payment due on January 24, 2003 under the syndicated loan was waived by the lenders through April 24, 2003 and has not been paid. While the lenders have not agreed to extend any additional waivers, they have not exercised their rights under a $50 million AES parent guarantee. There can be no assurance, however, that an additional waiver or a restructuring of this loan will be completed. All debt at Sul and AES Cayman Guaiba is classified as current at December 31, 2003.

AES has several subsidiaries in Argentina operating in both the competitive supply and growth distribution segments of the electricity business. Eden/Edes, Edelap and TermoAndes are growth distribution facilities that operate in the province of Buenos Aires. Generation facilities include Alicura, Parana, CTSN, Rio Juramento and several other smaller hydro facilities. These businesses are experiencing reduced cash flows arising from the economic and regulatory changes described in Note 13. Eden/Edes, Edelap, TermoAndes and Parana are in default on their project financing arrangements at December 31, 2003, and the related outstanding debt is classified as current.

In the United States, Wolf Hollow is in payment default at December 31, 2003, under its senior credit facility primarily due to depressed spark spreads in Texas and construction delays. Depressed merchant power prices and an unforeseen forced outage have caused AES Granite Ridge, a competitive supply business also located in the United States, to be in default of its loan agreements and unable to make debt service payments due to its lenders. In December 2003, Wolf Hollow and AES Granite Ridge were classified as held for sale and reported in discontinued operations (see Note 4). All of the outstanding debt of these businesses, approximately $600 million, is classified as current.

At the end of 2003, Los Mina and Andres in the Dominican Republic, each went into technical default on its outstanding debt. Discussions with the lenders are still ongoing. Management of these businesses expects to receive waivers upon completion of these discussions. All of the related outstanding debt of Los Mina and Andres is classified as current at December 31, 2003.

The total debt classified as current in the accompanying consolidated balance sheets related to such defaults, after taking into consideration reclassifications due to subsequent refinancing, was $2.3 billion at December 31, 2003, of which approximately $600 million is recorded as discontinued operations and businesses held for sale.

None of the businesses referred to above that are currently in default are owned by subsidiaries that currently meet the applicable definition of materiality in AES's corporate debt agreements in order for such defaults to trigger an event of default or permit an acceleration under such parent company indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact the Company's financial position and results of operations; it is possible that one or more of these subsidiaries could fall within the definition of a "material subsidiary" and thereby, upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the AES parent company's senior notes, senior subordinated notes and junior subordinated notes.

At December 31, 2003, the Company also reclassified $80 million from current liabilities to long-term liabilities relating to certain debt of IPALCO maturing within the next year, because of the Company's intent and ability to refinance these obligations on a long-term basis. See Note 23 for information about the refinancing.

RECOURSE DEBT—Recourse debt obligations are direct borrowings of the AES parent corporation and at December 31, 2003 and 2002, consisted of the following (in millions):

Private placement and tender offer. On May 8, 2003, AES completed a $1.8 billion private placement of second priority senior secured notes. Net proceeds were used to (i) repay $475 million of debt outstanding under our senior secured credit facilities, (ii) to repurchase approximately $1.1 billion aggregate principal amount of our senior notes pursuant to a tender offer, (iii) to repurchase approximately $104 million aggregate principal amount of our senior subordinated notes pursuant to a tender offer and (iv) for general corporate purposes, which included repurchasing other outstanding securities.

Amended and restated bank facilities. On July 29, 2003 the Company closed its amended and restated senior secured bank credit facilities providing for a $250 million revolving loan and letter of credit facility and a $700 million term loan facility. Loans under the amended facilities bear a floating interest rate at either LIBOR plus 4% or a base rate plus 3%, and maturity of the bank credit facilities has been extended to July 31, 2007. As a result of this financing, the total amount of credit available under

the amended facilities was increased by approximately $135 million to $950 million. The Company has authorized the issuance of letters of credit to AES Eastern Energy, L.P.'s counterparties from the Company's $250 million revolving loan and letter of credit facility. For the year 2003, $25 million was approved for such purposes, with an increase to $35 million for the calendar year 2004. As of December 31, 2003, $4.6 million of letters of credit had been issued to a number of counterparties to support normal, ongoing hedging activities.

The senior secured credit facilities are subject to mandatory prepayment on a ratable basis with the Company's 10% senior secured exchange notes due 2005:

Certain of the Company's obligations under the senior secured credit facilities are guaranteed by its direct subsidiaries through which the Company owns its interests in the Shady Point, Hawaii, Warrior Run and Eastern Energy businesses. The Company's obligations under the senior secured credit facilities are, subject to certain exceptions, substantially secured, equally and ratably with its 10% senior secured notes due 2005, by: (i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.

During 1999, AES Trust III, a wholly owned special purpose business trust, issued 9 million of $3.375 Term Convertible Preferred Securities ("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.

Dividends on the TECONS are payable quarterly at an annual rate of 6.75% by AES Trust III and 6% by AES Trust VII. 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 would accumulate quarterly and accrue interest and the Company may not declare or pay dividends on its common stock.

AES Trust III and AES Trust VII are variable interest entities under FASB Interpretation 46, Consolidation of Variable Interest Entities ("FIN 46"). AES is not the primary beneficiary of either AES Trust III or AES Trust VIII and accordingly does not consolidate their results. AES's obligations under the junior subordinated debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by the AES Corporation of each respective trust's obligations under the trust securities issued by each respective trust.

The Junior Subordinated Debentures due 2005 are convertible into common stock of the Company at the option of the holder at any time at or before maturity, unless previously redeemed, at a conversion price of $27.00 per share.

FUTURE MATURITIES OF DEBT—Scheduled maturities of total debt for continuing operations at December 31, 2003 are (in millions):

Scheduled maturities of total debt for discontinued operations at December 31, 2003 are (in fmillions):

COVENANTS—The terms of the Company's second priority senior secured, senior and subordinated notes contain certain restrictive covenants, including limitations on the Company's ability to incur additional debt, pay dividends to stockholders, incur additional liens, provide guarantees and enter into sale and leaseback transactions.

The senior secured credit facilities contain customary covenants and restrictions on the Company's ability to engage in certain activities, including, but not limited to:

The senior secured credit facilities also contain financial covenants requiring the Company to maintain certain financial ratios including:

The terms of the Company's non-recourse debt, which is debt held at subsidiaries, include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include but are not limited to maintenance of certain reserves, minimum levels of working capital and limitations on incurring additional indebtedness. Compliance with certain covenants may not be objectively determinable.

As of December 31, 2003, approximately $396 million of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within debt service reserves and other deposits in the consolidated balance sheets.

Various lender and governmental provisions restrict the ability of the Company's subsidiaries to transfer their net assets to the parent company. Such restricted net assets of subsidiaries amounted to approximately $6 billion at December 31, 2003.

OTHER FINANCING—IPL, a subsidiary of the Company, formed IPL Funding Corporation ("IPL Funding") in 1996 to purchase, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL in exchange for a note payable. IPL Funding is not consolidated by IPL or IPALCO since it meets requirements set forth in SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" to be considered a qualified special-purpose entity. IPL Funding has entered into a purchase facility with unrelated parties ("the Purchasers") pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million of the receivables purchased from IPL. As of December 31, 2003, the aggregate amount of receivables purchased pursuant to this facility was $50 million. The net cash flows between IPL and IPL Funding are limited to cash payments made by IPL to IPL Funding for interest charges and processing fees. These payments totaled approximately $1 million, $1.1 million and $2.3 million for the years ended December 31, 2003, 2002 and 2001, respectively. IPL retains servicing responsibilities through its role as a collection agent for the amounts due on the purchased receivables. IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL

Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of or otherwise relating to the sale agreement, subject to certain limitations as defined in the agreements. The transfers of such accounts receivable from IPL to IPL Funding are recorded as sales; however, no gain or loss is recorded on the sale.

Under the receivables sale agreement, if IPL fails to maintain certain financial covenants regarding interest coverage and debt to capital, it would constitute a "termination event." As of December 31, 2003, IPL was in compliance with such covenants.

As a result of IPL's current credit rating, the facility agent has the ability to (i) replace IPL as the collection agent; and (ii) declare a "lock-box" event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. In the facility agent's discretion, the lock-box account may be under the control of IPL (as collection agent) or under the control of the facility agent. A termination event would also give the Purchasers the option to discontinue the purchase of new receivables and cause all proceeds of the purchased receivables to be used to reduce the Purchaser's investment and to pay other amounts owed to the Purchasers and the facility agent. This would have the effect of reducing the operating capital available to IPL by the aggregate amount of such purchased receivables, currently $50 million.

Effective January 1, 2001, AES adopted SFAS No. 133, "Accounting For Derivative Instruments And Hedging Activities," which, as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. The adoption of SFAS No. 133 on January 1, 2001, resulted in a cumulative reduction to income of less than $1 million, net of deferred income tax effects, and a cumulative increase to accumulated other comprehensive loss in stockholders' equity (deficit) of $93 million, net of deferred income tax effects.

For the years ended December 31, 2003, 2002 and 2001 the impacts of changes in derivative fair value, net of income taxes, primarily related to derivatives that do not qualify for hedge accounting treatment, were a charge of $40 million, $12 million, and $36 million respectively. These amounts include a charge of $12 million, $12 million and $6 million after income taxes, related to the ineffective portion of derivatives qualifying as cash flow and fair value hedges for each of the years ended December 31, 2003, 2002 and 2001, respectively, and are primarily recorded in other expense.

Approximately $115 million of other comprehensive loss related to derivative instruments as of December 31, 2003 is expected to be recognized as a reduction to income from continuing operations over the next twelve months. A portion of this amount is expected to be offset by the effects of hedge accounting. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for hedges of interest rate risk, as depreciation is recorded for hedges of capitalized interest, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure, and as electric and gas sales and purchases are recognized for hedges of forecasted electric and gas transactions. Amounts

recorded in accumulated other comprehensive income (loss), after income taxes, during the years ended December 31, 2003, 2002, and 2001 respectively were as follows (in millions):

	Years Ended December 31,
	2003			2002
Balance, beginning of year	$	(398	)	$	(121	)
Reclassification to earnings		126			106
Reclassification upon sale or disposal		130			—
Change in fair value		(121	)		(383	)

Balance, December 31	$	(263	)	$	(398	)

AES utilizes derivative financial instruments to hedge interest rate risk, foreign exchange risk and commodity price risk. The Company utilizes interest rate swap, cap and floor agreements to hedge interest rate risk on floating rate debt. The majority of AES's interest rate derivatives are designated and qualify as cash flow hedges. Certain derivatives are not designated as hedging instruments, primarily because they do not qualify for hedge accounting treatment as defined by SFAS No. 133. The purpose of these instruments is to economically hedge interest rate risk, foreign exchange risk or commodity price risk. However, certain features of these contracts, primarily the inclusion of written options, cause them to not qualify for hedge accounting.

Currency forward and swap agreements are utilized by the Company to hedge foreign exchange risk which is a result of AES or one of its subsidiaries entering into monetary obligations in currencies other than its own functional currency. Portions of these contracts are designated and qualify as either fair value or cash flow hedges. Certain non-derivative instruments were designated and qualified as hedges of the foreign currency exposure of a net investment in a foreign operation, and approximately $13 million of transaction losses after income taxes, were included in the foreign currency cumulative translation adjustment for the year ended December 31, 2002.

The Company utilizes electric and gas derivative instruments, including swaps, options, forwards and futures, to hedge the risk related to electricity and gas sales and purchases. The majority of AES's electric and gas derivatives are designated and qualify as cash flow hedges.

The maximum length of time over which AES is hedging its exposure to variability in future cash flows for forecasted transactions, excluding forecasted transactions related to the payment of variable interest, is twenty-eight years. For the years ended December 31, 2003, 2002 and 2001, losses of $16 million, $1 million and $4 million, respectively were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it is probable that the forecasted transaction will not occur. For the year ended December 31, 2003, no fair value hedges were discontinued. For the year ended December 31, 2002, two fair value hedges were discontinued because they failed to meet the hedge effectiveness criteria of SFAS No. 133. The discontinuance of hedge accounting for these contracts did not have an impact on earnings.

OPERATING LEASES—As of December 31, 2003, 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, $31 million and $32 million in the years ended December 31, 2003, 2002 and 2001, respectively, including commitments of businesses classified as discontinued amounting to $0 million in 2003, $6 million in 2002 and $18 million in 2001.

The future minimum lease commitments under these leases are as follows (in millions):

CAPITAL LEASES—One of AES's subsidiaries, AES Indian Queens Power Limited, conducts a major part of its operations from leased facilities. The plant lease is for 25 years expiring in 2022, and has been recorded as a capital lease in Property, Plant and Equipment under "Electric generation and distribution assets." Gross value of the leased asset is $44 million and $40 million as of December 31, 2003 and 2002, respectively.

The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2003 (in millions):

	Total
2004	$	2
2005		2
2006		2
2007		3
2008		3
Thereafter		57

Total minimum lease payments	$	69

Less: imputed interest		(33	)

Present value of total minimum lease payments	$	36

SALE/LEASEBACK—In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas ("NYSEG"). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 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, $54 million and $58 million in 2003, 2002 and 2001, respectively.

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 (other then deferrable basic rent) and fixed charges expected to become due in the immediately succeeding three-year period. At December 31, 2003, 2002 and 2001, the amount deposited in the rent reserve account approximated $32 million. This amount is included in restricted cash and can only be utilized to satisfy lease obligations.

The lease agreements require the subsidiary to maintain an additional liquidity account. The required balance in the additional liquidity account was initially equal to the greater of $65 million less the balance in the rent reserve account or $29 million. As of December 31, 2003, the subsidiary had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit, issued by Fleet Bank in the stated amount of approximately $36 million. This letter of credit was established by AES for the benefit of the subsidiary. However, the subsidiary is obligated to replenish or replace this letter of credit in the event it is drawn upon or needs to be replaced.

CONTRACTS—Operating subsidiaries of the Company have entered into "take-or-pay" contracts for the purchase of electricity from third parties. Purchases in the years ended December 31, 2003, 2002 and 2001 were approximately $1,051 million, $1,263 million and $1,069 million, respectively, including purchases of businesses classified as discontinued amounting to $0 million in 2003, $44 million in 2002 and $36 million in 2001.

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 the year ended December 31, 2003, 2002 and 2001 were approximately $218 million, $642 million and $617 million, respectively, including purchases of businesses classified as discontinued amounting to $0 million in 2003, $403 million in 2002 and $419 million in 2001.

ENVIRONMENTAL—As of December 31, 2003, the Company has recorded cumulative liabilities associated with acquired generation plants of approximately $27 million for projected environmental remediation costs.

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 Notice of Violation ("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 May 2000, the New York State Department of Environmental Conservation ("NYSDEC") issued a 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 New York State Electric and Gas ("NYSEG"). 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 NYSDEC, and any additional enforcement actions that might be brought by the New York State Attorney General, the NYSDEC or the U.S. Environmental Protection Agency ("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. In addition to the NOV, the NYSDEC alleged, after our acquisition of the Cayuga, Westover, Greenidge, Hickling and Jennison plants from NYSEG in May 1999, air permit violations at each of those plants. Specifically, NYSDEC has alleged exceedances of the capacity emissions limitations at these plants. With respect to pre-May 1999 and post-May 1999 violations, respectively, NYSDEC has notified NYSEG, on the one hand, and AES, on the other, of their respective liability for such alleged violations. To remediate these alleged violations, NYSDEC has proposed that each of AES and NYSEG pay fines and penalties in excess of $100,000. Resolution of this matter also could require AES to install additional pollution control technology at these plants. NYSEG has asserted a claim against AES for indemnification against all penalties and other related costs arising out of NYSDEC's allegations. However, no formal consent order has been issued by the NYSDEC.

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.

GUARANTEES, LETTERS OF CREDITS—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. In the normal course of business, AES and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a subsidiary on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish the subsidiaries' intended business purposes.

Most of the contingent obligations primarily represent future performance commitments which the Company expects to fulfill within the normal course of business. Amounts presented in the above table represent the Company's current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure to the Company as of December 31, 2003. Guarantee termination provisions vary from less than 1 year to greater than 20 years. Some result from the end of a contract period, assignment, asset sale, change in credit rating, or elapsed time. The amounts above do not include obligations made by the Company for the benefit of the lenders associated with the non-recourse debt of subsidiaries recorded as liabilities in the accompanying consolidated balance sheet amounting to $147 million, and commitments to fund its equity in projects currently under development or in construction in the amount of $38 million.

The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power purchase agreements for projects in development, under construction and operating. While the Company does not expect to be required to fund any material amounts under these contingent contractual obligations during 2004 or beyond that are not recorded on the balance sheet, many of the events which would give rise to such an obligation are beyond the Company's control. There can be no assurance that the Company would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder.

The Company pays a letter-of-credit fee ranging from 0.5% to 5.0% per annum on the outstanding amounts.

During 2003, the Company recorded a $9.3 million liability of which represented the approximate fair value of the guarantee provided by the Company to Ameren Corporation ("Ameren") as a result of the sale of 100% ownership interest in CILCORP, a utility holding company whose largest subsidiary is Central Illinois Light Company ("CILCO"). In connection with the sale of CILCO, AES agreed to indemnify and make whole Ameren against 60% of the total of any and all liabilities, damages, penalties, claims and costs incurred by CILCO relating to the assertion of possible claim by Enron after the CILCORP closing. In connection with the indemnification provided to Ameren in the event that Ameren is required to pay any damages to Enron, an escrow agreement was made between AES and Ameren to establish a mechanism for holding a portion of the sales price in escrow to satisfy in part or in whole AES's obligations under the indemnification agreement. As such, Ameren transferred $5 million to the designated escrow account.

LITIGATION—In September 1999, a judge in the Brazilian appellate state court of Minas Gerais granted a temporary injunction suspending the effectiveness of a shareholders' agreement between

Southern Electric Brasil Participacoes, Ltda. ("SEB") and the state of Minas Gerais concerning CEMIG. AES's investment in CEMIG is through SEB. This shareholders' agreement granted SEB certain rights and powers in respect of CEMIG (the "Special Rights"). The temporary injunction was granted pending determination by the lower state court of whether the shareholders' agreement could grant SEB the Special Rights. In October 1999, the full state appellate court upheld the temporary injunction. In March 2000, the lower state court in Minas Gerais ruled on the merits of the case, holding that the shareholders' agreement was invalid where it purported to grant SEB the Special Rights. In August 2001, the state appellate court denied an appeal of the merits decision, and extended the injunction. In October 2001, SEB filed two appeals against the decision on the merits of the state appellate court, one to the Federal Superior Court and the other to the Supreme Court of Justice. The state appellate court denied access of these two appeals to the higher courts, and in August 2002, SEB filed two interlocutory appeals against such decision, one directed to the Federal Superior Court and the other to the Supreme Court of Justice. These appeals continue to be pending. SEB intends to vigorously pursue by all legal means a restoration of the value of its investment in CEMIG. However, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit the SEB's influence on the daily operation of CEMIG.

In November 2000, we were 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. The 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. On July 30, 2001, the Court remanded the case back to San Diego Superior Court. The case was consolidated with five other lawsuits alleging similar claims against other defendants. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which asserted the claims asserted in the earlier action and names AES, AES Redondo Beach, L.L.C., AES Alamitos, L.L.C., and AES Huntington Beach, L.L.C. as defendants. In May 2002, the case was removed by certain cross-defendants from the San Diego County Superior Court to the United States District Court for the Southern District of California. Plaintiffs filed a motion to remand the case to state court, which was granted on December 13, 2002. Certain defendants have appealed that decision to the United States Court of Appeals for the Ninth Circuit. That appeal is pending before the Ninth Circuit. We believe that we have meritorious defenses to any actions asserted against us and expect that we will defend ourselves vigorously against the allegations.

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 and AES Placerita. AES Southland and AES Placerita have cooperated fully with the FERC investigation.

requests from the FERC Staff, have responded to those data requests, and have cooperated fully with the investigation. The physical withholding investigation is ongoing.

In July 2001, a petition was filed against CESCO, an affiliate of the Company by the Grid Corporation of Orissa, India ("Gridco"), with the Orissa Electricity Regulatory Commission ("OERC"), alleging that CESCO has defaulted on its obligations as a government licensed distribution company; that CESCO management abandoned the management of CESCO; and asking for interim measures of protection, including the appointment of a government regulator to manage CESCO. Gridco, a state owned entity, is the sole energy wholesaler to CESCO. In August 2001, the management of CESCO was handed over by the OERC to a government administrator that was appointed by the OERC. By its Order of August 2001, the OERC held that the Company and other CESCO shareholders were not proper parties to the OERC proceeding and terminated the proceedings against the Company and other CESCO shareholders. Subsequently, OERC issued notices regarding the OERC proceedings to the Company and the other CESCO shareholders. The Company has advised OERC that the Company was not a party. In October 2003, OERC again forwarded a notice to the Company advising of a hearing in the OERC matter scheduled for November 2003. The Company, in November 2003, again advised the OERC that the Company is not subject to the OERC proceedings. Gridco also has asserted that a Letter of Comfort issued by the Company in connection with the Company's investment in CESCO obligates the Company to provide additional financial support to cover CESCO's financial obligations. In December 2001, a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 was served on the Company by Gridco pursuant to the terms of the CESCO Shareholder's Agreement ("SHA"), between Gridco, the Company, AES ODPL, and Jyoti Structures. The notice to arbitrate failed to detail the disputes under the SHA for which the Arbitration had been initiated. After both parties had appointed arbitrators, and those two arbitrators appointed the third neutral arbitrator, Gridco filed a motion with the India Supreme Court seeking the removal of AES's arbitrator and the neutral chairman arbitrator. In the fall of 2002, the Supreme Court rejected Gridco's motion to remove the arbitrators. Gridco has dropped the challenge of the appointment of neutral chairman arbitrator; however, it retained the challenge of removal of AES's arbitrator. Although that motion remains pending, the parties have filed their respective statement of claims, counter claims and defenses. On or about July 26, 2003, Gridco filed a motion in the District Court of Bhubaneshwar, India, seeking a stay of the arbitration and requesting that the District Court terminate the mandate of the neutral chairman arbitrator. The District Court gave a stay order, and the case was scheduled to be heard in mid-November 2003. Thereafter, pursuant to a separate motion filed with the Court in India, a further temporary stay of the arbitration proceedings was granted until the India Court issued a decision on whether or not to grant a permanent stay of the arbitration. In the interim, and pending a decision by the Court as to whether to grant a permanent stay, arbitration proceedings have been tentatively scheduled for April 2004. The Company believes that it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations.

Employees Retirement Income Security Act by investing assets of the thrift plan in the common stock of IPALCO prior to the acquisition of IPALCO by the Company. In December 2002, plaintiffs moved to certify this case as a class action. The Court granted the motion for class certification on September 30, 2003. On October 31, 2003, the parties filed cross-motions for summary judgment on liability. Those motions currently are pending before the Court. IPALCO believes it has meritorious defenses to the claims asserted against it and intends to defend this lawsuit vigorously.

In July 2002, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana. In September 2002, two virtually identical complaints were filed against the same defendants in the same court. All three lawsuits purport to be filed on behalf of a class of all persons who exchanged their shares of IPALCO common stock for shares of AES common stock issued pursuant to a registration statement dated and filed with the SEC on August 16, 2000. The complaint purports to allege violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 based on statements in or omissions from the registration statement concerning certain secured equity-linked loans by AES subsidiaries; the supposedly volatile nature of AES stock, as well as AES's allegedly unhedged operations in the United Kingdom and the alleged effect of the New Electrical Trading Agreements ("NETA") on AES's United Kingdom operations. In October 2002, the defendants moved to consolidate these three actions with the IPALCO securities lawsuit referred to immediately below. On November 5, 2002, the Court appointed lead plaintiffs and lead and local counsel. On March 19, 2003, the Court entered an order on defendants' motion to consolidate, in which the Court deferred its ruling on defendants' motion and referred the actions to a magistrate judge for pre-trial supervision. On April 14, 2003, lead plaintiffs filed an amended complaint, which adds former IPALCO directors and officers John R. Hodowal, Ramon L. Humke and John R. Brehm as defendants and, in addition to the purported claims in the original complaint, purports to allege against the newly added defendants violations of Sections 10(b) and 14(a) of the Securities Exchange Act of 1934 and Rules 10b-5 and 14a-9 promulgated thereunder. The amended complaint also purports to add a claim based on alleged misstatements or omissions concerning an alleged breach by AES of alleged obligations AES owed to Williams Energy Services Co. under an agreement between the two companies in connection with the California energy market. By Order dated August 25, 2003, the court consolidated these three actions with an action captioned Cole et al. v. IPALCO Enterprises, Inc. et al, 1:02-cv-01470-DFH-TAB (the "Cole Action"), which is discussed immediately below. On September 26, 2003, defendants filed a motion to dismiss the amended complaint. The motion to dismiss is sub judice. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend these lawsuits vigorously.

In September 2002, IPALCO and certain of its former officers and directors were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana (the "Cole Action"). The lawsuit purports to be filed on behalf of the class of all persons who exchanged shares of IPALCO common stock for shares of AES common stock pursuant to the Registration Statement dated and filed with the SEC on August 16, 2000. The complaint purports to allege violations of Sections 11 of the Securities Act of 1933 and Sections 10(a), 14(a) and 20(a) of the Securities Exchange Act of 1934, and Rules 10b-5 and 14a-9 promulgated thereunder based on statements in or omissions from the Registration Statement covering certain secured equity-linked loans by AES subsidiaries; the supposedly volatile nature of the price of AES stock; and AES's allegedly unhedged operations in the United Kingdom. By Order dated August 25, 2003, the court consolidated this action with three previously filed actions, discussed immediately above. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

filed against the same defendants in the same court. The lawsuits purport to be filed on behalf of a class of all persons who purchased the Company's common stock and certain of its bonds between April 26, 2001 and February 14, 2002. The complaints purport to allege violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder based on statements or omissions concerning the Company's United Kingdom operations and the alleged effect of the New Electrical Trading Agreements ("NETA") on those operations. On December 4, 2002 defendants moved to transfer the actions to the United States District Court for the Southern District of Indiana. By stipulation dated December 9, 2002, the parties agreed to consolidate these actions into one action. On December 12, 2002 the Court entered an order consolidating the cases under the caption In re AES Corporation Securities Litigation, Master File No. 02-CV-1485. On January 16, 2003, the Court granted defendants' motion to transfer the consolidated action to the United States District Court for the Southern District of Indiana. On September 26, 2003, plaintiffs filed a consolidated amended class action complaint on behalf of a purported class of all persons who purchased the Company's common stock and certain of its bonds between July 27, 2000 and November 8, 2002. The consolidated amended class action complaint, in addition to asserting the same claims asserted in the original complaints, also purports to allege that AES and the individual defendants failed to disclose information concerning AES's role in purported manipulation of the California electricity market, the effect thereof on AES's reported revenues, and AES's purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. Defendants filed a motion to dismiss on November 17, 2003. The motion to dismiss is sub judice. The Company and the individuals believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

discussed immediately above. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

In November 2002, a lawsuit was filed against AES Wolf Hollow, L.P. ("AESWH") and AES Frontier, L.P. ("AESF"), two of our indirect subsidiaries, in the District Court of Hood County, Texas by Stone & Webster, Inc. ("S&W"). S&W contracted to complete the engineering, procurement and construction of the Wolf Hollow project, a gas-fired combined cycle power plant in Hood County, Texas. In its initial complaint, S&W requested a declaratory judgment that a fire that took place at the project on June 16, 2002 constituted a force majeure event and that S&W was not required to pay rebates assessed for associated delays. As part of the initial complaint, S&W also sought to enjoin AESWH and AESF from drawing down on Letters of Credit provided by S&W. The Court refused to issue the injunction. S&W has since amended its complaint three times and joined additional parties, in addition to the claims already mentioned, the current claims by S&W include claims for breach of warranty, wrongful liquidated damages, foreclosure of lien, fraud and negligent misrepresentation. In January 2004, the Company filed a counterclaim against S&W and its parent, the Shaw Group, Inc. ("Shaw"). In February 2004, Shaw filed an answer to the Complaint. The Company and subsidiaries believe that each have meritorious defenses to the claims asserted against us by S&W, and intend to defend the lawsuit vigorously. Trial in this matter is set for March 7, 2005.

Secretariat of Economic Law for the Brazilian Department of Economic Protection and Defense ("SDE") issued a notice of preliminary investigation seeking information from a number of entities, including AES Brasil Energia, with respect to certain allegations arising out of the privatization of Eletropaulo. On August 1, 2003, AES Elpa S.A. responded on behalf of AES-affiliated companies and denied knowledge of these allegations. The SDE has begun a follow-up administrative proceeding as reported in a notice published on October 31, 2003.

AES Florestal, Ltda., ("Florestal") a wholly-owned subsidiary of AES Sul, is a wooden electric utility poles factory located in Triunfo, in the state of Rio Grande do Sul, Brazil. In October 1997 AES Sul acquired Florestal as part of the original privatization transaction by the Government of the State of Rio Grande do Sul, Brazil, that created AES Sul. From 1997 to the present, the chemical compound chromated copper arsenate has been used by Florestal to chemically treat the poles under an operating license issued by the Brazilian government. Prior to the acquisition of Florestal by AES Sul, another chemical, creosote was used to treat the poles. After acquiring Florestal, AES Sul discovered approximately 200 barrels of solid creosote waste on the Florestal property. In 2002 (i) a civil inquiry (Civil Inquiry No. 02/02) was initiated and (ii) a criminal lawsuit was filed in the city of Triunfo's Judiciary both by the Public Prosecutors office of the city of Triunfo. The civil lawsuit was settled in 2003. The criminal lawsuit has been suspended for a period of two years pending a certification of environmental compliance for Florestal and the occurrence of no further violations of environmental regulations. Florestal has hired an independent environmental assessment company to perform an environmental audit of the entire operational cycle at Florestal and to recommend remedial actions if

necessary. Pending the outcome of the environmental audit, AES Sul is not able to estimate the potential financial impact, if any, on AES Sul.

AES Ekibastusz LLP ("AES Ekibastusz"), a subsidiary of the Company, is involved in litigation in Kazakhstan concerning the Maikuben coal mine. AES Ekibastusz is the operator of the AES Ekibastusz power plant located in Kazakhstan. The coal mine was acquired in 2001 and provides coal to the power plant. Because the mine was in bankruptcy proceedings at the time of acquisition, AES Ekibastusz provided approximately US$20 million of financial assistance to the mine and acquired indirect ownership of the mine, as provided in Kazakhstan's bankruptcy legislation. That acquisition was later disputed by several creditors of the mine. After litigation, AES Ekibastusz was successful in having the creditor's claims dismissed by the Kazakhstan courts. In 2003, a new party filed a lawsuit in the local courts of Kazakhstan, claiming that it had succeeded to the rights of one of the creditors whose claims had been dismissed. The plaintiff in the pending lawsuit seeks to have ownership of the coal mine transferred from AES Ekibastusz to the plaintiff.

The Company is also involved in certain claims, suits and legal proceedings in the normal course of business.

The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company does not expect the ultimate resolution of these claims will have a material adverse effect on its financial position or results of operations.

RISKS RELATED TO POWER SALES CONTRACTS—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 case all of, the relevant plant's output over the term of the power sales contract. The remaining term of the power sales contracts related to the Company's power plants range from 5 to 27 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 contracts 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.

Two of these types of contracts at the Company's Warrior Run and Beaver Valley plants are with customers owned by Allegheny Energy, Inc., which has encountered financial difficulties. The Company does not believe the financial difficulties of Allegheny Energy, Inc. will have a material adverse effect on the performance of those customers; however, there can be no assurance that a further deterioration in Allegheny Energy, Inc.'s financial condition will not have a material adverse effect on the ability of those customers to perform their operations. The Company's investment in these subsidiaries was approximately $255 million at December 31, 2003. For the year ended December 31, 2003, the Company recorded $14 million of net income from the two subsidiaries. In 2002, Williams Energy, one commercial customer at three of the Company's subsidiaries, encountered financial difficulties related to its electricity trading operations and has been downgraded below investment grade by a number of ratings agencies. During 2003 the rating was upgraded but still remains below investment grade. There can be no assurance that Williams Energy will continue to meet its contractual commitments. The Company's investment in these subsidiaries was approximately $462 million at December 31, 2003. For the year ended December 31, 2003, the Company recorded $25 million of net income from the three subsidiaries.

Additionally, AES Wolf Hollow, L.P. and AES Granite Ridge, previously reported in the Company's competitive supply segment, have fuel supply agreements with El Paso Merchant Energy L.P. an affiliate of El Paso Corp., which has encountered financial difficulties. The Company does not believe the financial difficulties of El Paso Corp. will have a material adverse effect on El Paso Merchant Energy L.P.'s performance under the supply agreements; however, there can be no assurance that a further deterioration in El Paso Corp's. financial condition will not have a material adverse effect on the ability of El Paso Merchant Energy L.P. to perform its obligations. Both AES Wolf Hollow and AES Granite Ridge were classified as held for sale in fourth quarter of 2003 (see Note 4—Discontinued Operations).

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 were required to purchase wholesale power at higher market prices and to sell it at fixed prices to retail end users. Because the cost of wholesale power exceeded the price the utilities charged 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 a tolling agreement entered into by AES Southland, an AES subsidiary operating in California. But the Company's other California subsidiaries have some exposure to this risk. At December 31, 2003, 2002 and 2001, the Company had receivables of approximately $4 million, $4 million and $13 million, respectively, 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.

RISKS RELATED TO FOREIGN CURRENCIES—AES operates businesses in many foreign environments. Investments in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. The Company's financial position and results of operations have been significantly affected by fluctuations in the value of the Argentine peso, Brazilian Real and Venezuelan Bolivar relative to the U.S. dollar.

Depreciation of the Argentine Peso and Brazilian Real has resulted in foreign currency translation and transaction losses. Appreciation of those currencies has resulted in gains. Conversely, depreciation of the Venezuelan Bolivar has resulted in foreign currency gains and appreciation has resulted in losses. Net foreign currency transaction gains (losses) at the Company's subsidiaries and affiliates in Argentina, Brazil and Venezuela were as follows (in millions):

	Years Ended December 31,
	2003			2002			2001
Argentina	$	37		$	(143	)	$	(31	)
Brazil		130			(357	)		(210	)
Venezuela(1)		(12	)		79			13

Eletropaulo. On May 20, 2003, Eletropaulo received a letter from the President of the Mines and Energy Commission of the House of Representatives of the National Congress. The letter requested that Eletropaulo attend a Public Hearing (the "Public Hearing") at the National Congress to provide information concerning facts in connection with Eletropaulo's privatization. No other specificity regarding the information sought by the Commission was provided in the May 20^th letter. On May 28, 2003, the Public Hearing was postponed until June 12, 2003. On June 12, 2003, a representative of Eletropaulo attended the Public Hearing as requested by the Commission and discussed various issues regarding the electricity market and privatization. On September 17, 2003, the President of Eletropaulo attended another Public Hearing as requested by the Commission and reinforced the importance of Eletropaulo in the electricity sector in Brazil. The Company had a total negative investment in Eletropaulo as of December 31, 2003 of approximately $729 million.

Sul. Sul and AES Cayman Guaiba, a subsidiary of the Company that owns the Company's interest in Sul, are facing near-term debt payment obligations that must be extended, restructured, refinanced or repaid. See Note 9 for debt related information. The Company's total investment in Sul as of December 31, 2003 was approximately $266 million.

The political and economic environment in Venezuela continues to be unstable. The economy is experiencing negative GDP growth (approximately (9)% in 2003), high levels of unemployment, inflation, exchange controls, price controls, and political instability. These circumstances create significant uncertainty surrounding the performance, cash flow and profitability of EDC. However, AES is not required to support the potential cash flow or debt service obligations of EDC. AES's total investment in EDC at December 31, 2003 was approximately $1.9 billion, which is net of foreign currency translation losses.

Effective January 21, 2003, the Venezuelan Government and the Central Bank of Venezuela ("Central Bank") agreed to suspend the trading of foreign currencies and to establish new standards for the foreign currency exchange regime. Then, effective February 5, 2003, the Venezuelan Government and the Central Bank entered into an exchange agreement to govern the Foreign Currency Management Regime, and establish an applicable exchange rate. The exchange agreement established certain conditions including the centralization of the purchase and sale of currencies within the country by the Central Bank, and the incorporation of the Foreign Currency Management Commission ("CADIVI") to administer the execution of the exchange agreement and establish certain procedures and restrictions. The acquisition of foreign currencies is subject to the prior registration of the interested party and the issuance of an authorization to participate in the exchange regime. Furthermore, CADIVI governs the provisions of the exchange agreement, defines the procedures and requirements for the administration of foreign currencies for imports and exports, and authorizes purchases of currencies in the country. The exchange rates set by such agreements were 1,596 Bolivars per U.S. dollar for purchases and 1,600 Bolivars per U.S. dollar for sales. During 2003, CADIVI authorized exchange for the majority of EDC?s debt service and operational U.S. dollar obligations.

Effective February 5, 2004, the Venezuelan Government and the Central Bank issued a Currency Exchange Agreement No. 2 which amends exchange rates established by the above mentioned agreement. The exchange rates set by the new agreement are 1,916 Bolivars per U.S. dollar for purchases and 1,920 Bolivars per U.S. dollar for sales. These actions may impact the ability of EDC to distribute cash to the parent in the future. Further changes in the exchange rate may also result in the reduction of EDC's Net Worth calculated in Venezuelan GAAP below the level established by the covenants in two of the non-recourse debt obligations. As of December 31, 2003, EDC was in compliance with all of its debt covenants.

In 2002, Argentina continued to experience a political, social and economic crisis that has resulted in significant changes in general economic policies and regulations, as well as specific changes in the energy sector. In January and February 2002, many new economic measures were adopted by the Argentine government, including abandonment of the country's fixed dollar-to-peso exchange rate, converting U.S. dollar-denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government also adopted new regulations in the energy sector that have the effect of repealing U.S. dollar-denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos. In 2003, the political and social situation in Argentina showed signs of stabilization, the Argentine peso appreciated to the U.S. dollar and the economy and electricity demand started to recover. Presidential elections and the establishment of a new government regime occurred in May 2003, and the new government may enact changes to the regulations governing the electricity industry. In combination, these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES.

AES has several subsidiaries in Argentina operating in both the competitive supply and growth distribution segments of the electricity business. Eden/Edes and Edelap are growth distribution facilities that operate in the province of Buenos Aires. Generating facilities include Alicura, Parana, CTSN, Rio Juramento, TermoAndes and several other smaller hydro facilities. These businesses are experiencing reduced cash flows arising from the economic and regulatory changes described earlier, and Eden/Edes, Edelap, TermoAndes, and Parana are in default on their project financing arrangements.

The effects of the crisis are not expected to have a significant negative impact on AES's parent cash flow, due primarily to the non-recourse financing structure in place at most of AES's Argentine businesses. The effects of the current circumstances on future earnings are much more uncertain and difficult to predict. At December 31, 2003, AES's total investment in the competitive supply business in Argentina was approximately $111 million and the total investment in the growth distribution business was approximately negative $6 million. These investment amounts are net of foreign currency translation losses.

DERIVATIVES—Certain subsidiaries and an affiliate of the Company entered 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 its counterparties. The Company does not anticipate nonperformance by the counter-parties.

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.

Minority interest includes $60 million and $100 million of cumulative preferred stock of subsidiaries at December 31, 2003 and 2002, respectively. The total annual dividend requirement was approximately $3 million and $5 million at December 31, 2003 and 2002, respectively. Each series of preferred stock is redeemable solely at the option of the issuer at prices between $101 and $118 per share.

SALE OF STOCK—In June 2003, the Company sold 49.5 million shares of common stock at $7.00 per share. Net proceeds from the offering were $334 million.

SHARES ISSUED FOR ACQUISITIONS—In January 2001, the Company issued approximately 9.1 million shares valued at approximately $511 million to fund a portion of the acquisition of Gener. During March 2001, the Company issued approximately 41.5 million shares in the IPALCO pooling-of-interests transaction.

SHARES ISSUED FOR DEBT—During 2003, the Company swapped 12.2 million shares of common stock at an average price of $3.91 per share, for approximately $62.7 million in senior subordinated notes. This resulted in a gain on retirement of debt of approximately $14 million for the year ended December 31, 2003.

During 2002, the Company swapped 21.6 million shares of common stock at an average value of $3.39 per share, for approximately $117.2 million in senior subordinated notes. This resulted in a gain on retirement of approximately $44 million for the year ended December 31, 2002.

RESTRICTED STOCK—The Company issued restricted stock under various incentive stock option plans. Generally, under each plan, shares of restricted common stock with value equal to a stated percentage of participants' base salary are initially awarded at the beginning of a three-year performance period, subject to adjustment to reflect the participants' actual base salary. The shares remain restricted and nontransferable throughout each three-year performance period, vesting in one-third increments in each of the three years following the end of the performance period. At the end of a performance period, awards are subject to adjustment to reflect the Company's performance compared to peer companies. Final awards under the plans can range from zero up to 400% of the initial awards. Vested shares are no longer restricted and may be held or sold by the participant. Compensation expense of $0 million, $0 million and $8 million for 2003, 2002 and 2001, respectively, as measured by the market value of the common stock at the balance sheet date, has been recognized. In January 2001, the final performance evaluation was completed for one of the restricted stocks plans resulting in final awards of an additional 199,000 shares with approximately 101,000 shares becoming fully vested. All shares of restricted stock became fully vested on the date of merger with IPALCO. Under the terms of the restricted stock plan, no additional shares will be awarded.

STOCK OPTIONS—Since 2001, the Company has granted options to purchase shares of common stock during the year under three 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. Generally, stock options issued under this plan become exercisable by employees in as little as one year (100% in one year), or as many as four years (25% each year). At December 31, 2003, 16,944,935 shares were remaining for award under the plans. The maximum term of the options granted is 10 years.

The following table summarizes information about stock options outstanding at December 31, 2003 (in thousands of shares):

ACCUMULATED OTHER COMPREHENSIVE LOSS—The balances comprising accumulated other comprehensive loss are as follows:

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income (loss) from continuing operations. In the table below, income (loss) represents the numerator (in millions) and shares represent the denominator (in millions):

There were approximately 27,963,788 and 28,207,330 and 4,048,700 options outstanding in 2003, 2002 and 2001 that were omitted from the earnings per share calculation because they were anti-dilutive. In 2003, 2002 and 2001, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive.

INCOME TAX PROVISION—The (benefit) expense for income taxes on continuing operations consists of the following (in millions):

		Years Ended December 31,
		2003			2002			2001
Federal:
	Current	$	5		$	—		$	2
	Deferred		(36	)		54			42
State:
	Current		1			6			—
	Deferred		3			(17	)		7
Foreign:
	Current		230			129			200
	Deferred		(9	)		113			59

Total		$	194		$	285		$	310

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 is as follows:

	Years Ended December 31,
	2003		2002		2001
Statutory Federal tax rate	35	%	35	%	35	%
State taxes, net of Federal tax benefit	2		1		1
Taxes on foreign earnings	(26	)	5		2
Valuation allowance	17		(61	)	—
Other-net	2		(1	)	—

Effective tax rate	30	%	(21	)%	38	%

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 carry forwards. 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, 2003, the Company had Federal net operating loss carry forwards for tax purposes of approximately $891 million expiring from 2019 through 2023, Federal general business tax credit carry forwards for tax purposes of approximately $45 million expiring in years 2005 through 2022, and Federal alternative minimum tax credits of approximately $5 million that carry forward without expiration. As of December 31, 2003, the Company had foreign net operating loss carry forwards of approximately $2.1 billion that expire at various times beginning in 2004 and some of which carry forward without expiration, and foreign assets tax credits of approximately $1 million that expire in 2006. The Company had state net operating loss carry forwards as of December 31, 2003 of approximately $785 million expiring in years 2004 through 2023, and state tax credit carry forwards of approximately $3 million expiring in years 2004 through 2010.

The valuation allowance decreased by $228 million during 2003 to $660 million at December 31, 2003. This net decrease was primarily the result of the removal of valuation allowances attributable to companies no longer included in the consolidated financial statements. The valuation allowance also increased due to certain foreign net operating loss carry forwards and capital loss carry forwards, the ultimate realization of which is not known at this time. The Company believes that it is more likely than not the remaining deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income.

	December 31,
	2003			2002
Differences between book and tax basis of property	$	1,581		$	1,399
Other taxable temporary differences		14			127

Total deferred tax liability		1,595			1,526

Operating loss carry forwards		(1,047	)		(814	)
Capital loss carry forwards		(358	)		(348	)
Bad debt and other book provisions		(132	)		(167	)
Retirement costs		(321	)		(388	)
Tax credit carry forwards		(53	)		(96	)
Other deductible temporary differences		(210	)		(520	)

Total gross deferred tax asset		(2,121	)		(2,333	)
Less: valuation allowance		660			888

Total net deferred tax asset		(1,461	)		(1,445	)

Net deferred tax liability	$	134		$	81

Undistributed earnings of certain foreign subsidiaries and affiliates aggregated approximately $1.5 billion and $1.2 billion at December 31, 2003 and 2002, respectively. 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.

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 Company's income tax benefits related to the tax status of these operations are estimated to be $66 million, $40 million and $25 million for the years ended December 31, 2003, 2002 and 2001, respectively.

Income (loss) from continuing operations before income taxes and minority interest consisted of the following:

	Years Ended December 31,
	2003			2002			2001
U.S.	$	(169	)	$	(169	)	$	284
Non-U.S.		809			(1,175	)		530

Total	$	640		$	(1,344	)	$	814

PROFIT SHARING AND STOCK OWNERSHIP PLANS—The Company sponsors one defined contribution plan, qualified under section 401 of the Internal Revenue Code, which is available to eligible AES employees. The plan provides 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 ratably over a five-year period ending on the 5th anniversary of their hire date. Company contributions to the plans were approximately $14 million, $15 million and $13 million for the years ended December 31, 2003, 2002 and 2001, respectively.

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 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). Shares of stock were distributed under the Plan in 2003. No stock associated with distributions was issued during 2002 or 2001 under such plan.

Common stock units held under the AES deferred compensation plans do not represent issued shares of common stock. The deferred compensation liabilities related to such plans were approximately $1 million as of December 31, 2003 and 2002, and were convertible into approximately 407,000 and 857,000 shares at December 31, 2003 and 2002, respectively. For those electing to participate in the deferred compensation plans the amount of the stock unit award is based on the compensation and average stock price during the compensation period. The liabilities will only be settled in stock, except cash settlement is required in the event of recapitalization transactions, as defined in the plan documents.

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 cannot be forfeited. 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. Of the thirteen defined benefit plans, two are at U.S. subsidiaries and the remaining are at foreign subsidiaries. Prior to the consolidation of Eletropaulo in February 2002, the Company did not have significant benefit obligations from its foreign plans. Since the consolidation of Eletropaulo, the benefit obligation from foreign plans has become significant relative to the total; therefore, the 2003 and 2002 amounts distinguish between the U.S. and foreign plans.

All but three of the Company's subsidiaries use a December 31 measurement date. The remaining three subsidiaries use either a November 30 or October 31 measurement date.

Significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost are as follows:

A subsidiary of the Company has a defined benefit plan which has a benefit obligation of $443 million and $411 million at December 31, 2003 and 2002, respectively, and uses salary bands to determine future benefit costs rather than rate of compensation increases. As such, rates of compensation increase in the table above do not include amounts relating to this specific defined benefit plan.

Total pension cost for the years ended December 31, 2003, 2002 and 2001 includes the following components (in millions):

The changes in the benefit obligation of the plans combined for the years ended December 31, 2003 and 2002 are as follows (in millions):

The changes in the plan assets of the plans combined for the years ended December 31, 2003 and 2002 are as follows (in millions):

The funded status of the plans combined for the years ended as of December 31, 2003 and 2002 are as follows (in millions):

At December 31, 2003, the aggregate benefit obligation and aggregate fair value of plan assets for plans with benefit obligations in excess of plan assets were $2,794 million and $1,460 million, respectively. All of the Company's plans at December 31, 2002 had benefit obligations exceeding the fair value of the related plan's assets.

At December 31, 2003 and 2002, the aggregate accumulated benefit obligation was $2,758 million and $2,267 million, respectively, and the aggregate fair value of plan assets was $1,460 million and $1,005 million, respectively for plans with accumulated benefit obligation in excess of plan assets.

The scheduled cash flows for U.S. and foreign employer contributions, benefit payments and estimated future payments are:

	U.S.		Foreign
Employer Contributions:
2002	$	18	$	145
2003	$	98	$	145
2004 (estimated)	$	50	$	148
Benefit Payments:
2002	$	30	$	120
2003	$	30	$	159
Estimated Future Payments:
2004	$	30	$	184
2005	$	31	$	189
2006	$	31	$	196
2007	$	22	$	201
2008	$	32	$	207
2009-2014	$	157	$	1,158

The Company's target allocation for 2004 and pension plan asset allocation at December 31, 2003, and 2002 are as follows:

	Target Allocation		Percentage of Plan Assets as of December 31,
	2004		2003		2002
Asset Category	2004		2003		2002
Asset Category	U.S.	Foreign	U.S.	Foreign	U.S.	Foreign
Equity Securities	55-60%	19-60%	46%	25%	55%	22%
Debt Securities	40%	40-76%	45%	70%	32%	71%
Real Estate	5%	3-6%	5%	3%	0%	5%
Other	0%	%	4%	2%	13%	2%

Total			100%	100%	100%	100%

Consistent with the above, the allocation is reviewed intermittently to determine a suitable asset allocation which seeks to control risk through portfolio diversification and takes into account, among possible other factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends.

The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk. Our assumed asset allocation uses a lower exposure to equities to more closely match market conditions and near term forecasts. One subsidiary employs an asset liability management program which evaluates the asset allocation semi-annually and forecasts returns over the next 10 years.

From November 2000 through September 2001, a subsidiary of the Company implemented several Voluntary Early Retirement Programs ("VERP"). These programs offer enhanced retirement benefits upon early retirement to eligible employees. The VERP was available to all employees, except officers, whose combined age and years of service totaled at least 75 on June 30, 2001. Participation was limited to, and subsequently accepted by, 550 qualified employees. Participants elected actual retirement dates in 2001. Additionally, the post-retirement benefits will be provided to VERP retirees until age 55 at which time they will be eligible to receive benefits from the independent Voluntary Employee Benefit Association trustee. The subsidiary recognized $0 million, $0 million and $19 million of pre-tax non-cash pension benefit costs for the VERP in 2003, 2002 and 2001, respectively.

In August 2002, a subsidiary of the Company implemented a VERP. The VERP was offered to 56 qualified plan participants. The 27 participants that accepted the offer retired effective September 1, 2002. The subsidiary recognized $3 million of pre-tax non-cash benefit costs for the VERP in 2002.

The Company operates in four business segments: contract generation, competitive supply, large utilities and growth distribution businesses. Contract generation businesses are businesses that supply wholesale electricity under long-term contracts for more than 75% of their output, and these businesses generally have little exposure to commodity price risk. Competitive supply businesses are businesses that supply wholesale electricity pursuant to short-term contracts or into spot electricity markets. Competitive supply businesses are generally exposed to commodity price risk. Large utility businesses are utilities of significant size that maintain a monopoly franchise within a defined service area, and these businesses are generally subjected to extensive regulation in their respective jurisdiction. Growth distribution businesses are distribution businesses that offer significant potential for growth because they face particular challenges related to operational difficulties such as outdated equipment, significant non-technical losses, cultural problems associated with customer safety and non-payment, emerging economies, less stable governments or regulatory regimes, or are located in a developing nation that allow for operating improvements that would result in financial performance improvement that are typically greater than those seen in the large utility business. Although the nature of the product is the same, the segments are differentiated by the nature of the customers, operational differences and risk exposure. All balance sheet information for businesses that were discontinued during the year are segregated and are shown separately in the chart below. All income statement related information is shown in the line "Discontinued operations" in the accompanying consolidated statements of operations.

The accounting policies of the four 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 its business segments. Depreciation and amortization at the business segments are included in the calculation of gross margin. Corporate depreciation and amortization is reported within "Corporate and business development office expenses" in the consolidated statements of operations. Equity in earnings is used to evaluate the performance of businesses that are significantly influenced by the Company. Sales between the segments 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 consolidated 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, the fair value is estimated using quoted market prices or discounted cash flow analyses. 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 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, 2003 and 2002 are as follows (in millions):

Amounts in the table above include the carrying amount and fair value of financial instruments of discontinued operations and assets held for sale.

As of December 31, 2003, discontinued operations and assets held for sale had non-recourse debt with a carrying amount and fair value of $636 million, foreign currency derivatives, net (assets), with a carrying amount and fair value of $45 million, interest rate swaps (liabilities) with a carrying amount and fair value of $95 million and interest rate caps and floors, net (liabilities), with a carrying amount and fair value of $39 million.

The fair value estimates presented herein are based on pertinent information as of December 31, 2003 and 2002. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2003.

Consolidation of Variable Interest Entities—On December 24, 2003 the FASB issued Interpretation No. 46 (Revised 2003), Consolidation of Variable Interest Entities ("FIN 46(R)"). FIN 46(R) partially deferred the effective date of FIN 46 for certain entities, and makes several other major changes to FIN 46 which include, an improved definition of variable interest, and an exemption for many entities defined as businesses in the Interpretation. FIN 46(R) also eliminated bias against decision maker fees and certain guarantee fees which were previously treated as variable interests in a variable interest entity, the effect of which is that decision makers and certain guarantors are less likely to become primary beneficiaries. The Company applied FIN 46 in its financial statements relating to its interest in variable interest entities or potential variable interest entities commonly referred to as special-purpose entities as of December 31, 2003. The Company is required to apply FIN 46(R) for all other types of entities in its financial statements for the quarter ending March 31, 2004. The effects FIN 46(R) will have on results of operations and financial position are currently being evaluated. The Company does not believe that the adoption and application of FIN 46(R) will result in the consolidation of any previously unconsolidated entities or material additional disclosure. Application of FIN 46(R) may cause the Company to discontinue consolidation of certain subsidiaries.

The Company completed sales of certain assets after the year ended December 31, 2003.

El Faro. In 1999 the Company initiated a development project in Honduras which consisted of a 580-MW combined-cycle power plant fueled by natural gas; a liquefied natural gas import terminal with storage capacity of one million barrels; and transmission lines and line upgrades (together "El Faro" or "the Project"). During April 2003, after consideration of existing business conditions and future opportunities, the Company elected to offer the Project for sale. In the second quarter of 2003, the Company determined that, in accordance with Statement of Financial Accounting Standards No. 144, the Project was deemed to be impaired since the carrying amount of the Company's investment in the Project exceeded its fair value. As a result during the second quarter of 2003, the Company wrote off capitalized costs of approximately $20 million associated with the Project. On January 12, 2004, the Company completed the sale of the project for nominal consideration.

Whitefield. In the fourth quarter of 2003, the Company classified AES Whitefield as held for sale in accordance with SFAS No. 144. The Company completed the sale of 100% of its ownership interest in AES Whitefield on March 9, 2004. The proceeds from the sale were nominal.

The Company completed the refinancing of certain of its outstanding debt at December 31, 2003.

AES Elpa and AES Transgas. During 2003 the Company was involved in negotiations with the Brazilian National Development Bank ("BNDES") and its wholly owned subsidiary, BNDES Participações S.A. ("BNDESPAR"), to restructure the outstanding indebtedness of the Company's Brazilian subsidiaries AES Transgas and AES Elpa, the holding companies of Eletropaulo ("BNDES Debt Restructuring"). Agreement on the BNDES Debt Restructuring was reached on December 22, 2003. On January 19, 2004 and on January 23, 2004 approval was received on the BNDES Debt Restructuring from both ANEEL and the Brazilian Central Bank, respectively. The transaction became effective on January 30, 2004 after approval from ANEEL and the Central Bank of Brazil as well as payment of $90 million by AES. Under the BNDES Debt Restructuring, all of the Company's equity capital interests in Eletropaulo, AES Uruguaiana Empreendimentos Ltda. ("AES Uruguaiana") and AES Tiete S.A. ("AES Tiete") have been transferred to Brasiliana Energia, S.A. ("Brasiliana Energia"), a holding company created for the debt restructuring. Pursuant to the shareholders' agreement signed between AES and BNDES, AES controls Brasiliana Energia through its ownership of a majority of the voting shares of the company. AES owns 50.01% of the common shares and BNDES owns 49.99% of the common shares plus non-voting preferred shares that provides BNDES with approximately 53.84% of the total capital of Brasiliana Energia.

Following the completion of the BNDES Debt Restructuring process, the remaining outstanding debt owed to BNDESPAR by AES Elpa and AES Transgas is convertible debentures (the "Convertible Debentures") of approximately $510 million. These debentures are non-recourse debt to AES. The Convertible Debentures bear interest at a rate of 9.0% per annum, indexed in U.S. dollars, and will amortize over an 11 year period. In the event of a default under the Convertible Debentures, they can be converted by BNDESPAR into common shares of Brasiliana Energia in an amount sufficient to give BNDESPAR operational and managerial control of Brasiliana Energia. Under the terms of the BNDES Debt Restructuring, the Company will, subject to certain protective rights granted to BNDESPAR under the Restructuring Documents, retain operational and managerial control of Eletropaulo, AES Uruguaiana and AES Tiete as long as no default under the Convertible Debentures occurs.

Eletropaulo. Due to financial covenant and other defaults under Eletropaulo loan agreements, Eletropaulo's commercial lenders have the right to call due approximately $787 million of indebtedness, as of December 31, 2003. In December 2003, Eletropaulo reached an agreement with its private creditors to reschedule this outstanding debt over the next five years (see Note 9). The agreement with Eletropaulo creditors resolves all outstanding defaults and accelerations with its operating company lenders. As the result of this transaction, 70% of the reprofiled debt will be denominated in Brazilian Reais. Closing of the Eletropaulo reprofiling transaction, which is under negotiation, is subject to definitive documentation that is expected to be entered into on or shortly after March 15, 2004. At December 31, 2003, this $787 million of indebtedness is classified as current on the accompanying consolidated balance sheet.

IPALCO. On January 13, 2004, IPL issued $100 million of 6.60% first mortgage bonds due January 1, 2034. The net proceeds of approximately $99 million were used to retire $80 million of 6.05% first mortgage bonds due February 2004 and to reimburse IPL's treasury for expenditures previously incurred in connection with its capital expenditure program.

Gener. Gener is currently pursuing a plan to refinance $700 million of its indebtedness that matures in 2005 and 2006. On February 23, 2004 AES Gener S.A. ("Gener") announced details relating to the restructuring of Gener. Pursuant to the restructuring, which is expected to be completed by the first week in April, (i) Inversiones Cachagua Ltda. ("Cachagua"), a holding company of Gener, will settle its intercompany loan with Gener (transaction completed on February 27, 2004); (ii) Gener will issued approximately $400 million of bonds in the international capital markets (transaction completed on March 12, 2004). In December 2003 and February 2004 in connection with the bond offering, Gener executed a series of treasury lock agreements to reduce its exposure to the underlying interest rate of the notes. These treasury lock agreements will not be reflected as cash flow hedges and as of March 10, 2004 were terminated by Gener. The fair market value of these transactions as of such date represented a loss of approximately $21.3 million before income taxes; (iii) AES will sell a portion of the common shares of Gener owned by Cachagua in the Chilean and international equity markets; (iv) Gener will offer up to $125 million of new common shares to its shareholders. All the funds previously described will be used to repurchase up to $700 million of Gener's notes. In addition, Gener is in the process of restructuring the debt of its subsidiaries TermoAndes S.A. ("TermoAndes") and InterAndes S.A. ("InterAndes"). Under the terms of an agreement reached on February 27, 2004, noteholders will receive a cash payment in exchange for an extension of the loan to 2010. None of the financing is committed, so there can be no assurance that the refinancing will occur upon these terms or at all.

Other. On February 4, 2004, the Company called for redemption $155,049,000 aggregate principal amount of its outstanding 8% Senior Notes due 2008, which represents the entire outstanding principal amount of the 8% Senior Notes due 2008, and $34,174,000 aggregate principal amount of its outstanding 10% secured Senior Notes due 2005. The 8% Senior Notes due 2008 and the 10% secured Senior Notes due 2005 will be redeemed on March 8, 2004 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date. The mandatory redemption of the 10% secured Senior Notes due 2005 is being made with a portion of the Company's "Adjusted Free Cash Flow" (as defined in the indenture pursuant to which the notes were issued) for the fiscal year ended December 31, 2003 as required by the indenture and will be made on a pro rata basis.

On February 10, 2004 we priced an offering of $500 million of unsecured senior notes. The unsecured senior notes mature on March 1, 2014 and are callabale at our option at any time at a redemption price equal to 100% of the principal amount of the unsecured senior notes plus a make-whole premium. The unsecured senior notes were issued at a price of 98.288% and pay interest semi-annually at an annual coupon rate of 7.75%.

Dominican Republic. On January 27, 2004, the Company received notice of a "Formulation of Charges" filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the "Formulation of Charges", the Superintendence asserts that the existence of three-generation companies (Empresa Generadora de Electricidad Itabo, S.A., Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A.) in the Dominican Republic, violates certain antitrust provisions of the General Electricity law of the Dominican Republic. On February 10, 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic (the "Court") an action seeking injunctive relief based on several constitutional due process violations contained in the "Formulation of Charges" (the "Constitutional Injunction"). On or about February 24, 2004, the Court granted the Constitutional Injunction and ordered the immediate cease of any effects of the "Formulation of Charges" and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. On March 1, 2004, the Superintendence of Electricity appealed the Court's decision. No hearing date has been scheduled for the appeal.

Chile. On February 18, 2004, AES Gener S.A. ("Gener SA"), a subsidiary of the Company, filed a lawsuit in the Federal District Court for the Southern District of New York (the "Lawsuit"). Gener SA is co-venturer with Coastal Itabu, Ltd ("Coastal") in Empressa Generadors de Electricidad Itabu, S.A. ("Itabu"), a Dominican Republic electric generation Company. The lawsuit sought to enjoin the efforts initiated by Coastal to hire an alleged "independent expert", purportedly pursuant to the Shareholder Agreement between the parties, to perform a valuation of Gener SA's aggregate interests in Itabu. Coastal asserts that Gener SA has committed a material breach under the parties' Shareholder Agreement and, therefore, Gener is required if requested by Coastal to sell its aggregate interests in Itabu to Coastal at price equal to 75% of the independent expert's valuation. Coastal claims a breach occurred based on alleged violations by Gener SA of purported antitrust laws of the Dominican Republic. Gener SA disputes that any default has occurred. On March 11, 2004, upon motion by Gener SA, the court in the Lawsuit enjoined the evaluation being performed by the "expert" and ordered the parties to arbitration. On March 11, 2004, Gener SA commenced arbitration proceedings.

Argentina. Pursuant to the pesification established by the Public Emergency Law and related decrees in Argentina, since the beginning of 2002, the Company's subsidiary Termoandes has converted its obligations under its gas supply and gas transportation contracts into pesos, while its income from its electricity exports remains accounted for in U.S. dollars. In accordance with the Argentine regulations, payments must be made in Argentine pesos at a 1:1 exchange rate. The gas suppliers have objected to the payment in pesos. On January 30, 2004, the consortium of gas suppliers, comprised Tecpetrol S.A., Mobil Argentina S.A. and Compania General de Combustibles S.A., presented a demand for arbitration at the ICC (International Chamber of Commerce) requesting the re-dollarization of the gas price. The arbitration seeks approximately $10,000,000 for past gas supplies. On March 11, 2004, TermoAndes filed with the ICC a response to the arbitration demand. The arbitration is ongoing.

Dominican Republic. Los Mina, a wholly owned subsidiary of AES, did not make a $20 million revolving loan payment under its existing credit agreement due March 11, 2004. An amendment to the existing credit agreement is being negotiated with the lenders. This amendment would extend the maturity and increase the interest rate of the loan. The amendment is expected to be completed by the end of March 2004. This payment default represents a cross default under the Andres credit agreement if an amendment is not obtained. As of December 31, 2003, the debt for both of these subsidiaries was reported as current in the accompanying balance sheet. See Note 9—Long-Term Debt.

The following table summarizes the unaudited quarterly statements of operations for the Company for 2003 and 2002 (in millions, except per share amounts). Additionally, the amounts have been adjusted to report the impact of our classification of certain businesses during the twelve months ended December 31, 2003 as discontinued operations pursuant to SFAS No. 144.

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

There were no changes in or disagreements on any matters of accounting principles or financial disclosure between us and our independent auditors.

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in our Company's Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Also, we have investments in certain unconsolidated entities. As we do not control or manage these entities, the disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries.

As of December 31, 2003, we carried out the evaluation required by paragraph (b) of Exchange Act Rules 13a-15 or 15d-15, under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) or 15d-15(e). Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective.

Based on the evaluation conducted by management, including the Chief Executive Officer and the Chief Financial Officer, there have been no significant changes in our internal controls during the fourth quarter of 2003 that have materially affected, or are reasonably likely to materially affect the internal controls. As a result of the changes implemented in June 2003, instead of being required to disclose significant changes in internal controls subsequent to the date of their evaluation, companies must disclose changes that occurred during the fiscal quarter covered by the report.

The Securities and Exchange Commission's Rule 10b5-1 permits directors, officers and other key personnel to establish purchase and sale programs. The rule permits such persons to adopt written plans at a time before becoming aware of material nonpublic information and to sell shares according to a plan on a regular basis (for example, weekly or monthly), regardless of any subsequent nonpublic information they receive. Rule 10b5-1 plans allow systematic, pre-planned sales that take place over an extended period and should have a less disruptive influence on the price of our stock. Plans of this type inform the marketplace about the nature of the trading activities of our directors and officers. We recognize that our directors and officers may have reasons totally unrelated to their assessment of the company or its prospects in determining to effect transaction in our common stock. Such reasons might include, for example tax and estate planning, the purchase of a home, the payment of college tuition, the establishment of a trust, the balancing of assets, or other personal reasons.

Mr. Paul T. Hanrahan has adopted a trading plan pursuant to Rule 10b5-1. The plan covers 232,000 option shares issued pursuant to option grants awarded in February 1994 that expire in February 2005.

Previously Mr. Roger W. Sant and Mr. Robert F. Hemphill Jr. adopted 10b5-1 plans. Mr. Sant amended his plan to sell an additional 1.2 million AES shares through 2004. To date 1.1 million AES shares have been sold pursuant to Mr. Sant's plan and an additional 1.8 million AES shares remain to be sold under the plan.

Certain information regarding executive officers required by this Item is set forth as a supplementary item in Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this Item, to the extent not included above, will be contained in our Proxy Statement for the Annual Meeting of Shareholders to be held on April 28, 2004 and is hereby incorporated by reference.

See the information contained under the captions "Compensation of Executive Officers" and "Compensation of Directors" of the Proxy Statement for the Annual Meeting of Stockholders of the of the Registrant to be held on April 28, 2004 which is incorporated herein by reference.

See the information contained under the caption "Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers" of the Proxy Statement for the Annual Meeting of Shareholders of the Registrant to be held on April 28, 2004, which information is incorporated herein by reference.

Except for the information concerning equity compensation plans below, the information required by Item 12 is incorporated by reference to the Company's 2004 Proxy Statement under the caption "Security Ownership of Certain Beneficial Owners and Management."

The following table provides information about shares of AES common stock that may be issued under AES's equity compensation plans, as of December 31, 2003:

Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2003)

See the information contained under the caption "Related Party Transactions" of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 28, 2004, which information is incorporated herein by reference.

The information required by this Item will be contained in our Proxy Statement for the Annual Meeting of Shareholders to be held on April 28, 2004 and is hereby incorporated by reference.

The Company filed the following reports on Form 8-K during the quarter ended December 31, 2003. Information regarding the items reported on is as follows:

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
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.

Reclassifications—Certain reclassifications have been made to conform with the 2003 presentation.

FUTURE MATURITIES OF DEBT—Scheduled maturities of total debt for continuing operations at December 31, 2003 are (in millions):

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

GUARANTEES—In connection with certain of its project financing, acquisition, and power purchase agreements, the Company 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 and other obligations discussed below, were limited as of December 31, 2003, by the terms of the agreements, to an aggregate of approximately $515 million representing 55 agreements with individual exposures ranging from less than $1 million up to $100 million. Of this amount, $147 million represents credit enhancements for non-recourse debt, and $38 million commitments to fund its equity in projects currently under development or in construction.

LETTERS OF CREDIT—At December 31, 2003, the Company had $89 million in letters of credit outstanding representing 9 agreements with individual exposures ranging from less than $1 million up to $36 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. The Company pays a letter of credit fee ranging from 0.5% to 5.00% per annum on the outstanding amounts. In addition, the Company had $4 million in surety bonds outstanding at December 31, 2003.

Delaware		54 1163725
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1001 North 19th Street 20^th Floor Arlington, Virginia (Address of principal executive offices)		22209 (Zip Code)

Distribution Facilities	Year of acquisition	Geographic Location	Approximate Number of Customers Served	Approximate Gigawatt Hours	AES Equity Interest (percent)
*Asia*
Eastern Kazakhstan REC (2)	1999	Kazakhstan	280,000	1,000	0
Semipalatensk REC (2)	1999	Kazakhstan	180,000	1,000	0

Generation Facilities	Dominant Fuel	Year of Acquisition or Commencement of Commercial Operations	Geographic Location	Gross MW	AES Equity Interest (percent)
*North America*
IPALCO-Georgetown	Gas	2001	USA	79	100
IPALCO-Eagle Valley	Coal	2001	USA	341	100
IPALCO-Petersburg	Coal	2001	USA	1,716	100
IPALCO-Harding Street	Coal	2001	USA	1,102	100
*Caribbean*
EDC-generation (4 plants)	Gas/Oil	2000	Venezuela	2,616	86

Distribution Facilities	Year of acquisition	Geographic Location	Approximate Number of Customers Served	2003 Approximate Gigawatt Hours	AES Equity Interest (percent)
*North America*
IPALCO	2001	USA	450,000	15,700	100
*South America*
Eletropaulo (1)	1998	Brazil	5,050,000	32,800	70
*Caribbean*
EDC-distribution	2000	Venezuela	1,000,000	10,400	86

Generation Facilities		Dominant Fuel		Year of Acquisition or Commencement of Commercial Operations		Geographic Location		Gross MW		AES Equity Interest (percent)
*Europe/Africa*
SONEL		Hydro		2001		Cameroon		850		56

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		New York Stock Exchange
4.50% Junior Subordinated Debentures Due 2005		New York Stock Exchange
AES Trust III, $3.375 Trust Convertible Preferred Securities		New York Stock Exchange

ITEM 1. BUSINESS			3
	A.	Overview	3
	B.	How to Contact AES and Sources of Other Information	3
	C.	Operating Segments	3
	D.	Customers	12
	E.	Employees	12
	F.	Executive Officers	13
	G.	Regulatory Matters	14
ITEM 2. PROPERTIES			26
ITEM 3. LEGAL PROCEEDINGS			26
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS			33
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDERS MATTERS			34
	A.	Market Information	34
	B.	Holders	34
	C.	Dividends	34
ITEM 6. SELECTED FINANCIAL DATA			35
ITEM 7. MANAGEMENTS' DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			36
	A.	Executive Summary/Overview	36
	B.	Strategic Initiatives Affecting Results of Operations	37
	C.	Critical Accounting Estimates	41
	D.	New Accounting Pronouncements	45
	E.	Results of Operations	46
	F.	Capital Resource and Liquidity	58
	G.	Cautionary Statements and Risk Factors	65
	H.	Derivatives and Energy Trading Activities	68
	I.	Related Party Transactions	68
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			69
	A.	Overview Regarding Market Risks	69
	B.	Interest Rate Risks	69
	C.	Foreign Exchange Rate Risk	69
	D.	Commodity Price Risk	69
	E.	Value at Risk	69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			71

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			140
ITEM 9A. CONTROLS AND PROCEDURES			140
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT			141
ITEM 11. EXECUTIVE COMPENSATION			141
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS			141
	A.	Security Ownership of Certain Beneficial Owners and Management	141
	B.	Security Ownership of Directors and Executive Officers	141
	C.	Changes in Control	141
	D.	Securities Authorized for Issuance Under Equity Compensation Plans	142
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			142
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES			142
PART IV
ITEM 15. EXHIBITS FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K			143
	A.	Financial Statements and Exhibits	143
	B.	Reports on Form 8-K	143
	C.	Exhibits	143
	D.	Financial Statement Schedules	145
SIGNATURES			146

Generation Facilities	Dominant Fuel	Year of Acquisition or Commencement of Commercial Operations	Geographic Location	Gross MW	AES Equity Interest (percent)
*North America*
Kingston	Gas	1997	Canada	110	50
Beaver Valley	Coal	1987	USA	125	100
Thames	Coal	1990	USA	181	100
Shady Point	Coal	1991	USA	320	100
Hawaii	Coal	1992	USA	203	100
Southland-Alamitos	Gas	1998	USA	1,986	100
Southland-Huntington Beach	Gas	1998	USA	452	100
Southland-Huntington Beach 3&4	Gas	2003	USA	452	100
Southland-Redondo Beach	Gas	1998	USA	1,334	100
Warrior Run	Coal	2000	USA	180	100
Hemphill	Biomass	2001	USA	14	67
Mendota	Biomass	2001	USA	25	100
Ironwood	Gas	2001	USA	705	100
Red Oak	Gas	2002	USA	832	100
Placerita	Gas	1989	USA	120	100
Delano	Biomass	2001	USA	50	100

*South America*
Gener-TermoAndes	Gas	2000	Argentina	643	99
Uruguaiana (1)	Gas	2000	Brazil	639	100
Tiete (10 plants) (1)	Hydro	1999	Brazil	2,650	52
GENER-Norgener	Coal	2000	Chile	277	99
GENER-Centrogener (8 plants)	Hydro/Coal/Oil	2000	Chile	782	99
GENER-Electrica de Santiago	Gas	2000	Chile	379	89
GENER-Energia Verde	Biomass	2000	Chile	42	99
GENER-Guacolda	Coal	2000	Chile	304	49
*Europe and Africa*
Bohemia	Coal	2001	Czech Republic	50	100
Elsta	Gas	1998	Netherlands	405	50
Ebute	Gas	2001	Nigeria	306	95
Kilroot	Coal	1992	UK	520	97
Tisza II	Gas/Oil	1996	Hungary	860	100
Cartagena	Gas	2006	Spain	1,200	71
*Asia*
Cili	Hydro	1996	China	26	51
Wuhu	Coal	1996	China	250	25
Chengdu	Gas	1997	China	48	35
Hefei	Oil	1997	China	115	70
Jiaozuo	Coal	1997	China	250	70
Aixi	Coal	1998	China	50	71
Yangcheng	Coal	2001	China	2,100	25
OPGC	Coal	1998	India	420	49
Lal Pir (2)	Oil	1997	Pakistan	365	55
Pak Gen (2)	Oil	1998	Pakistan	365	55
Barka (2)	Gas	2003	Oman	427	52
Ras Laffan	Gas	2003	Qatar	416	55
Kelanitissa	Diesel	2003	Sri Lanka	168	90
*Caribbean*
Merida III	Gas	2000	Mexico	495	55
Puerto Rico	Coal	2002	USA	454	100
Itabo	Coal/Gas	2000	Dominican Republic	433	25
Los Mina	Gas	1997	Dominican Republic	210	100
Andres	Gas	2003	Dominican Republic	304	100

Generation Facilities	Dominant Fuel	Year of Acquisition or Commencement of Commercial Operations	Geographic Location	Gross MW	AES Equity Interest (percent)
*North America*
Deepwater	Pet Coke	1986	USA	160	100
NY-Cayuga	Coal	1999	USA	306	100
NY-Greenidge	Coal	1999	USA	161	100
NY-Somerset	Coal	1999	USA	675	100
NY-Westover	Coal	1999	USA	126	100
Whitefield (1)(3)	Biomass	2001	USA	16	100
Granite Ridge (1)	Gas	2003	USA	720	100
Wolf Hollow (1)	Gas	2003	USA	730	100
*South America*
San Nicolás-CTSN	Coal	1993	Argentina	650	88
Rio Juramento-Cabra Corral	Hydro	1995	Argentina	102	98
Rio Juramento-El Tunal	Hydro	1995	Argentina	10	98
San Juan-Sarmiento	Gas	1996	Argentina	33	98
San Juan-Ullum	Hydro	1996	Argentina	45	98
Quebrada de Ullum	Hydro	1998	Argentina	45	100
Caracoles	Hydro	2006	Argentina	185	100
Alicura	Hydro	2000	Argentina	1,040	100
Central Dique	Gas	1998	Argentina	68	51
Parana	Gas	2001	Argentina	845	100
*Europe and Africa*
Borsod	Coal	1996	Hungary	171	100
Tiszapalkonya	Coal	1996	Hungary	250	100
Ottana	Oil	2001	Italy	140	100
Indian Queens	Oil	1996	UK	140	100
*Asia*
Ekibastuz	Coal	1996	Kazakhstan	4,000	100
Altai-Shulbinsk Hydro	Hydro	1997	Kazakhstan	702	100
Altai-Sogrinsk CHP	Coal	1997	Kazakhstan	301	100
Altai-Ust Kamenogorsk Heat Nets (2)	Heat DistCo	1998	Kazakhstan	260	0
Altai-Ust-Kamenogorsk CHP	Coal	1997	Kazakhstan	1,356	100
Altai-Ust-Kamenogorsk Hydro	Hydro	1997	Kazakhstan	331	100
*Caribbean*
Bayano	Hydro	1999	Panama	248	49
Bayano Expansion	Hydro	2004	Panama	12	49
Chiriqui-La Estrella	Hydro	1999	Panama	42	49
Chiriqui-Los Valles	Hydro	1999	Panama	48	49
Chiriqui-Esti	Hydro	2003	Panama	120	49
Panama-GT	Oil	1999	Panama	43	49
Chivor	Hydro	2000	Colombia	1,000	99
Colombia I (1)	Gas	2000	Colombia	90	69

Distribution Facilities	Year of acquisition	Geographic Location	Approximate Number of Customers Served	2003 Approximate Gigawatt Hours	AES Equity Interest (percent)
*South America*
Sul (1)	1997	Brazil	975,000	7,300	98
Eden	1997	Argentina	278,500	1,800	90
Edes	1997	Argentina	145,000	600	90
Edelap	1998	Argentina	280,000	2,100	90
*Europe and Africa*
SONEL	2001	Cameroon	505,300	3,700	56
Kievoblenergo	2001	Ukraine	811,000	3,800	75
Rivnooblenergo	2001	Ukraine	403,000	1,700	75
*Caribbean*
CLESA	1998	El Salvador	251,800	600	64
EDE Este (2)	1999	Dominican Republic	293,000	1,900	50
CAESS	2000	El Salvador	473,000	1,700	75
DEUSEM	2000	El Salvador	49,000	100	74
EEO	2000	El Salvador	187,800	300	89

2003	High		Low		2002	High		Low
First Quarter	$	4.04	$	2.72	First Quarter	$	17.84	$	4.11
Second Quarter		8.37		3.75	Second Quarter		9.17		3.55
Third Quarter		7.70		5.91	Third Quarter		4.61		1.56
Fourth Quarter		9.50		7.57	Fourth Quarter		3.57		0.95

			December 31, 2003			December 31, 2002			December 31, 2001
			Year to Date Amount		% of Total Revenues	Year to Date Amount		% of Total Revenues	Year to Date Amount		% of Total Revenues
			(in $millions)
Large Utilities:
	North America		$	832	10%	$	818	11%	$	836	13%
	South America			1,861	22%		1,698	23%		— —
	Caribbean*			608	8%		634	9%		805	13%

		Total Large Utilities	$	3,301	40%	$	3,150	43%	$	1,641	26%

Growth Distribution:
	South America		$	415	5%	$	263	4%	$	781	12%
	Caribbean*			343	4%		311	4%		321	5%
	Europe/Africa			368	4%		294	4%		144	2%

		Total Growth Distribution	$	1,126	13%	$	868	12%	$	1,246	20%

		Total Regulated Revenues	$	4,427	53%	$	4,018	54%	$	2,887	46%

			December 31, 2003				December 31, 2002					December 31, 2001
			Year to Date Amount			Operating Gross Margin %	Year to Date Amount			Operating Gross Margin %		Year to Date Amount			Operating Gross Margin %
			(in $millions)
Large Utilities:
	North America		$	282		34%	$	302		37	%	$	287		34	%
	South America			252		14%		165		10	%		(14	)	—	%
	Caribbean*			229		38%		220		35	%		342		42	%

		Total Large Utilities	$	763		23%	$	687		22	%	$	615		37	%

Growth Distribution:
	South America		$	79		19%	$	(61	)	(23	)%	$	249		32	%
	Caribbean*			71		21%		53		17	%		51		16	%
	Europe/Africa			36		10%		26		9	%		(9	)	(6	)%
	Asia			(3	)	—%		(3	)	—	%		(3	)	—	%

		Total Growth Distribution	$	183		16%	$	15		2	%	$	288		23	%

		Total Regulated Gross Margin	$	946		21%	$	702		17	%	$	903		31	%

	December 31,
	2003		2002			2001		2000		1999
	(in millions)
Balance Sheet Data:
Total assets	$	29,904	$	34,607		$	37,146	$	33,355	$	23,537
Non-recourse debt (long-term)		10,930		10,044			10,787		9,306		6,086
Non-recourse debt (long-term)—Discontinued operations		—		4,126			4,037		3,557		3,435
Recourse debt (long-term)		5,862		6,755			5,891		4,686		3,485
Stockholders' equity (deficit)		645		(341	)		5,539		5,542		3,315

Contractual Obligations	Total	Less then 1 year	2-3 years	3-5 years	After 5 years	Notes Reference
Debt Obligations	20,274	3,426	2,928	3,414	10,506	9
Capital Lease Obligations	69	2	4	6	57	11
Operating Lease Obligations	1,643	81	148	143	1,271	11
Purchase "Take-or-Pay" Obligations	18,837	1,534	2,004	1,682	13,617	11
Other Long-term Obligations reflected on Balance Sheet(1)	400	—	198	35	167	N/A

TOTAL	41,223	5,043	5,282	5,280	25,618

	Payment due by period (amounts in millions)
Non-contingent contractual obligation	Less than 1 year		1 to 3 years		Over 3 years		Total
Indebtedness (excluding interest)	$	77	$	303	$	5,559	$	5,939
Trust preferred securities (excluding dividends)		—		731		—		731
Construction commitments		38		—		—		38

Total	$	115	$	1,034	$	5,559	$	6,708

Contingent contractual obligations	Amount		Number of Agreements	Exposure Range for Each Agreement	Recorded On Balance Sheet
Guarantees	$	515	55	<$1 – $100	$	164
Letters of credit — under the Revolver		70	7	<$1 – $ 36		—
Letters of credit — outside the Revolver		19	2	<$5 – $ 14		—
Surety bonds		4	6	<$1 – $ 3		—

Total	$	608	70		$	164

			2003			2002
			(Amounts in Millions, Except Shares and Par Value)
ASSETS
Current Assets:
Cash and cash equivalents			$	1,737		$	792
Restricted cash				288			158
Short-term investments				189			177
Accounts receivable — net of reserves of $291-2003; $310 -2002				1,211			1,001
Inventory				376			353
Receivable from affiliates				3			25
Deferred income taxes — current				136			138
Prepaid expenses				64			27
Other current assets				677			923
Current assets of discontinued operations and businesses held for sale				205			763

	Total current assets			4,886			4,357

Property, Plant and Equipment:
Land				733			687
Electric generation and distribution assets				21,087			18,176
Accumulated depreciation and amortization				(4,593	)		(3,692	)
Construction in progress				1,278			2,349

	Property, plant, and equipment — net			18,505			17,520

Other Assets:
Deferred financing costs — net				430			390
Investments in and advances to affiliates				648			678
Debt service reserves and other deposits				534			508
Goodwill — net				1,378			1,373
Deferred income taxes — noncurrent				781			967
Long-term assets of discontinued operations and businesses held for sale				750			7,332
Other assets				1,992			1,482

	Total other assets			6,513			12,730

		Total	$	29,904		$	34,607

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current Liabilities:
Accounts payable			$	1,225		$	1,018
Accrued interest				561			331
Accrued and other liabilities				1,156			1,091
Current liabilities of discontinued operations and businesses held for sale				699			763
Recourse debt — current portion				77			26
Non-recourse debt — current portion				2,769			3,277

	Total current liabilities			6,487			6,506

Long-Term Liabilities:
Non-recourse debt				10,930			10,044
Recourse debt				5,862			6,755
Deferred income taxes — noncurrent				1,051			1,186
Pension liabilities				947			1,166
Long-term liabilities of discontinued operations and businesses held for sale				94			5,738
Other long-term liabilities				3,083			2,896

	Total long-term liabilities			21,967			27,785

Minority Interest (including discontinued operations of $12—2003; $41—2002)				805			657
Commitments and Contingencies (Note 11)
Stockholders' Equity (Deficit):
Preferred stock, no par value — 50 million shares authorized; none issued				—			—
Common stock, $.01 par value — 1,200 million shares authorized for 2003 and 2002, 626 million issued and outstanding in 2003, 776 million issued and 558 million outstanding in 2002				6			6
Additional paid-in capital				5,737			5,312
Accumulated deficit				(1,103	)		(700	)
Accumulated other comprehensive loss				(3,995	)		(4,959	)

	Total stockholders' equity (deficit)			645			(341	)

		Total	$	29,904		$	34,607

		2003			2002			2001
		(Amounts in Millions, Except Shares and Par Value)
Revenues
Regulated		$	4,427		$	4,018		$	2,887
Non-regulated			3,988			3,362			3,412

	Total Revenues		8,415			7,380			6,299

Cost of sales
Regulated			(3,481	)		(3,316	)		(1,984	)
Non-regulated			(2,501	)		(2,114	)		(2,315	)

	Total cost of sales		(5,982	)		(5,430	)		(4,299	)

Corporate and business development office expenses			(157	)		(112	)		(120	)
Severance and transaction costs			—			—			(131	)
Interest expense			(1,986	)		(1,744	)		(1,327	)
Interest income			280			259			159
Other income			171			133			113
Other expense			(110	)		(83	)		(61	)
(Loss) gain on sale of investments and asset impairment expense			(201	)		(473	)		18
Goodwill impairment expense			(11	)		(612	)		—
Foreign currency transaction gains (losses)			127			(459	)		(12	)
Equity in earnings (loss) of affiliates			94			(203	)		175

INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST			640			(1,344	)		814
Income tax expense			194			285			310
Minority interest (income) expense			110			(20	)		98

INCOME (LOSS) FROM CONTINUING OPERATIONS			336			(1,609	)		406
(Loss) Income from operations of discontinued businesses (net of income tax benefit of $72, $407 and expense of $80, respectively)			(780	)		(1,554	)		(133	)

(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE			(444	)		(3,163	)		273
Cumulative effect of change in accounting principle (net of income tax expense of $22 and income tax benefit of $72, respectively)			41			(346	)		—

Net (loss) income		$	(403	)	$	(3,509	)	$	273

BASIC (LOSS) EARNINGS PER SHARE:
Income (loss) from continuing operations		$	0.56		$	(2.99	)	$	0.76
Discontinued operations			(1.31	)		(2.88	)		(0.25	)
Cumulative effect of accounting change			0.07			(0.64	)		—

BASIC (LOSS) EARNINGS PER SHARE		$	(0.68	)	$	(6.51	)	$	0.51

DILUTED (LOSS) EARNINGS PER SHARE:
Income (Loss) from continuing operations		$	0.56		$	(2.99	)	$	0.76
Discontinued operations			(1.30	)		(2.88	)		(0.25	)
Cumulative effect of accounting change			0.07			(0.64	)		—

DILUTED (LOSS) EARNINGS PER SHARE		$	(0.67	)	$	(6.51	)	$	0.51

			2003			2002			2001
			(Amounts in Millions)
OPERATING ACTIVITIES:
Net (loss) income			$	(403	)	$	(3,509	)	$	273
Adjustments to net (loss) income:
	Cumulative effect of change in accounting principle			(63	)		418			—
	Depreciation and amortization — continuing and discontinued operations			781			837			859
	Loss (gain) from sale of investments and asset impairment expense			201			410			(18	)
	Goodwill impairment expense			11			675			—
	Loss on disposal and impairment write-down associated with discontinued operations			678			1,900			182
	Provision for deferred taxes			(105	)		(315	)		47
	Minority interest (earnings) expense			110			(20	)		98
	Foreign currency transaction (gains) losses			(127	)		459			12
	Loss (earnings) of affiliates, net of dividends			(7	)		285			(140	)
	Other			57			16			(61	)
Changes in operating assets and liabilities:
	(Increase) decrease in accounts receivable			(101	)		128			712
	(Increase) decrease in inventory			(2	)		129			(10	)
	Decrease (increase) in prepaid expenses and other current assets			112			(301	)		(34	)
	(Increase) decrease in other assets			(112	)		(160	)		295
	(Increase) decrease in accounts payable			198			286			(125	)
	(Increase) decrease in accrued interest			287			98			(148	)
	(Increase) decrease in accrued and other liabilities			210			67			(334	)
	(Decrease) increase in other liabilities			(149	)		41			83

		Net cash provided by operating activities		1,576			1,444			1,691

INVESTING ACTIVITIES:
Property additions				(1,228	)		(2,116	)		(3,173	)
Acquisitions-net of cash acquired				—			(35	)		(1,365	)
Increase in cash from Eletropaulo share swap				—			162			—
Proceeds from the sales of assets				1,086			375			505
Sale of short-term investments				96			70			670
Purchase of short-term investments				(83	)		(145	)		(638	)
Proceeds from sale of available-for-sale securities				—			92			59
Affiliate advances and equity investments				—			(29	)		(133	)
(Increase) decrease in restricted cash				(214	)		25			832
Project development costs				—			(22	)		(105	)
Debt service reserves and other assets				(26	)		23			45
Other investing				(14	)		—			—

		Net cash used in investing activities		(383	)		(1,600	)		(3,303	)

FINANCING ACTIVITIES:
(Repayments) borrowings under the revolving credit facilities, net				(228	)		158			(70	)
Issuance of non-recourse debt and other coupon bearing securities				4,614			3,481			5,935
Repayments of non-recourse debt and other coupon bearing securities				(4,916	)		(3,389	)		(4,015	)
Payments for deferred financing costs				(146	)		(67	)		(153	)
Distributions to minority interests, net				(12	)		(11	)		(70	)
Issuance of common stock, net				337			—			14
Common stock dividends paid				—			—			(15	)
Other financing				(2	)		—			—

		Net cash (used in) provided by financing activities		(353	)		172			1,626
		Effect of exchange rate changes on cash		39			(81	)		(31	)

Total increase (decrease) in cash and cash equivalents				879			(65	)		(17	)
Decrease in cash and cash equivalents of discontinued operations and businesses held for sale				66			85			75
Cash and cash equivalents, beginning				792			772			714

Cash and cash equivalents, ending			$	1,737		$	792		$	772

SUPPLEMENTAL DISCLOSURES:
Cash payments for interest-net of amounts capitalized			$	1,827		$	2,007		$	1,846
Cash payments for income taxes-net of refunds				121			(3	)		254
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Common stock issued for acquisitions				—			—			511
Common stock issued for debt retirement				48			73			—
Liabilities assumed in purchase transactions				—			—			1,362
Liabilities relieved due to sale of assets				1,296			—			—
Liabilities consolidated in Eletropaulo transaction				—			4,907			—

	Common Stock						Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Loss
	Common Stock			Additional Paid-In Capital									Treasury Stock			Comprehensive (Loss) Income
	Shares	Amount		Additional Paid-In Capital									Treasury Stock			Comprehensive (Loss) Income
	(Amounts in Millions)
Balance at January 1, 2001	521.7	$	5	$	5,172		$	2,551		$	(1,679	)	$	(507	)	$	111

Cumulative effect of adopting SFAS No. 133 on January 1, 2001 (net of income tax benefit of $50)	—		—		—			—			(93	)		—			(93	)
Net income	—		—		—			273			—			—			273
Foreign currency translation adjustment (net of reclassification to earnings of $12, net of tax, for the sale or write off of investments in foreign entities and an income tax benefit of $38)	—		—		—			—			(636	)		—			(636	)
Unrealized losses on marketable securities (no income tax effect)	—		—		—			—			(48	)		—			(48	)
Minimum pension liability adjustment (net of income tax benefit of $10)	—		—		—			—			(16	)		—			(16	)
Change in derivative fair value (including a reclassification to earnings of ($32) million, net of tax, and an income tax benefit of $11)	—		—		—			—			(28	)		—			(28	)

Comprehensive loss																$	(548	)

Dividends declared	—		—		—			(15	)		—			—
Issuance of common stock pursuant to acquisitions	9.4		—		511			—			—
Retirement of treasury stock	—		—		(507	)		—			—			507
Issuance of common stock under benefit plans and exercise of stock options and warrants	2.1		—		34			—			—			—
Tax benefit associated with the exercise of options	—		—		15			—			—			—

Balance at December 31, 2001	533.2		5		5,225			2,809			(2,500	)		—

Net Loss	—		—		—			(3,509	)		—			—			(3,509	)
Foreign currency translation adjustment (net of reclassification to earnings of $65, net of tax, for the sale or write off of investments in foreign entities (no income tax effect))	—		—		—			—			(1,677	)		—			(1,677	)
Realized losses on marketable securities (no income tax effect)	—		—		—			—			48			—			48
Minimum pension liability adjustment (net of income tax benefit of $229)	—		—		—			—			(553	)		—			(553	)
Change in derivative fair value (including a reclassification to earnings of ($106) million, net of tax, and an income tax benefit of $41)	—		—		—			—			(277	)		—			(277	)

Comprehensive loss																$	(5,968	)

Issuance of common stock in exchange for cancellation of debt	21.6		1		73			—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	3.1				14			—			—			—

Balance at December 31, 2002	557.9		6		5,312			(700	)		(4,959	)		—

Net loss	—		—		—			(403	)		—			—			(403	)
Foreign currency translation adjustment (net of reclassification to earnings of $114, net of tax, for the sale or write off of investments in foreign entities (no income tax effect))	—		—		—			—			504			—			504
Minimum pension liability adjustment (net of income tax benefit of $128)	—		—		—			—			325			—			325
Change in derivative fair value (including a reclassification to earnings of ($126) million, net of tax, and an income tax benefit of $47)	—		—		—			—			135			—			135

Comprehensive income																$	561

Issuance of common stock through public offering	49.5		—		334
Issuance of common stock in exchange for cancellation of debt	12.2		—		63			—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	6.0		—		19			—			—			—
Stock option expense	—		—		9			—			—			—

Balance at December 31, 2003	625.6	$	6	$	5,737		$	(1,103	)	$	(3,995	)	$	—

	December 31, 2003		December 31, 2002
	(in millions)		(in millions)
ASSETS:
Cash-unrestricted	$	11	$	77
Cash-restricted		34		74
Short-term investments		—		2
Accounts receivable, net		88		321
Inventory		20		145
Other current assets		51		144
PP&E		614		5,818
Other long-term assets		137		1,514

Total assets	$	955	$	8,095

LIABILITIES:
Accounts payable	$	76	$	225
Current portion of long-term debt		580		200
Other current liabilities		42		338
Long-term debt		56		4,126
Other long-term liabilities		39		1,612

Total liabilities	$	793	$	6,501

	Contract Generation			Competitive Supply			Large Utilities			Growth Distribution			Total
Carrying amount at December 31, 2001	$	1,194		$	133		$	—		$	1,010		$	2,337
Goodwill acquired during the period		—			—			780			—			780
Impairment losses from annual analysis		—			(5	)		(607	)		—			(612	)
Impairment losses from adoption of SFAS No. 142		—			(72	)		—			(681	)		(753	)
Concession contracts reclassed to other assets		(11	)		—			—			(152	)		(163	)
Translation adjustments and other		(7	)		(2	)		(173	)		(34	)		(216	)

Carrying amount at December 31, 2002		1,176			54			—			143			1,373
Impairment losses from annual analysis		—			(11	)		—			—			(11	)
Translation adjustments and other		15			1			—			—			16

Carrying amount at December 31, 2003	$	1,191		$	44		$	—		$	143		$	1,378

AS OF AND FOR THE YEARS ENDED DECEMBER 31,	2003		2002(1)		2001(1)
Revenues	$	2,758	$	2,832	$	6,147
Operating Income		1,039		695		1,717
Net Income		407		229		650
Current Assets		1,347		1,097		3,700
Noncurrent Assets		7,479		6,751		14,942
Current Liabilities		1,434		1,418		3,510
Noncurrent Liabilities		3,795		3,349		8,297
Stockholder's Equity		3,597		3,081		6,835

				December 31,
		Interest Rate (1)	Final Maturity	December 31,
		Interest Rate (1)	Final Maturity	2003			2002
VARIABLE RATE:
	Bank loans	5.79%	2022	$	5,759		$	7,498
	Commercial paper	—%	—		—			406
	Notes and Bonds	9.22%	2012		425			616
	Debt to (or guaranteed by) multilateral or export credit agencies	3.87%	2018		553			934
	Other	16.48%	2022		406			455
FIXED RATE:
	Bank loans	8.44%	2024		1,013			982
	Commercial Paper	14.04%	2005		101			146
	Notes and bonds	8.09%	2034		4,973			5,995
	Debt to (or guaranteed by) multilateral or export credit agencies	6.31%	2012		271			347
	Other	10.03%	2017		834			279

	SUBTOTAL				14,335			17,658
	Less: Non-recourse debt of discontinued operations				(636	)		(4,337	)

	SUBTOTAL				13,699			13,321
	Less: Current maturities				(2,769	)		(3,277	)

	TOTAL			$	10,930		$	10,044

	Interest Rate (1)	Final Maturity	First Call Date (2)	2003			2002
Corporate revolving bank loan	8.10%	2007	—	$	—		$	228
Term loan A	8.12%	2005	—		—			500
Term loan B	7.99%	2005	—		—			427
Term loan C	7.94%	2005	—		—			260
Term loan	5.13%	2008	—		300			—
Term loan	5.32%	2008	—		400			—
Senior secured notes	10.00%	2005	—		232			258
Senior secured notes	9.00%	2015	—		600			—
Senior secured notes	8.75%	2013	—		1,200			—
Senior notes	8.00%	2008	2000		155			199
Senior notes	9.50%	2009	—		470			750
Senior notes	9.38%	2010	—		423			850
Senior notes	8.88%	2011	—		313			537
Senior notes	8.38%	2011	—		170			217
Senior notes	8.75%	2008	—		223			400
Remarketable or Redeemable Securities	7.38%	2003	—		—			26
Senior subordinated notes	10.25%	2006	2001		—			231
Senior subordinated notes	8.38%	2007	2002		210			316
Senior subordinated notes	8.50%	2007	2002		259			349
Senior subordinated debentures	8.88%	2027	2004		115			125
Convertible junior subordinated debentures	6.75%	2029	—		517			517
Convertible junior subordinated debentures	6.00%	2008	—		213			460
Convertible junior subordinated debentures	4.50%	2005	2001		150			150
Unamortized discounts					(11	)		(19	)

SUBTOTAL					5,939			6,781
Less: Current maturities					(77	)		(26	)

Total				$	5,862		$	6,755

2004	$	2,846
2005		1,684
2006		1,221
2007		1,162
2008		2,242
Thereafter		10,483

Total	$	19,638

	Total
2004	$	1,026
2005		729
2006		483
2007		479
2008		473
Thereafter		8,992

Total	$	12,182

Contingent contractual obligations	Amount		Number of Agreements	Term Range (years)	Maximum Exposure Range for Each Agreement
	(amounts in $millions, except agreements and years)
Guarantees	$	330	33	<1 – 20+	<$1 – $100
Letters of credit — under the Revolver		70	7	<1 – 2	<$1 – $36
Letters of credit — outside the Revolver		19	2	<1	<$5 – $14
Surety bonds		4	6	<1	<$1 – $3

Total	$	423	48

	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	9,359	9.0	$	2.75	761	$	2.40
$3.25 – $9.88	4,519	2.2		5.51	4,211		5.39
$9.89 – $14.40	19,580	7.4		13.03	19,580		13.03
$14.41 – $22.85	2,887	4.7		17.85	2,886		17.85
$22.86 – $58.00	4,462	6.5		44.11	4,456		44.09
$58.01 – $80.00	9	6.7		61.42	9		61.28

Total	40,816	6.9	$	13.59	31,903	$	16.56

	December 31, 2003					December 31, 2002							December 31, 2001
	Income		Share	$ per Share		(Loss)			Shares	$ per Share			Income		Share	$ per Share
BASIC EARNINGS (LOSS) PER SHARE:
Income (Loss) from continuing operations	$	336	594.7	$	0.56	$	(1,609	)	538.9	$	(2.99	)	$	406	532.2	$	0.76
EFFECT OF DILUTIVE SECURITIES:
Stock options and warrants		—	3.1		—		—		—		—			—	5.3		—
Stock units allocated to deferred compensation plans		—	0.1		—		—		—		—			—	0.4		—

DILUTED (LOSS) EARNINGS PER SHARE	$	336	597.9	$	0.56	$	(1,609	)	538.9	$	(2.99	)	$	406	537.9	$	0.76

	Revenues (1)		Depreciation and Amortization		Gross Margin (2)		Equity in (Loss) Earnings (3)		Total Assets		Investment in and Advances to Affiliates		Property Additions
Year Ended December 31, 2003
Contract Generation	$	3,108	$	288	$	1,267	$	94	$	13,473	$	619	$	583
Competitive Supply		880		54		220				2,137		7		126
Large Utilities		3,301		307		763		—		9,409		—		300
Growth Distribution		1,126		85		183		—		2,788		—		87
Discontinued Businesses		—		—		—		—		955		—		111
Corporate				4						1,142		22		21

Total	$	8,415	$	738	$	2,433	$	94	$	29,904	$	648	$	1,228

	Revenues (1)		Depreciation and Amortization		Gross Margin (2)		Equity in (Loss) Earnings (3)			Total Assets		Investment in and Advances to Affiliates			Property Additions
Year Ended December 31, 2002
Contract Generation	$	2,550	$	226	$	1,065	$	75		$	12,092	$	671		$	926
Competitive Supply		812		66		183		(3	)		2,796		7			335
Large Utilities		3,150		286		687		(275	)		8,829		—			300
Growth Distribution		868		85		15		—			2,394		(20	)		82
Discontinued Businesses		—		—		—		—			8,093		—			473
Corporate		—		2		—		—			403		20			—

Total	$	7,380	$	665	$	1,950	$	(203	)	$	34,607	$	678		$	2,116

	Revenues (1)		Depreciation and Amortization		Gross Margin (2)		Equity in (Loss) Earnings (3)			Total Assets		Investment in and Advances to Affiliates		Property Additions
Year Ended December 31, 2001
Contract Generation	$	2,572	$	253	$	893	$	54		$	11,654	$	659	$	737
Competitive Supply		840		74		204		(9	)		3,515		46		967
Large Utilities		1,641		203		615		144			7,769		2,293		378
Growth Distribution		1,246		99		288		(14	)		3,683		12		45
Discontinued Businesses		—		—		—		—			10,250		—		1,043
Corporate		—		3		—		—			275		21		3

Total	$	6,299	$	632	$	2,000	$	175		$	37,146	$	3,031	$	3,173

	December 31, 2003				December 31, 2002
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Foreign currency forwards and swaps, net	$	56	$	56	$	17	$	17
Energy derivatives, net		162		162		201		201
Liabilities:
Non-recourse debt		14,335		14,397		17,647		20,447
Recourse debt		5,939		6,228		6,781		4,179
Interest rate swaps		394		394		557		557
Interest rate caps and floors, net		68		68		115		115