ITEM 1.    BUSINESS

Overview

        We are a global power company. We own a portfolio of electricity generation and distribution businesses on five continents and in 28 countries, with generation capacity totaling approximately 43,000 Megawatts ("MW") and distribution networks serving over 11 million people as of December 31, 2007. Our global workforce of 28,000 people provides electricity to people in diverse markets ranging from urban centers in the United States to remote villages in India. We were incorporated in Delaware in 1981 and for more than two decades we have been committed to providing safe and reliable energy.

        We operate two primary types of businesses. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. The second is our Utilities business, where we own and/or operate utilities to distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors in a defined service area.

        We are also developing an Alternative Energy business. Alternative Energy includes strategic initiatives such as wind generation and climate solutions. While alternative energy is not currently

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material to our results of operations, it is a fast growing part of our business. We have more than 1,000 MW of wind projects in operation and are one of the fastest-growing producers of wind energy in the United States. In the area of climate solutions, we are building a global business for the production and marketing of greenhouse gas emissions offset credits and are currently developing projects in North America, Asia, Europe and Latin America.

        Our business model benefits from a diverse power generation portfolio that is largely contracted, which reduces the risk related to the market prices of electricity and fuel, while our electric utility portfolio consists of businesses in mature markets as well as faster-growing emerging markets. Portfolio management is becoming an increasing area of focus through which we have and will continue to sell or monetize a portion of certain businesses or assets when market values appear attractive. Furthermore, as we continue to expand and grow our business, we will maintain a focus on efforts to improve our business operations and management processes, including our internal controls over financial reporting.

        Our portfolio of power generation facilities employs a broad range of technologies and fuel sources, including coal, gas, fuel oil and renewable sources such as hydroelectric power, wind and biomass. We currently have more than 7,454 MW of hydropower in operation or under development in nine countries. When combined with the facilities employing renewable energy sources in our Alternative Energy business, our facilities generating power from renewable sources represented approximately 20% of our entire portfolio of generation capacity as of December 31, 2007.

        Our goal is to continue building on our traditional lines of business, while expanding into other essential energy-related areas, such as Alternative Energy. As we move into new lines of business, we will leverage the competitive advantages that result from our unique global footprint, local market insights and our operational and business development expertise. We continue to emphasize growth through "greenfield" development, platform expansion, privatization of government-owned assets, and mergers and acquisitions. We see investments with high growth potential as the most significant contributor to long-term shareholder value creation.

Key Business Lines

        AES's primary sources of revenue and gross margin today are from Utilities and Generation. These businesses are distinguished by the nature of the customers, operational differences, cost structure, regulatory environment and risk exposure. The breakout of revenue and gross margin between Generation and Utilities for the years ended December 31, 2007, 2006 and 2005, respectively is shown below.

Revenue

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Gross Margin

Generation

        We currently own or operate 121 Generation facilities in 26 countries on five continents. We have 12 new Generation facilities under construction. As part of our portfolio management activities, we have entered into an agreement to sell certain businesses in Kazakhstan. We are a major power source in many countries, such as Panama where we are the largest generator of electricity, and Chile, where AES Gener ("Gener") is the second largest electricity generation company. Our Generation business uses a wide range of technologies and fuel types including coal, combined-cycle gas turbines, hydroelectric power and biomass.

        Performance drivers for our Generation businesses include, among other things, plant reliability, fuel costs and fixed-cost management. Growth in Generation is largely tied to securing new power purchase agreements ("PPAs"), expanding capacity in our existing facilities and building new power plants.

        The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. In 2007, approximately 62% of the revenues from our Generation business was from plants that operate under PPAs of five years or longer for 75% or more of their output capacity. These businesses often reduce their exposure to fuel supply risks by entering into long-term fuel supply contracts or fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. These long-term contractual agreements result in relatively predictable cash flow and earnings and reduce exposure to volatility in the market price for electricity and fuel; however, the amount of earnings and cash flow predictability varies from business to business based on the degree to which its exposure is limited by the contracts that it has negotiated.

        Our Generation businesses with long-term contracts face most of their competition from other utilities and independent power producers prior to the execution of a power sales agreement during the development phase of a project or upon expiration of an existing agreement. Once a project is operational, we traditionally have faced limited competition due to the long-term nature of the generation contracts. However, as our existing contracts expire, the introduction of new competitive power markets has increased competition to attract new customers and maintain our current customer base.

        The balance of our Generation business sells power through competitive markets under short-term contracts or directly in the spot market. As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity, natural gas, coal and other fuels. However, for a number of these facilities, including our plants in New York, which include

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a fleet of low-cost coal fired plants, we have hedged the majority of our exposure to fuel, energy and emissions pricing for the next several years. Competitive factors for these facilities include price, reliability, operational cost and third party credit requirements.

Utilities

        AES distributes power to over 11 million people in eight countries on five continents and consists primarily of 15 companies owned or operated under management agreements, each of which operate in defined service areas. These businesses have a variety of structures ranging from pure distribution businesses to fully integrated utilities, which generate, transmit and distribute power. Our largest utility, Indianapolis Power & Light ("IPL"), has the exclusive right to provide retail services to approximately 465,000 customers in Indianapolis, Indiana. Eletropaulo Metropolitana Electricidad de São Paulo S.A ("AES Eletropaulo" or "Eletropaulo"), serving the São Paulo, Brazil area for over 100 years, has over five million customers and is the largest electricity distribution company in Brazil in terms of revenues and electricity distributed. In Cameroon, we are the primary generator and distributor of electricity and in El Salvador we serve more than 80% of the country's electricity customers. In May 2007, we completed the sale of La Electricidad de Caracas ("EDC"), our utility in Venezuela, for US$739 million, net of tax.

        Performance drivers for Utilities include, but are not limited to, reliability of service; management of working capital; negotiation of tariff adjustments; compliance with extensive regulatory requirements; and in developing countries, reduction of commercial and technical losses. The results of operations of our Utilities businesses are sensitive to changes in economic growth and regulation and abnormal weather conditions in the area in which they operate.

        Utilities face relatively little direct competition due to significant barriers to entry which are present in these markets. Where we do face competition is in our efforts to acquire existing businesses and develop new ones. In this arena, we compete against a number of other participants, some of which have greater financial resources, have been engaged in distribution related businesses for periods longer than we have, and/or have accumulated more significant portfolios. Relevant competitive factors for our power distribution businesses include financial resources, governmental assistance, regulatory restrictions and access to non-recourse financing. In certain locations, our distribution businesses face increased competition as a result of changes in laws and regulations which allow wholesale and retail services to be provided on a competitive basis.

Alternative Energy

        As demand for more sustainable and environmentally friendly sources of energy grows, we continue to invest in Alternative Energy, with a current focus on increasing our wind power capacity and building our climate solutions business for greenhouse gas ("GHG") reduction. Alternative Energy is not currently one of our primary lines of business, but we expect this high growth sector to be a material contributor to our revenue and gross margin in the future. AES entered the wind business in 2005 and today we have ten wind generation facilities with more than 1,000 MW of wind projects in operation. In addition, we are developing GHG reduction projects. Many countries that have approved the Kyoto Protocol are marketing the credits created. AES already operates in 18 of the developing countries that are eligible for these credits, which provides us with a good foundation for this new business.

Risks

        We routinely encounter and address risks, some of which may cause our future results to be different, sometimes materially different, than we presently anticipate. The categories of risk we have identified in Item 1A Risk Factors of this Form 10-K include the following:

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Risks associated with our operations in areas with extensive governmental and environmental regulation;

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Risks associated with our exposure to material litigation and regulatory proceedings;



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Risks associated with our disclosure controls and internal controls over financial reporting;



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Risks associated with our high levels of debt;



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Risks associated with the operation of power plants;



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Risks associated with Revenue and Earnings volatility; and



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Risks associated with our ability to raise needed capital.

        The categories of risk identified above are discussed and explained in greater detail in Item 1A Risk Factors of this Form 10-K. These risk factors should be read in conjunction with Management's Discussion and Analysis ("MD&A"), and the Consolidated Financial Statements and related notes included elsewhere in this report.

Our Organization

        We believe our broad geographic footprint allows us to focus development in targeted markets with opportunities for new investment and provides stability through our presence in more developed regions. We organize our operations along our two primary lines of business and within four geographic regions: Latin America; North America; Europe & Africa; and, Asia & the Middle East ("Asia").

        We believe our presence in each region affords us important relationships and helps us identify local markets with attractive opportunities for new investment. As a result, we have structured our organization so that each region is led by a regional president responsible for managing existing businesses and business development. The regional presidents report to our Chief Operating Officer ("COO"). Our Alternative Energy Group is led by an Executive Vice President that reports to the Chief Executive Officer ("CEO") and is based in Arlington, Virginia. Our Business Excellence Group, led by an Executive Vice President who reports to the COO, supports the regions in areas such as procurement, engineering and construction, safety, environment and information technology. Our global Business Excellence Group is developing processes to foster innovation, share knowledge and improve performance across our businesses. For further information on our management team, see Executive Officers discussion below.

Segments

        The Company currently reports seven operating segments:

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Latin America Generation;



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Latin America Utilities;



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North America Generation;



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North America Utilities;



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Europe & Africa Generation;



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Europe & Africa Utilities;



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Asia Generation.

        Three regions, North America, Latin America and Europe & Africa, are engaged in both Generation and Utility businesses. Our Asia region only has Generation. Accordingly, these businesses and regions account for seven segments. "Corporate and Other" includes corporate overhead costs which are not directly associated with the operations of our seven primary operating segments; interest income and expense; other intercompany charges such as management fees and self-insurance premiums which are fully eliminated in consolidation; and revenue, development costs and operational costs related to our Alternative Energy business, which is currently not material to our presentation of operating segments.

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        The graph below shows the breakdown between our Latin America Generation and Utilities segments as a percentage of total Latin America revenue and as a percentage of total Latin America gross margin for the years ended December 31, 2007, 2006, and 2005. See Note 22—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

Revenue		Gross Margin

        Latin America Generation.     Our largest generation business in Latin America, AES Tietê ("Tietê"), located in Brazil, represents approximately 21% of the total generation capacity in the state of São Paulo and is the 9th largest generator in Brazil. AES holds a 24% economic interest in Tietê. In Argentina, we are one of the largest private power generators contributing 12% of the country's total power generation capacity. In Chile, we are the second largest generator of power. We currently have five new generation plants under construction—three coal plants and one hydro plant in Chile and one hydro plant in Panama with a combined generation capacity of 924 MW.

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        Set forth below is a list of our Latin America Generation facilities:

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AES operates this facility through management or operations and maintenance agreements and owns no equity interest in this facility

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Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava and Promissão

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Gener—Electrica de Santiago plants: Renca and Nueva Renca

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Gener—Energia Verde Plants: Constitución, Laja and San Francisco de Mostazal

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Gener—Gener plants: Ventanas, Laguna Verde, Laguna Verde Turbogas, Alfalfal, Maitenas, Queltehues, Volcán and Los Vientos. Los Vientos started full commercial operations in January, 2007

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Itabo plants: Itabo, Santo Domingo, Timbegue, Los Mina and Higuamo

Generation under construction

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        Latin America Utilities.     Each of our Utilities businesses in Latin America sells electricity under regulated tariff agreements and each has transmission and distribution capabilities but none of them has generation capability. AES Eletropaulo, a consolidated subsidiary of which AES owns 16% and which has served the São Paulo, Brazil area for over 100 years, has over five million customers and is the largest electricity distribution company in Brazil in terms of revenues and electricity distributed. Pursuant to its concession contract, AES Eletropaulo is entitled to distribute electricity in its service area until 2028. AES 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 and 44% of the population in the State of São Paulo, Brazil. AES Sul ("Sul"), a wholly owned subsidiary, serves over one million customers. In El Salvador, our Utilities businesses provide electricity to over 80% of the country serving approximately 1 million customers. In May 2007, we sold EDC, our Utility business in Venezuela.

        Set forth below is a list of our Latin America Utilities facilities:

⁽¹⁾

AES operates these facilities through management agreements and owns no equity interest in these businesses

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        The graph below shows the breakdown between our North American Generation and Utilities segments as a percentage of total North America revenue and as a percentage of total North American gross margin for the years ended December 31, 2007, 2006, and 2005. See Note 22—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

Revenue		Gross Margin

        North American Generation.     Approximately 63% of the generation capacity sold to third parties is supported by long-term power purchase or tolling agreements. Our North America Generation businesses consist of seven gas-fired plants, ten coal-fired plants, and three petroleum coke-fired plants in Puerto Rico and Mexico. In 2007, AES Eastern Energy, our Generation business in the State of New York was able to capitalize on favorable market conditions of its energy sales in the competitive spot market. Our businesses also generated revenue and gross margin growth from new investments, primarily through the acquisition of Termoelectrica del Golfo ("TEG") and Termoelectrica del Penoles ("TEP").

        AES's operating strategy is to continue to improve availability and lower the operating cost of its base load capacity. AES is committed to providing cleaner forms of reliable energy in the U.S. Since 1999, AES has invested more than $150 million in emissions control projects. In 2006, AES announced plans to invest in technology at AES Westover in New York, which is expected to reduce CO ₂ emissions by 95%, mercury emissions by 90% and NO ₂ emissions up to 90% once the project is complete.

        Set forth below is a list of our North American Generation facilities:

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        North American Utilities.     AES has one integrated utility in North America, IPL, which it owns through IPALCO Enterprises Inc. ("IPALCO"), the parent holding company of IPL. IPL is engaged in generating, transmitting, distributing and selling electric energy to approximately 465,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL also owns and operates four generation facilities that provide essentially all of the electricity it distributes. The two largest 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 gross generation capability is 3,699 MW. Over half of IPL's coal is provided by one supplier with which IPL has long-term contracts. A key driver for the business is tariff recovery for environmental projects through the rate adjustment process. IPL's customers include residential, industrial and commercial which made up 44%, 38% and 18% of North America Utilities revenue for 2007.

IPL's facilities

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IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg

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        The graph below shows the breakdown between our Europe & Africa Generation and Utilities segments as a percentage of total Europe & Africa revenue and as a percentage of total Europe & Africa gross margin for the years ended December 31, 2007, 2006, and 2005. See Note 22—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

Revenue		Gross Margin

        Europe & Africa Generation.     In 2006, we began commercial operation of AES Cartagena ("Cartagena"), our first power plant in Spain, with 1,200 MW capacity. The results of operations for Cartagena, an unconsolidated entity, are in the Equity in Earnings of Affiliates line item on the Consolidated Statements of Operations and therefore not reflected in these segment operating results. Today, AES operates five power plants in Kazakhstan which account for almost 30% of the country's total installed generation capacity. However, we recently announced an agreement to sell two of our facilities in Kazakhstan. As part of this agreement, AES will continue to operate these facilities under a management agreement through 2010. Key business drivers of this segment are: foreign currency exchange rates, new legislation and regulations including those related to the environment.

        Set forth below is a list of our generation facilities in the Europe & Africa Generation segment:

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AES additionally owns and operates the Maikuben West coal mine in Kazakhstan, supplying coal to AES businesses and third parties

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AES operates these facilities through management or operations and concession agreements and owns no equity interest in these businesses

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⁽³⁾

AES entered into a stock purchase agreement to sell its indirect wholly-owned subsidiary, Ekibastuz and the Maikuben West coal mine. The transaction is expected to close in the second quarter of 2008.

Generation under construction

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JV with I.C. Energy. I.C. Energy Plants: Damlapinar Konya, Kepezkaya Konya, and Kumkoy Samsun

        Europe & Africa Utilities.     AES acquired a 56% interest in an integrated utility AES SONEL ("SONEL") in 2001. SONEL generates, transmits and distributes electricity to over half a million people and is the sole source of electricity in Cameroon. Our distribution businesses in Cameroon, the Ukraine and Kazakhstan together serve approximately 2.4 million customers.

        Set forth below is a list of the generation and distribution facilities in our Europe & Africa Utilities segment:

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AES operates these facilities through management agreements and owns no equity interest in these businesses

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Shygys Energo Trade, a retail electricity company is 100% owned by EK REC and purchases distribution service from EK REC and electricity in the wholesale electricity market and resells to the distributions customers of EK REC.

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Ust-Kamenogorsk Heat Nets provide transmission and distribution of heat with a total heat generating capacity of 224 Gcal

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Asia

        Our Asian operations accounted for 7%, 7% and 6% of consolidated revenues in 2007, 2006 and 2005, respectively. Asia's Generation business operates 13 power plants with a total capacity of 5,369 MW in six countries and has one power plant under construction. AES only operates generation facilities in Asia. See Note 22—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for revenue, gross margin and total assets by segment. The following table provides highlights for our Asia operations:

        Asia Generation.     Over half of our facilities and generation capacity in Asia are located in China. In 1996, AES joined with Chinese partners to build Yangcheng, the first "coal-by-wire" power plant with the capacity of 2,100 MW. In 2003, AES started commercial operations of its combined power and desalination water facility in Oman, the first of its kind. We also have a combined power and desalination water facility, the first such facility to be awarded to the private sector, in Qatar. This facility generates over 30% of the country's peak system capacity and 25% of the country's water supply. AES Amman East ("Amman East") is a 370 MW combined-cycle gas power plant under construction in Jordan. Commercial operations are expected to commence in 2009.

        In early February 2008, the Company signed an agreement with National Power Corporation ("NPC"), a state owned utility, to purchase a 600 MW coal-fired generation facility in Masinloc, Philippines for $930 million. The purchase will be primarily financed by non-recourse debt. The 10 year old plant, which is currently partially operational, consists of two turbines; one turbine is currently in working condition while the second turbine will require maintenance to return it to a working condition. The plant will require an additional investment, over the next six to 12 months, to bring it up to the required operational standard. The Masinloc plant is not currently compliant with government mandated environmental regulations. Masinloc will receive permits from the Philippine government to allow for the continued operation of the plant during its environmental clean-up period. The sale is expected to close in April 2008.

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        Set forth below is a list of our generation facilities in Asia:

Generation

Generation under construction

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Construction of the Amman East power plant commenced in May, 2007

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Joint Venture with Guohua Energy Investment Co. Ltd.

Corporate and Other

        Corporate and Other includes general and administrative expenses related to corporate staff functions and initiatives—primarily executive management, finance, legal, human resources, information systems and certain development costs which are not allocable to our business segments; interest income and interest expense; and intercompany charges such as management fees and self insurance premiums which are fully eliminated in consolidation.

        In addition, Corporate and Other also includes the net operating results of our Alternative Energy business which is not material to our presentation of reporting segments. See Note 22—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

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We own and operate 725 MW of wind generation capacity and operate an additional 298 MW capacity through operating and management agreements.



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Our Alternative Energy businesses are located primarily in North America where we operate wind generation facilities that have generation capacity of 722 MW. Another U.S. facility, Buffalo Gap III with 170 MW capacity is under construction and expected to commence commercial operations in 2008.



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We also have ownership interests in development-stage companies in Scotland, France and Bulgaria.

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        Set forth below is a list of our Alternative Energy facilities:

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AES owns these wind facilities together with third party equity investors with both parties in all project holding variable ownership interests. It also has ownership interests in development-stage companies in Scotland, France and Bulgaria

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AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses

Alternative Energy businesses under construction

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Customers

        We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2007 total revenues.

Employees

        As of December 31, 2007 we employed approximately 28,000 people.

Executive Officers

        The following individuals are our executive officers:

         Paul Hanrahan, 50 years old, has been the President and Chief Executive Officer ("CEO") since 2002. Prior to assuming his current position, Mr. Hanrahan was the Chief Operating Officer ("COO") and Executive Vice President. In this role, he was responsible for managing all aspects of 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, Ltd., a public company formerly listed on NASDAQ. Mr. Hanrahan also

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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). Mr. Hanrahan is a graduate of Harvard Business School and the U.S. Naval Academy.

         David S. Gee, 53 years old, became an Executive Vice President of the Company in 2006 and the Regional President of North America in 2005. Prior to joining the Company in 2004 as Vice President of Strategy, Mr. Gee was Vice President of Strategic Planning for PG&E in San Francisco, California from 2000 until 2005. Mr. Gee was a principal consultant for McKinsey & Co. from 1985 to 2000 in Houston, Mexico City and London. He was also an Associate for Baker Hughes and Booz Allen & Hamilton in Houston, Texas. Mr. Gee has a Bachelor of Science degree in Chemical Engineering from the University of Virginia and a Master of Science degree in Finance from the Sloan School of Management at the Massachusetts Institute of Technology.

         Andres R. Gluski, 50 years old, has been an Executive Vice President and COO of the Company since March 2007. Prior to becoming the COO, Mr. Gluski was Executive Vice President and the Regional President of Latin America since 2006. Mr. Gluski was Senior Vice President for the Caribbean and Central America from 2003 to 2006, was Group Manager and CEO of EDC (Venezuela) from 2002 to 2003, served as CEO of Gener (Chile) in 2001 and was Executive Vice President of EDC and Corporacion EDC. Prior to joining the Company in 1997, Mr. Gluski was Executive Vice President of Corporate Banking for Banco de Venezuela and Executive Vice President of Finance of CANTV in Venezuela. Mr. Gluski is a graduate of Wake Forest University and holds a Master of Arts and a Doctorate in Economics from the University of Virginia.

         Victoria D. Harker, 43 years old, has been an Executive Vice President and Chief Financial Officer ("CFO") since January 2006. Prior to joining the Company, Ms. Harker held the positions of Acting CFO, Senior Vice President and Treasurer of MCI from November 2002 through January 2006. Prior to that, Ms. Harker served as CFO of MCI Group, a unit of WorldCom Inc., from 1998 to 2002. Prior to 1998, Ms. Harker held several positions at MCI in the areas of finance, information technology and operations. Ms. Harker received a Bachelor of Arts degree in English and Economics from the University of Virginia and a Masters in Business Administration, Finance from American University.

         Robert F. Hemphill, Jr., 64 years old, has been an Executive Vice President of the Company since February 2005. Mr. Hemphill served as the Company's Director from June 1996 to February 2005 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 Altair Nanotechnologies and Phoenix Motorcars International. Mr. Hemphill received a Bachelor of Arts degree in Political Science from Yale University, a Master of Arts in Political Science from the University of California, Los Angeles, and a Masters in Business Administration, Finance from George Washington University.

         Jay L. Kloosterboer, 47 years old, is the Executive Vice President of Business Excellence. Mr. Kloosterboer joined the Company in 2003 as Vice President and Chief Human Resource Officer. Prior to joining the Company, Mr. Kloosterboer held various senior Human Resources positions at Honeywell International from 1996 to 2003. Mr. Kloosterboer also held management positions at General Electric and Morgan Stanley. He received a Bachelor of Arts degree from Marquette University and holds a Master of Arts degree from the New Mexico State University.

         William R. Luraschi, 44 years old, is an Executive Vice President of the Company and President of the Alternative Energy Business. Mr. Luraschi joined the Company in 1993 and has been an Executive Vice President since July 2003. He was the Company's General Counsel from January 1994 until May 2005. Mr. Luraschi also served as Corporate Secretary from February 1996 until June 2002. Prior to joining the Company, he was an attorney with the law firm of Chadbourne & Parke, LLP. Mr. Luraschi received a Bachelor of Science from the University Of Connecticut and holds a Juris Doctorate from Rutgers School of Law.

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         Brian A. Miller, 42 years old, is an Executive Vice President of the Company, General Counsel and Corporate Secretary. Mr. Miller joined the Company in 2001 and has served in various positions including Vice President, Deputy General Counsel, Corporate Secretary, General Counsel for North America and Assistant General Counsel. Prior to joining AES, he was an attorney with the law firm Chadbourne & Parke, LLP. Mr. Miller received a bachelor's degree in History and Economics from Boston College and holds a Juris Doctorate from the University Of Connecticut School Of Law.

         John McLaren, 45 years old, is an Executive Vice President of the Company, and Regional President of Europe & Africa. Mr. McLaren served as Vice President of Operations for AES Europe & Africa from 2003 to 2006 (and AES Europe, Middle East and Africa from May 2005 to January 2006), Group Manager for Operations in Europe & Africa from 2002 to 2003, Project Director from 2000 to 2002, and Business Manager for AES Medway Operations Ltd. from 1997 to 2000. Mr. McLaren joined the Company in 1993. He holds a Masters in Business Administration from the University of Greenwich Business School in London.

         Mark E. Woodruff, 50 years old, is an Executive Vice President of the Company and Regional President of Asia & Middle East. Prior to his current position, Mr. Woodruff was Vice President of North America Business Development from September 2006 to March 2007 and was Vice President of AES for the North America West region from 2002 to 2006. Mr. Woodruff has held various leadership positions since joining the Company in 1992. Prior to joining the Company in 1991, Mr. Woodruff was a Project Manager for Delmarva Capital Investments, a subsidiary of Delmarva Power & Light Company. Mr. Woodruff holds a Bachelor of Science degree in Mechanical and Aerospace Engineering from the University of Delaware.

How to Contact AES and Sources of Other Information

        Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is (703) 522-1315. Our website 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. After the reports are filed with or furnished to the Securities and Exchange Commission ("SEC"), they are available from us free of charge. Material contained on our website is not part of and is not incorporated by reference in this Form 10-K.

        Our Chief Executive Officer and our Chief Financial Officer have provided certifications to the SEC as required by Section 302 of the Sarbanes-Oxley Act of 2002. These certifications are included as exhibits to this Annual Report on Form 10-K.

        Our Chief Executive Officer provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on July 20, 2007.

        Our Code of Business Conduct ("Code of Conduct") and Corporate Governance Guidelines have been adopted by our Board of Directors. The Code of Conduct is intended to govern as a requirement of employment the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to or waivers from the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.

        On July 30, 2007, the Company adopted a revised Code of Conduct applicable to all of its directors and employees, including its executive officers. The revised Code of Conduct aligns expectations regarding business conduct with updates to the Company's core values and reaffirms the

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Company's commitment to doing business with the highest standard of integrity. There are no material substantive changes to the Code of Conduct. The revised Code of Conduct is posted on the Company's website at www.aes.com

Regulatory Matters

Overview

        In each country where we conduct business, we are subject to extensive and complex governmental regulations which affect most aspects of our business, such as regulations governing the generation and distribution of electricity and environmental regulations. These regulations affect the operation, development, growth and ownership of our businesses. Regulations differ on a country by country basis and are based upon the type of business we operate in a particular country.

Regulation of our Generation businesses

        Our Generation businesses operate in two different types of regulatory environments:

        Market Environments.     In market environments, sales of electricity may be made directly on the spot market, under negotiated bilateral contracts, or pursuant to PPAs. The spot markets are typically administered by a central dispatch or system operator who seeks to optimize the use of the generation resources throughout an interconnected system (cost of the least expensive next generation plant required to meet system demand). The spot price is usually set at the marginal cost of energy or based on bid prices. In addition, many of these wholesale markets include markets for ancillary services to support the reliable operation of the transmission system, such as regulation (a service that corrects for short-term changes in electricity use that could impact the stability of the power system). Most of our businesses in Europe, Latin America and the US operate in these types of liberalized markets.

        Other Environments.     We operate Generation assets in certain countries that do not have a spot market. In these environments, electricity is sold only through PPAs with state-owned entities and/or industrial clients as the offtaker. The countries where we operate in this type of environment include Nigeria, Oman, Pakistan, Qatar, Sri Lanka and Jordan.

Regulation of our Distribution businesses

        In general, our distribution companies sell electricity directly to end users, such as homes and businesses and bill customers directly. The amount our distribution companies can charge customers for electricity is governed by a regulated tariff. The tariff, in turn, is generally based upon a certain usage level that includes a pass through of costs to the customer that are not controlled by the distribution company, including the costs of fuel (in the case of integrated utilities) and/or the costs of purchased energy, plus a margin for the value added by the distributor, usually calculated as a fair return on the fair value of the company's assets. This regulated tariff is periodically reviewed and reset by the regulatory agency of the government, with the exception of any components that are directly passed through to the customer, which are usually adjusted through an automated process. In many instances, the tariffs can be adjusted between scheduled regulatory resets pursuant to an inflation or another index. Customers with demand above a certain level are often unregulated and can choose to contract with generation companies directly and pay a wheeling fee, which is a fee to the distribution company for use of the distribution system. Most of our utilities operate as monopolies within exclusive geographic areas set by the regulatory agency and face very limited competition from other distributors.

        Set forth below is a discussion of the most material regulations we face in each country where we do business. In each country, the regulatory environment can pose material risks to our business, its operations and/or its financial condition. For further discussion of those risks, see the Risk Factors in Item 1A of this Annual Report on Form 10-K.

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Latin America

        Brazil.     Brazil has one main interconnected electricity system, the National Interconnected System. The power industry in Brazil is regulated by the Brazilian government, acting through the Ministry of Mines and Energy and the National Electric Energy Agency, ("ANEEL"), an independent federal regulatory agency that has authority over the Brazilian power industry. ANEEL supervises concessions for electricity generation, transmission, trading and distribution, including the setting of tariff rates, and supervising and auditing of concessionaires.

        On March 15, 2004, the Brazilian government launched a proposed new model for the Brazilian power sector. The New Power Sector Model created two energy markets: (1) the regulated contractual market for the distribution companies, and (2) the free contract environment market, designed for traders and other large volume users.

        Under the New Power Sector Model, every distribution utility is obligated to contract to meet 100% of its anticipated energy requirements over the coming five years in the regulated contractual market, through energy auctions from new proposed generation projects or existing generation facilities. The existing bilateral contracts are being honored, but cannot be renewed.

        In order to optimize the generation of electricity through Brazil's nationwide system, generation plants are allocated a generating capacity referred to as "assured energy" or the amount of energy representing the long-term average energy production of the plant defined by ANEEL. Together with the system operator, ANEEL establishes the amount of assured energy to be sold by each plant. The system operator determines generation dispatch which takes into account nationwide electricity demand, hydrological conditions and system constraints. In order to mitigate risks involved in hydroelectric generation, a mechanism is in place to transfer surplus energy from those who generated in excess of their assured energy to those who generated less than their assured energy. The energy that is reallocated through this mechanism is priced pursuant to an energy optimization tariff, designed to optimize the use of generation available in the system.

        The tariff charged by distribution companies to regulated customers is composed of a non-manageable cost component (Part A), which includes energy purchase costs and charges related to the use of transmission and distribution systems and is directly passed through to customers and a manageable cost component (Part B), which includes operations and maintenance costs based on a reference company (a model distribution company defined by ANEEL), recovery of depreciated assets and a component for the value added by the distributor (calculated as net asset base multiplied by pre-tax weighted average cost of capital). Part B is reset every four to five years depending on the specific concession. There is an annual tariff adjustment to pass through Part A costs to customers and to adjust the Part B costs by inflation less an efficiency factor (X-Factor). Distribution companies are also entitled to extraordinary tariff revisions, in the event of significant changes to their cost structure. The tariff reset methodology will be the subject of a Public Hearing scheduled to take place on February 27, 2008.

        AES businesses in Brazil consists of: two distribution businesses—Eletropaulo, serving over five million customers in the Sao Paulo area, and AES Sul, serving over one million customers in the state of Rio Grande do Sul; and two generation businesses—Tiete, a 2,650 MW hydro-generation facility, and Uruguaiana, a 639 MW generation facility.

        On July 4, 2007, Eletropaulo had its periodic tariff review and reset, which resulted in an average tariff reduction of 8.43%. As part of the tariff reset process, ANEEL recalculated the regulatory return on capital for all of the distribution companies in Brazil based on current Brazilian interest rates, which have decreased since the last reset and a lower country risk. The lower regulatory return was one of the main drivers of the reduction in tariff. The next tariff reset for Sul is scheduled for April 2008.

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        Sul is pursuing the annulment of ANEEL's Order 288, issued on May 16, 2002, in which ANEEL retroactively prohibited several companies, Sul included, the opportunity to choose not to participate in the "exposition relief mechanism," which allowed these companies to sell the energy from Itaipu into the spot market. This lawsuit has a financial impact of about R$437.8 million (historic values referring to 2001 and 2002) or approximately US$248 million as of December 31, 2007. Sul was granted a preliminary injunction ordering ANEEL to review the Brazilian Electric Energy Commercialization Chamber or ("CCEE") registers, calculations and liquidation. This lawsuit awaits the judge's decision regarding either ANEEL's petition to include CCEE as a co-defendant in the lawsuit or ANEEL's compliance with the injunction. If the operations registered in CCEE are cleared with the effect of Order #288 in place, Sul will owe a net amount of approximately R$80 million (historic values referring to 2001) or approximately US$45 million as of December 31, 2007. Sul is current on all CCEE charges and costs incurred subsequent to the period in question in the Order #288 matter. All amounts, including the amount owed to CCEE in the event Sul loses the case, are reserved in Sul's books.

        AES Tietê's concession agreement with the State of Sao Paulo for its generation plant includes an obligation to increase generation capacity by 15% by the end of 2007. AES Tietê, as well as other concessionaire generators, were not able to meet this requirement due to regulatory, environmental and hydrological constraints. The matter is under consideration by the State Government of São Paulo. AES is seeking to resolve the issue through an extension of the deadline or other options. An adverse decision by the regulator could have a negative impact on the value of the plant, but at this time the positions of ANEEL and the State of Sao Paulo are not known.

        Chile.     Chile has four electricity systems. The two major interconnected electricity systems are the Central Interconnected System ("SIC"), covering 92% of the population of the country and 75% of the load, and the Northern Interconnected System ("SING"), covering 6% of the population and 24% of the load.

        Under Chile's Electric Law, the electricity market is 100% privately-owned. The Chilean Ministry of Economy and Energy regulates the granting of concessions to generation companies for hydroelectric facilities and to distribution companies for distribution networks. Concessions are not required for thermoelectric power plants. The National Energy Commission defines energy policy and generally oversees electric regulation. The Superintendency of Electricity and Fuels supervises compliance with quality of service and safety standards. In 2005, an autonomous commission, the Panel of Experts, was established to resolve technical disputes within the electricity sector.

        The Chilean electricity system is principally a contract-based market in which customer demand is supplied through long-term PPAs with generators. The PPAs specify the volume, price and term conditions for the sale of energy and capacity. The Electric Law establishes two types of customers: unregulated customers with demand in excess of 2 MW and regulated customers with demand less than or equal to 2 MW which are usually supplied by distribution companies. Customers with demand between 0.5 MW and 2 MW are allowed to choose either the regulated or unregulated regime every four years. Unregulated customers freely negotiate supply contracts directly with the generators or distribution companies.

        In order to minimize the operational cost of the system, independent load centers dispatch plants on a mandatory basis in order to achieve the lowest cost of production available to meet the level of demand at any given time, constrained to maintain safety and reliability of service. As a result, the electricity systems are intended to be near-perfect markets for the generation of electricity in which the lowest cost producer is used to satisfy demand before the next lowest cost producer is dispatched. As a result, although generation companies freely enter into PPAs with distribution companies and other customers for the sale of capacity and energy, the electricity necessary to fulfill these agreements is provided by the contracting generation company only if the generation company's marginal cost of

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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 system marginal cost. The marginal cost of production is the cost of the least expensive next unit required to meet system demand at a given time.

        The cost of investment and operation of transmission systems are borne by generation companies and consumers (regulated tolls), in proportion to their use.

        In May 2005, there was an amendment to the Electric Law designed to provide incentive for future generation projects. In general, the law increased the flexibility of the regulated pricing system to respond to the higher generation cost scenario which resulted from the natural gas curtailments. One of the principal aspects of the law is the gradual replacement of node prices with prices awarded through public bid processes. Under the terms of the amendment, distribution companies are required to hold public bid processes for new supply contracts. Beginning in 2009, these contracts may not exceed 15 years, and will be awarded based on the lowest energy price offered.

        In addition, a procedure was established to govern the situation of distribution companies without contract supply. Law 20,220 ("Ley Tokman") published in the Official Gazette on September 14, 2007, obliges generation companies to continue with the energy supply to distribution companies that lose their contract either due to their bankruptcy, bankruptcy of their supplier, or the anticipated termination of the contract by arbitration award or court's decision. The law states that if a distribution company in that situation is not able to procure a new contract, then all the generation companies should supply to the distribution company at node prices (prices determined by the authority every six months), thereby assuming the costs of spot market prices, which becomes a credit only within a bankruptcy proceeding.

        On July 13, 2004, AES Gener and ESSA filed for arbitration with the International Court of Arbitration against certain Argentine natural gas producers, members of the Sierra Chata Consortium. The main purpose of the lawsuit was that the arbitral court ordered the producers to comply with their contractual obligations, deliver the total concentrated gas and/or to provide compensation for damages incurred by the plaintiffs. The International Court of Arbitration issued its final award on December 19, 2007. The award: (i) rejected the plaintiff's claim; (ii) declared the existence of a force majeure event; and (iii) declared the gas supply agreement terminated and exempted the Parties for any liability thereto.

        Colombia.     Colombia has one main national interconnected system (the SIN). In 1994 the Colombian Congress issued the laws of Domiciliary Public Services and the Electricity Law, which set the institutional arrangement and the general regulatory framework for the electricity sector. The Regulatory Commission of Electricity and Gas ("CREG") was created to foster the efficient supply of energy through regulation of the wholesale market, the natural monopolies of transmission and distribution, and by setting limits for horizontal and vertical economic integration. The control function was assigned to the Superintendency of Public Services.

        The wholesale market is organized around both bilateral contracts and a mandatory pool and spot market for all generation units larger than 20 MW. Each unit bids its availability quantities for a 24 hour period with one bid price set for those 24 hours. The dispatch is arranged by lowest to highest bid price and the spot price is set by the marginal price.

        The spot market started in July 1995, and in 1996 a capacity payment was introduced for a term of 10 years. In December 2006, a regulation was enacted that replaced the capacity charge with the reliability charge and established two implementation periods. The first period consists of a transition period from December 2006 to November 2012, during which, the price is equal to US$13.045 per MWh ("megawatt hour") and volume is determined based on firm energy offers which are pro-rated so that the total firm energy level does not exceed system demand. The second period, in which the

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reliability charge will be determined, based on the energy price and volume offers submitted by new market participants bidding for new capacity for the system begins in December 2012. The first reliability charge auction will be held in May 2008. The closing price of each auction will determine the reliability charge for existing plants.

        Argentina.     Argentina has one main national interconnected system. The National Electrical Regulating Agency is responsible for ensuring the compliance of transmission and distribution companies to concessions granted by the Argentine government and approves distribution tariffs. The regulatory entity authorized to manage and operate the wholesale electricity market in Argentina is Compañía Administradora del Mercado Mayorista Eléctrico, Sociedad Anómima, ("CAMMESA"), in coordination with the policies established by the National Secretariat of Energy. CAMMESA performs load dispatching and clears commercial transactions for energy and power. Sales of electricity may be made on the spot market at the marginal cost of energy to satisfy the system's hourly demand, or in the wholesale energy market under negotiated term contracts. As a result of the gas crisis, this mechanism was modified in 2003 by Resolution 240/03. At present, the price is determined as if all generating units in Argentina were operating with natural gas, even though they may be using other, more expensive, alternative fuels. In the case of generators using alternative fuels, CAMMESA pays the total variable cost of production, which may exceed the established spot price. Additionally, in the spot market, generators are also remunerated for their capacity to generate electricity in excess of supply agreements or private contracts executed by them.

        As the result of a political, social and economic crisis, the Argentine government adopted many new economic measures since 2002. The regulations adopted in the energy sector effectively terminated the use of the U.S. Dollar as the functional currency of the Argentine electricity sector. During 2004, the Energy Secretariat reached agreements with natural gas and electricity producers to reform the energy markets. In the electricity sector, the Energy Secretariat passed Resolution 826/2004, inviting generators to contribute a percentage of their sales margins to fund the development and construction of two new power plants to be installed by 2008/2009. The time period for the funding was set from January 2004 through December 2006 and was subsequently extended through December 2007. In exchange, the Government committed to reform the market regulation to match the pre-crisis rules prevailing before December 2001. Additionally, participating generators will receive a pro-rata ownership share in the new generation plants after ten years.

        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 were converted to pesos and were frozen at the peso national rate as of December 31, 2001. In October 2003, the Argentine Congress established a procedure for renegotiation of the public utilities concessions and extended the period for that process until December 31, 2007.

        On November 12, 2004, EDELAP, an AES distribution business, signed a Letter of Understanding with the Argentine government in order to renegotiate its concession contract and to start a tariff reform process, which was ratified by the National Congress on May 11, 2005. Final government approval was obtained on July 14, 2005. As a first step during this process, a Distribution Value Added ("DVA") increase of 28%, effective February 1, 2005, was granted. On October 24, 2005, EDEN and EDES, two AES distribution businesses, signed a Letter of Understanding with the Ministry of Infrastructure and Public Services of the Province of Buenos Aires to renegotiate their concession contracts and to start a tariff reform process, which was formally approved on November 30, 2005. An initial 19% DVA increase went effective in August 2005 and an additional 8% DVA increase became effective in January 2007.

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        Upon execution of these Letters of Understanding, AES agreed to postpone or suspend certain international claims. However, these Letters of Understanding provide that if the government does not fulfill its commitments, AES may restart the international claim process. AES has postponed any action until the tariff reset is finalized.

        El Salvador.     Electricity generators and distribution companies in El Salvador are linked through a single, main interconnected system managed by the Transactions Unit ("UT"). The El Salvador wholesale electricity market is comprised of: (1) a contract market based on contracts between electricity generators, distributors and trading companies and (2) a spot market for uncontracted electricity based upon bids from spot market participants specifying prices at which they are willing to buy or sell electricity.

        El Salvador has five electricity distribution companies, which came under private ownership as part of the privatization process that took place in 1998. AES controls four of these five distribution companies, encompassing about 80% of the national territory. El Salvador's electricity industry is regulated under the General Electricity Law enacted in October 1996 and subsequently amended twice in June 2003, and in October 2007. The Superintendencia General de Electricidad y Telecomunicaciones ("SIGET") is an independent regulatory authority that regulates the electricity and telecommunications sectors in El Salvador.

        The maximum tariff to be charged by distribution companies to regulated customers is subject to the approval of the SIGET. The components of the electricity tariff are (a) the average energy price ("energy charge"), (b) the charges for the use of the distribution network ("distribution charge"), and (c) customer service costs ("service charge"). Both the distribution charge and service charge are based on average capital costs as well as operation and maintenance costs of an efficient distribution company. The energy charge is adjusted every six months to reflect the changes in the spot market price for electricity. The distribution charge and service charge are approved by SIGET every five years and have two adjustments: (1) an annual adjustment considering the inflation variation and (2) an automatic adjustment in April, July and October, provided that change in the adjusted value exceeds the value in effect by at least 10%.

        The distribution tariff for all five distribution companies in El Salvador was reset on December 4, 2007. The approved tariff schedule is valid for the next five years (2008-2012). One outcome of the tariff reset was a significant reduction in the distribution value added component of the tariff for each of the company's distribution businesses. The company has since appealed the new tariff schedule to the El Salvador Supreme Court.

        Currently, the Company faces the following regulatory actions:

        a)    Connection and reconnection charge regulations: The SIGET is currently in the process of approving changes in the methodology used for calculating and applying connection and reconnection charges. It is estimated that the changes being approved could reduce the annual revenues associated with connection and reconnection by as much as 30%.

        b)    Quality of Service ("QoS") regulations: QoS regulations are entering into the permanent application regime. As a result, quality requirements will be higher and enforced to their full extent. In addition, the distribution companies could be required to compensate customers as a result of not meeting the prescribed quality standards.

        Dominican Republic.     The Dominican Republic has one main interconnected system and four isolated systems. Under current regulations, the Dominican government retains ultimate oversight and regulatory authority as well as control and ownership of the transmission grid and the hydroelectric facilities in the country. In addition, the government shares ownership in certain generation and distribution assets. The Dominican government's oversight responsibilities for the electricity sector are carried out by the National Energy Commission ("CNE") and the Superintendency of Electricity.

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        The spot market in the Dominican Republic commenced operations in June 2000. All participants in the Dominican electric system with available units are put in order of merit for dispatch based on lowest marginal cost. The order of merit determines the price to be paid for the electricity and the order in which each participant is dispatched. The order of merit is effective for one week. Sector participants may execute private contracts in which they agree to specific energy and capacity transactions.

        The regulatory framework in the Dominican electricity market establishes a methodology for calculating the firm capacity for each power generation unit. A new regulation recently passed by the CNE effectively changes the methodology for calculating firm capacity from a yearly to a monthly basis. While this new methodology has not yet been applied, it is estimated that it would result in a net reduction in the firm capacity payments paid to generators. The Company has sent a proposal to CNE proposing changes to the new firm capacity calculation that would help mitigate the impact of the new regulation.

        The financial and political crisis in the Dominican Republic during 2004 caused a financial crisis in the electricity sector. The inability to pass through higher fuel prices and the costs of devaluation led to a gap between collections at the distribution companies and the amounts required to pay the generators. In 2005 the government committed itself to stay current with its energy bills and also to cover the potential deficit of distribution companies. During 2005 and 2006, the government has been paying both the subsidies and its own energy bills on time. In December 2006, a bill with the primary goal of supporting fraud prosecution was sent to Congress by the Executive Branch. This bill was approved in July 2007 and is expected to help the sector reach financial sustainability by: criminalizing electrical fraud; setting new limits to non-regulated users in order to protect the distribution companies' market; allowing for service cutoff after only one bill due; and classifying as a national security breach the intentional damage or interruption of the national electricity grid.

        Despite these improvements, the electricity sector has not completely recovered from the financial crisis of 2004. In 2006 the electricity sector needed US$530 million in subsidies from the government to cover current operations. In 2007, the sector needed more than US$630 million and, at current fuel prices, the government has budgeted an amount of US$800 million for 2008.

        In October of 2006, CDEEE (Corporación Dominicana de Empresas Electricas Estatales), the state owned transmission and water company, began making public statements that it intends to seek to compel the renegotiation and/or recission of long-term power purchase agreements with certain power generating companies in the Dominican Republic. Although the details concerning CDEEE's statements are unclear and no formal government action has been taken, AES owns ownership interests in three power generation facilities in the country (AES Andres, Itabo and Dominican Power Partners) that could be adversely affected by the actions taken by the CDEEE, if any.

        Panama.     Panama has one main interconnected system (the NIS). The National Authority of Public Services regulates power generation, transmission, interconnection and distribution activities in the electric power sector and is responsible for the planning and coordination of the NIS. The National Dispatch Center ("CND") is responsible for planning, supervising and controlling the integrated operation of the NIS and for ensuring its safe and reliable operation. The dispatch order is determined by the CND, which dispatches electricity from generation plants based on lowest marginal cost.

        In order to mitigate spot market volatility, generators can enter into long-term PPAs with distribution companies and large users. The terms and contents of PPAs are determined through a competitive bidding process. Generators can also enter into reserve supply contracts with each other. Distribution companies are required to contract 100% of their annual energy requirements (although they can self-generate up to 15% of their demand).

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North America

        United States.     The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both Federal regulation, as implemented by the FERC, and regional regulation as defined by rules designed and implemented by an Independent System Operator ("ISO"). These rules for the most part govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. The current regulatory framework in the U.S. is the result of a series of regulatory actions that have taken place over the past two decades, as well as numerous policies adopted by both the federal government and the individual states that encourage competition in wholesale and retail electricity markets.

        The Federal government, through regulations promulgated by FERC, has primary jurisdiction over wholesale electricity markets and transmission services. While there have been numerous Federal statutes enacted during the past 30 years, including the Public Utility Regulatory Policy Act of 1978 ("PURPA"), the Energy Policy Act of 1992 ("EPAct 1992"), the Energy Policy Act of 2005 ("EPAct 2005"), there are two fundamental regulatory initiatives implemented by FERC during that time frame that directly impact our U.S. businesses:

(a)

FERC approval of market based rate authority beginning in 1986 for many providers of wholesale generation; and



(b)

FERC issuance of Order #888 in 1996 mandating the functional separation of generation and transmission operations and requiring utilities to provide open access to their transmission systems.

        Several of our generation businesses in the U.S. currently operate as Qualifying Facilities ("QF's") as defined under PURPA. These businesses entered into long-term contracts with electric utilities that had a mandatory obligation at that time, as specified under PURPA, to purchase power from QF's at the utility's avoided cost (i.e. the likely costs for both energy and facilities that would have been incurred by the purchasing utility if that utility had to provide its own generating capacity). EPAct 2005 later amended PURPA to eliminate the mandatory purchase obligation in certain markets, but did so only on a prospective basis. Cogeneration facilities and small power production facilities that meet certain criteria can be QFs. To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output, and must meet certain efficiency standards. To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet certain size criteria.

        Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators ("EWG's") as defined under EPAct 1992. These businesses are exempt from the PUHCA, and subject to FERC approval, have the right to sell power at market-based rates, either directly to the wholesale market or to a 3rd party offtaker such as a power marketer or utility/industrial customer.

        As an example, one of our larger generation businesses in the U.S. is Eastern Energy. A brief description of the regulatory environment under which Eastern Energy operates is provided below:

        Eastern Energy.     AES, through its Eastern Energy subsidiary, currently owns 4 coal-fired generation plants with a combined total capacity of 1,268 MWs located in the state of New York. The plants sell power directly to the New York Independent System Operator ("NYISO"), a FERC approved regional operator which manages the transmission system in New York and operates the state's wholesale electricity markets. NYISO is regulated as an electric utility by the FERC and has an Open Access Transmission Tariff on file that incorporates rates and conditions for use of the transmission system and a Market Services Tariff that describes the rules and conditions of use for the various markets.

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        The NYISO wholesale power markets are based on a combination of bilateral contracts, contracts for differences ("CFDs") which financially settle relative to an agreed upon index or floating price, and NYISO-administered day-ahead and real-time energy markets. The day-ahead market includes energy, regulation and operating reserves and is a financially binding commitment to produce or replace the products sold. The real time market, which also offers energy, regulation and operating reserves, is a balancing market and is not a financially binding commitment but rather a best effort standard. NYISO uses location based marginal pricing (i.e., pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the region) calculated at each node to account for congestion on the grid. Generators are paid the location marginal price at their node, while the end customer pays a zonal price that is the average of nodes within a zone. The market has a $1,000/MWh cap on bids for energy. However, market rules also incorporate scarcity pricing mechanisms when the market is short of required operating reserves that can result in energy prices above $1,000 MWh.

        In addition to our generation businesses, we also operate IPL, a vertically integrated utility located in Indiana. A brief description of the regulatory environment under which IPL operates is provided below:

        IPL.     As a regulated electric utility, IPL is subject to regulation by the FERC and the Indiana Utility Regulatory Commission ("IURC"). As indicated below, the financial performance of IPL is directly impacted by the outcome of various regulatory proceedings before the IURC and FERC.

        The IURC sets IPL's retail rates, has approval authority over any proposal to issue either equity or debt instruments, sets the rules and regulations that govern relations between IPL and its customers, prescribes the manner and form of IPL's accounting records, including the fixing of its depreciation rates, has approval authority over any sale, assignment, transfer or lease of IPL's assets, and establishes assigned service areas, within the boundaries of which IPL is authorized to furnish all retail electric service on an exclusive basis.

        IPL's tariff rates for electric service to retail customers (basic rates and charges) are set and approved by the IURC after public hearings ("general rate case"). General rate cases, which have occurred at irregular intervals, involve consumer groups and customers. The last general rate case for IPL was completed in 1995. In addition, pursuant to statute, the IURC is required to conduct a periodic review of the basic rates and charges of all utilities at least once every four years, but the IURC has the authority to review the rates of any utility at any time it chooses. Such reviews have not been subject to public hearings.

        The majority of IPL customers are served pursuant to retail tariffs that provide for the monthly billing or crediting to customers of increases or decreases, respectively, in the actual costs of fuel (including purchased power costs) consumed from estimated fuel costs embedded in basic rates, subject to certain restrictions on the level of operating income. These billing or crediting mechanisms are referred to as "trackers". This is significant because fuel and purchased power costs represent a large portion of IPL's total costs. In addition, IPL's rate authority provides for a return on IPL's investment and recovery of the depreciation and operation and maintenance expenses associated with the nitrogen oxide ("NOx") compliance construction program and its multipollutant plan. The trackers allow IPL to recover the cost of qualifying investments, including a return on investment, without the need for a general rate case.

        IPL may apply to the IURC for a change in its fuel charge every three months to recover its estimated fuel costs, including the fuel portion of purchased power costs, which may be above or below the levels included in its basic rates and charges. IPL must present evidence in each fuel adjustment charge, or FAC, proceeding that its has made every reasonable effort to acquire fuel and generate or purchase power, or both, so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

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        Independent of the IURC's ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in FAC. Additionally, customer refunds may result if a utility's rolling 12-month operating income, determined at quarterly measurement dates, exceeds a utility's authorized annual net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve month net operating income can be offset.

        In IPL's three most recently approved FAC filings, the IURC found that IPL's rolling annual net operating income was greater than the authorized annual net operating income by $24.6 million for the twelve months ended October 31, 2007; by $22.5 million for the twelve months ended July 31, 2007; and by $3.8 million for the twelve months ended April 30, 2007. Because IPL has had a cumulative net operating income deficiency, it has not been required to make customer refunds in its FAC proceedings. However, even though IPL has a cumulative net operating income deficiency, the IURC may still review IPL's basic rates and charges on a prospective basis at any time it chooses.

        In December 2007, IPL received a letter from the staff of the IURC requesting information relevant to its periodic review of its basic rates and charges. IPL subsequently provided information to staff and has engaged in discussions with staff on this matter. The IURC staff was concerned that the higher than usual 2007 earnings may continue in the future and IPL is evaluating alternatives for addressing the IURC's concerns. It is not clear what action, if any, the IURC staff will recommend as a result of its periodic review of IPL's basic rates and charges.

        IPL participates in the restructured wholesale energy market operated by the Midwest ISO ("MISO") and under the jurisdiction of the FERC since its implementation April 1, 2004. Prior to the implementation of these markets, IPL dispatched its generation and purchased power resources directly to meet its demands. In the MISO markets, IPL is obligated to offer its generation and to bid its demand into the market on an hourly basis. The MISO settles these hourly offers and bids based on location based marginal prices (i.e. pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the MISO region). The MISO evaluates the market participants' energy injections into, and withdrawals from, the system to economically dispatch the entire MISO system on a five-minute basis. Market participants are able to hedge their exposure to congestion charges, which result from constraints on the transmission system, with certain Financial Transmission Rights ("FTRs"). Participants are allocated FTRs each year and are permitted to purchase additional FTRs. As anticipated and in keeping with similar market start-ups around the world, location marginal prices are volatile, and there are process, data and model issues requiring editing and enhancement. IPL and other market participants have raised concerns with certain MISO transactions and the resolution of those items could impact our results of operations.

        In IPL's March 2006 proceeding before the commission, a consumer advocacy group representing some of IPL's industrial customers requested that a sub-docket be established to review MISO fuel cost components and IPL's generation and demand bidding practices. To date, no procedural schedule for this sub-docket has been established, and IPL cannot predict what refunds, if any, may be required, or for what period of time.

        Mexico.     Mexico has for the most part a single national electricity grid (referred to as the "National Interconnected System"), covering nearly all of Mexico's territory. The only exception is the Baja California peninsula which has its own separate electricity system. Article 27 of the Mexican Constitution reserves the generation, transmission, transformation, distribution, and supply of electric power exclusively to the Mexican State for the purpose of providing a "public service". The Federal Electricity Commission ("CFE"), by virtue of Article 1 of the Energy Law, is granted sole and exclusive responsibility for providing this public service as it relates to the supply, transmission and distribution of electric power.

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        In 1992, the Energy Law was amended to allow private parties to invest in certain activities in the Mexico electrical power market, under the assumption that "self-supply" generation of electric power is not considered a public service. These reforms allowed private parties to obtain permits from the Ministry of Energy for (i) generating power for self-supply; (ii) generating power through co-generation processes; (iii) generating power through independent production; (iv) small-scale production and (v) importing and exporting electrical power. Beneficiaries holding any of the permits contemplated under the Energy Law are required to enter into PPAs with the CFE with regard to all surplus power produced. It is under this basis that AES's Merida ("Merida") and Tamuin facilities operate. Merida, a majority owned 484 MW generation business, provides power exclusively to CFE under a long-term contract. Tamuin provides the majority of its output to two offtakers under long-term contracts, and can sell any excess or surplus energy produced to CFE at a predetermined day-ahead price.

Europe & Africa

        European Union.     European Union ("EU") member states are required to implement EU legislation, although there is a degree of disparity as to how such legislation is implemented and the pace of implementation in the respective member states. EU legislation covers a range of topics which impact the energy sector, including market liberalization and environmental legislation. The Company has subsidiaries which operate existing generation businesses in a number of countries which are member states of the EU, including the Czech Republic, Hungary, the Netherlands, Spain and the United Kingdom. The Company also has subsidiaries which are in the process of constructing a generation plant in Bulgaria. Bulgaria became a member state of the EU as of January 1, 2007.

        The principles of market liberalization in the EU electricity and gas markets were introduced under the Electricity and Gas Directives. In 2005, the European Commission ("EC"), the legislative and administrative body of the EU, launched a sector-wide inquiry into the European gas and electricity markets. In the context of the electricity market, the inquiry has to date focused on identifying issues related to price formation in the electricity wholesale markets and the role of long-term agreements as a possible barrier to entry with a view to improving the competitive situation. In January 2007, the EC published a proposal for a new common energy policy for Europe. The proposal focuses on consumer choice, fairer prices, cleaner energy and security of supply. A key component of the proposal is specific core energy objectives for the EU, including:

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20% reduction in EU GHG emissions, as compared with 1990 levels, or 30% if other developed nations agree to take similar action by 2020;



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increase in the use of renewable energy, to 20% of all energy consumed. This is a binding target; however, the plan allows flexibility in how each country contributes to the overall EU target;



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20% increase in energy efficiency; and



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increase in the use of biofuels, to 10% of all fuel used in transport.

        In September 2007, and again in January 2008, the EC published further draft legislative proposals to realize its common energy policy and its ambitious environmental goals. These proposals are however still in the very early stages of parliamentary deliberation and it is not possible to predict at this stage whether and when they will be adopted and implemented.

        Progress in the implementation of the directives referred to above varies from member state to member state. AES Generation businesses in each member state will be required to comply with the relevant measures taken to implement the directives. See "Air Emissions" below, for a description of these Directives.

        Kazakhstan.     Under the present regulatory structure, the electricity generation and supply sector in Kazakhstan is mainly regulated by the Ministry of Energy and Mineral Resources (the "Ministry"), the

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Committee for protection of competition of the Ministry of Industry and Commerce (the "Committee") and the Agency for Regulation of Natural Monopolies (the "Agency"). Each has the necessary authority for the supervision of the Kazakhstan power industry. However, the continuous changes in the law and Kazakhstani Government result in certain contradictions between different laws and regulations as well as the absence of a clear demarcation between rights and responsibilities of the Ministry, the Committee and the Agency. This in turn results in some uncertainty in the regulatory environment of the power sector.

        Kazakhstan has a wholesale power market, where generators and customers are free to sign contracts at negotiated prices. The power market infrastructure is evolving into a functioning centralized trading system. The government is planning to introduce a real-time balancing market in 2008. Since 2004, power producers, guaranteed suppliers and wholesale traders have been required to purchase and sell part of their electricity volumes on the electronic centralized power trading market. State-owned entities and natural monopolies are obligated to buy power through tenders and centralized trading. The wholesale transmission grid is owned by state-owned company KEGOC, which also acts as the system operator.

        To date, the Agency approves and regulates all tariffs for power transmission and distribution. Under the law, power companies have to notify the Agency of the proposed increase of their prices and the Agency has the right to veto such proposed tariff increases. Further, the Agency has the right to request decrease of the applicable tariffs and/or request introduction of the fixed prices for those power companies with prior record of anti-monopoly violations.

        Two hydro plants which are under AES concession, Ust-Kamenogorsk and Shulbinsk, together with Ust-Kamenogorsk TET, all located in the Eastern Kazakhstan region, are recognized by the Committee as dominant entities in the regional market because their aggregated share in the electricity supply commodity market in the region is 70%. These businesses are required to notify the competition authority about any power price increases for regional customers.

        Effective January 1, 2008, the Prime Minister of Kazakhstan has ordered all generating plants in Kazakhstan to maintain fourth quarter 2007 price levels through the first quarter of 2008 in order to help moderate high inflation rates in Kazakhstan. It is not clear whether this order is legal, or if it will be maintained beyond the first quarter of 2008. One of AES's plants, AES Ekibastuz GRES 1, has agreed to the tariff freeze. The other AES plants in Kazakhstan are reviewing their options, but to date have not made a decision with regard to tariff levels for 2008.

        In February 2007, the Committee initiated administrative proceedings against UK Hydro, and Shulbinsk Hydro, an AES subsidiary, and subsequently AES Ust-Kamengorskaya TET LLP, ("UKT") and Nurenergoservice LLP, AES's electricity trading business in Kazakhstan, for alleged violation of Kazakhstan's antimonopoly laws. Initial decisions have been reached by the Courts in these proceedings. See Item 3 Legal Proceedings in this Form 10-K.

        In October 2007, Kazakhstan adopted amendments into Subsoil Law which allow the government to terminate any subsoil agreements in case of a threat to national interests or other reasons. The new law may have an impact on AES's Maikuben coal mine operation, which has a subsoil agreement with the government of Kazakhstan.

        In December 2007, the Kazakhstan government approved a resolution to introduce State price regulation for power sold to customers in the Southern zone via the North-South interconnects. All power companies located in the Northern zone with customers located in the Southern region are required to submit price information to the regulator, which then has the right to decrease the tariff based on a reasonable profit return approach.

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        In January 2008, the Ministry of Economy proposed to the Government a new tax on profit of non-resident legal entities from the sale of shares of a Kazakhstan company with a subsoil agreement and property located in Kazakhstan.

        In January 2008, the Ministry of Environment protection submitted a proposal to the Government on ratification of the Kyoto protocol.

        In January 2008, the Committee was reorganized into an independent state body, an Agency charged with the protection of competition. The role and functions of this new Agency in relation to the regulation of the power sector are not clear and will be determined in new rules and legislation.

        On February 4, 2008, the Company entered into a sale and purchase agreement with Kazakhmys PLC ("Kazakhmys"). Under the agreement, the Company is selling to Kazakhmys certain indirect wholly-owned subsidiaries with operations in Kazakhstan, including AES Ekibastuz LLP, the operator of the AES Ekibastuz power plant, and Maikuben West LLP, the owner of the AES Maikuben coal mine, which collectively generated total revenues of approximately $185 million for the year ended December 31, 2007. The Company will receive consideration of approximately $1.1 billion at closing and will have the opportunity, over three years, to receive additional consideration of up to approximately $380 million under earn-out provisions, a management fee and a capital expenditure program bonus, for a total consideration of up to $1.48 billion. The management agreement, also entered into on February 4, 2008, pursuant to which an affiliate of the Company will manage the businesses sold to Kazakhmys, runs through December 2010, unless earlier terminated in accordance with the agreement. The sale is subject to certain regulatory and third-party approvals and to customary purchase price adjustments. The transaction is expected to close by the end of the second quarter of 2008.

        The Company is retaining its facilities in Eastern Kazakhstan, including Sogrinsk CHP and Ust-Kamenogorsk CHP; its facilities under concession agreements, Shulbinsk HPP and Ust-Kamenogorsk HPP; and its trading business, Nurenergoservice L.L.P. The litigation asserted against these businesses described above remains pending.

        Cameroon.     The law governing the Cameroonian electricity sector was passed in December 1998. The regulator is the Electricity Sector Regulatory Agency ("ARSEL") and its role is regulating and ensuring the proper functioning of the electricity sector, supervising the process of granting concessions, licenses and authorizations to operators, monitoring the application of the electricity regulation by the operators of the sector, approving and/or publicizing the regulated tariffs in the sector and safeguarding the interests of electricity operators and consumers. ARSEL has the legal status of a Public Administrative Establishment and is placed under the dual technical supervisory authority of the Ministries charged with electricity and finance.

        The concession agreement of July 2001 between the Republic of Cameroon and SONEL covers a twenty-year period. The first three years constituted a grace period to permit resolution of issues existing at the time of the privatization. In 2006, SONEL and the Cameroonian government signed an amended concession agreement. The amendment updates the schedule for investments to more than double the number of people SONEL serves over the next 15 years and provides for upgrading the generation, transmission and distribution system. Additionally, the concession agreement amended the tariff structure that results in an electricity price based on a reasonable return on the generation, transmission and distribution asset base and a pass through of a portion of fuel costs associated with increased thermal generation in years when hydrology is poor. The amended concession agreement has also reduced the cost of connection to facilitate access to electricity in Cameroon.

        Nigeria.     Nigeria's electricity sector consists of a generation market comprised of approximately 6 GW of installed capacity, with the state-owned entity, Power Holding Company of Nigeria ("PHCN") holding approximately 88% of the market share and two independent power producers ("IPPs") holding the remaining 12%. The IPPs, of which AES Nigeria Barges Ltd. ("AESNB") is one, maintain long term contracts with PHCN as the sole offtaker.

        All of Nigeria's distribution and transmission networks and companies are owned by state entities.

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        In March 2005, President Obasanjo signed the Power Sector Reform Bill into law, enabling private companies to participate in transmission and distribution in addition to electricity generation that had previously been legalized. The government has separated PHCN into eleven distribution firms, six generating companies, and a transmission company, all of which plan to be privatized. Several problems, including union opposition, have delayed the privatization indefinitely. However, it is envisaged that after the privatization process, the power sector will transform into a fully liberalized market.

        The Nigerian Electricity Regulatory Commission ("NERC") has also been established to regulate the electricity sector including the setting of tariffs and industry standards for future electricity sector development. NERC has asked the Company to revalidate our generation license. As part of the revalidation exercise, NERC is imposing certain conditions on the Company which are in conflict with its PPA and which may result in additional costs. The Company is reviewing the terms of the new license and plans to negotiate its terms and conditions to make them more consistent with our existing PPA. At this time, it is not clear what might be the final outcome of these negotiations. Under the terms of the PPA, the Company has a right to pass through any such cost and there is no cap. At present we estimate that the additional cost, if any, due to license will be about US$1 million.

        Hungary.     The Hungarian market has one main interconnected system. The state-owned electricity wholesaler, MVM, is the dominant exporter, importer and wholesaler of electricity. MVM's affiliated company; MAVIR is the Hungarian transmission system operator. Currently, Hungary is dependent on energy imports (mainly from Russia) since domestic production only partially covers consumption. Magyar Energia Hivatal (MEH), is the government entity responsible for regulation of the electricity industry in Hungary. The 2001 Electricity Act, which became effective in January 2003, brought the Hungarian electricity market into accord with EU directives in terms of third party access to the electricity grid and removal of subsidies, and defines a market that includes electricity generation companies, electricity distributors, power traders and an electricity grid operator.

        A gradual introduction of competition in the electricity market started in 2004, when the industrial users, constituting about 70% of total consumption, were allowed to choose their electricity suppliers. With the adoption of a new Electricity Act by Hungary in 2007, which became effective January 1, 2008, Hungary is taking the final legislative step to implement a fully liberalized electricity market. By virtue of the new electricity act, all customers become eligible to choose their electricity supplier. In the competitive market, generators sell capacity to wholesale traders, distribution companies, other generators, electricity traders and eligible customers at an unregulated price.

        As a member state of the EU, the Hungarian government notified the EC of arrangements concerning compensation to the state owned electricity wholesaler, MVM. The EC decided to open a formal investigation in 2005 to determine whether or not any government subsidies were provided by MVM to its suppliers which are incompatible with the common market. Although the EC has not completed its investigation or published any conclusions, the Commissioner for Competition has indicated informally that she considers the long term power purchase arrangements, including the contract with AES Tisza II power plant to be contrary to applicable EU laws and has encouraged the Hungarian government to terminate the long term PPAs. In December 2006, the Hungarian government carried out negotiations with the EC on this issue. If the Hungarian authorities follow the EC's decision, they may seek to revise the contracts and /or require the repayment of certain funds received by generators pursuant to the contracts. Simultaneously, at the end of 2006 and for the majority of 2007, the Hungarian government reintroduced administrative pricing for all electricity generators based on AES's agreements under the PPAs in place. A decision is expected in the near future.

        In January 2007, AES Summit Generation Limited, a holding company associated with AES operations in Hungary, notified the Hungarian government of a dispute concerning its acts and omissions related to AES's substantial investments in Hungary in connection with the re-introduction of

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the administrative prices for Hungarian electricity generators. In conjunction with this, AES and the Hungarian government have commenced International Centre for Settlement of Investment Disputes ("ICSID") arbitration proceedings under the Energy Charter Treaty in connection with the re-introduction of the administrative prices for the Hungarian electricity generators. In the meantime, pursuant to the new Electricity Act in force from January 1, 2008, administrative prices for electricity generators were subsequently abolished. Whether additional Hungarian government legislative initiatives pertaining to the electricity market related to recommendations of the EC Commissioner for Competition or other EU bodies or certain domestic political developments will be introduced in 2008 remains unclear. See Item 3 Legal Proceedings in this Form 10-K.

        In July 2007, the Prime Minister's office began a negotiation process with all the PPA generators regarding the possible renegotiation of the existing PPAs to bring them in line with the recommendations of the EC Commissioner for Competition. Some of the PPA generators agreed to amend their PPA which amendment was made conditional on the EU's approval; AES Tisza II's PPA has not been amended as part of this negotiation process.

        Ukraine.     The electricity sector in Ukraine is regulated by the National Energy Regulatory Commission ("NERC"). Electricity costs to end users in Ukraine consist of three main components: 1) the wholesale market tariff is the price at which the distributor purchases energy on the wholesale market, 2) the distribution tariff covers the cost of transporting electricity over the distribution network, 3) the supply tariff covers the cost of supplying electricity to an end user. The total cost to the end user permitted by the regulator under the distribution and supply tariff in each year is referred to as DVA. The distribution and supply tariffs for the five privatized distribution companies in Ukraine are established by the NERC on an annual basis, at which time an operational expense allowance is adjusted for inflation, and the tariff is adjusted for the amount of capital that was invested for the year and the amount of energy that was distributed. A change in the methodology with respect to the treatment of wages and salaries was effected at the end of 2007, by which adjustment for inflation has been replaced by adjustments based on the average industrial wage in the country.

        NERC twice authorized 25% increases in end user tariffs for residential customers in 2006. During 2007, the wholesale electricity market price increased approximately 21% due to increases in fuel prices and changes in the pricing arrangements for thermal generating companies. Due to Parliamentary elections in 2007, significant staff changes took place in the key regulatory agencies. In particular, new Minister of Energy and NERC Chairmen were appointed.

        It is expected that the tariff methodology applied to the calculation of AES Ukraine's tariffs will further evolve beginning in 2009 pursuant to provisions approved in 2008 that included: (i) the rate of return on initial investment will be revised with a floor of 11%; (ii) commercial losses will not be allowed in the tariff; and (iii) the "black box" concept of operational expenses other than wages and salaries fixed in 2003 and inflated since then on an annual basis will be revised as well.

        United Kingdom.     AES Kilroot ("Kilroot") is subject to regulation by the Northern Ireland Authority for Utility Regulation ("NIAUR"). Under the terms of the generating license granted to Kilroot, the NIAUR has the right to review and, subject to compliance with certain procedural steps and conditions, require the early termination in 2010 of the long-term PPAs under which Kilroot currently supplies electricity to Northern Ireland Electricity ("NIE") until 2024.

        On March 21, 2007, Order 2007 (Single Wholesale Market—Northern Ireland) was enacted, which provided for the introduction and regulation of a single wholesale electricity market for Northern Ireland and the Republic of Ireland that began operation in November of 2007. The legislation grants powers to the Department of Enterprise, Trade and Investment, or NIAER, for a period of two years to modify existing arrangements within the electricity market in Northern Ireland, including the power to modify existing licenses and/or require the amendment or termination of existing agreements or arrangements, to allow for the creation of a single wholesale electricity market. Modifications have

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been made to Kilroot's license and agreements to accomplish the objectives of the single market and to allow for the separation of NIE into constituent bodies and the extraction of the management of the transmission system ("SONI") from NIE. These activities have been completed with reasonably minimal impact and with the maintenance of existing underlying guarantees for Kilroot.

        Revenues from the new market include a regulated capacity and an energy payment based on the system marginal price ("SMP"). Bidding principles restrict bids to short run marginal cost ("SRMC"). Total annual capacity payments are calculated as the product of the annualised fixed cost of a best new entrant ("BNE") peaking plant multiplied by the capacity required to meet the security standard. This capacity pot is then distributed on the basis of plant availability.

        Despite the new market mechanisms, Kilroot has continued to operate under its existing PPA which is able to subsist within the single wholesale market, although operating dispatch instructions are now a function of the new market inputs and system constraints and no longer the exclusive decision of NIE. The impact on the business has been minimal as the relatively higher price of gas has led Kilroot to be dispatched consistently during peak winter demand. However, NIAUR has sought to invoke the introduction of the single electricity market ("SEM") as a rationale for the early termination in 2010 of the long-term PPAs between Kilroot and NIE. Kilroot is currently challenging by way of judicial review proceedings the determination of NIAUR that the introduction of the SEM constitutes requisite arrangements to allow such early termination.

        Following receipt of a complaint from Friends of the Earth claiming that the existing long-term PPAs with NIE in Northern Ireland are incompatible with EU law, the EC has requested certain information from the UK authorities related to these agreements, including information pertaining to the Kilroot power plant and PPA in order to enable the EC to assess the complaint. Department of Enterprise Trade and Investment ("DETI") submitted a response to the EC on January 12, 2007 and there have been no further developments.

        Czech Republic.     The electricity industry in Czech Republic is dominated by three vertically integrated companies ("CEZ", "E.ON" and "PRE") that both supply and distribute power. CEZ which owns approximately 70% of the installed capacity produced approximately 73% of the Czech Republic's energy in 2006. Electricity distribution is also dominated by these three entities: CEZ (62%); E.ON (25%); and PRE (13%). There are 22 generators with installed capacity of over 50 MW and 25 generators with installed capacities between 5-50 MW, none of which have a market share greater than 3%. In accordance with EU directives regarding market liberalization, all customers are able to select their energy supplier.

        Since August 2007, the Prague Energy Exchange has been trading energy in the form of base load and peak load on a monthly, quarterly and annual basis. The majority of electricity is, however, still traded on a bilateral basis between generators and distributors, independent traders (there are six major active traders plus more than 20 smaller traders in the market) and also between generators and final customers. As early as February 2008, it is expected that a day ahead spot market will be incorporated into the Energy Exchange. AES Bohemia's electricity, steam, water and compressed air output is governed under bi-lateral contracts with industrial and municipal customers in the surrounding area.

        Spain.     Spain is a member of the EU and as such the Spanish Government has been taking steps to liberalize the country's electricity sector in accordance with EU directives. Since January 1, 2003, all customers have been eligible to choose their electricity supplier.

        AES currently operates and holds a 71% ownership interest in a 1,200 MW natural gas-fired plant located in Cartagena on the southeast coast of Spain, Cartagena. The plant sells energy into the Pan-Iberian electricity market ("MIBEL"). The MIBEL market was created in January 2004 when Spain and Portugal signed a formal agreement. This new market allows generators in the two countries to sell their electricity on both sides of Spanish-Portuguese border as one single market. OMEL,

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Spain's energy market regulator and Portugal's equivalent, OMIP, merged in April 2006, creating OMI, a single operator for the MIBEL electricity market, which began in the summer of 2006 with the objective of setting up mechanism for harmonizing tariffs and of integrating the current management functions of the spot and forward markets.

        The state-owned transmission company, Red Eléctrica de España ("REE") owns 99% of the 400 kilovolt ("kV") grid and 98% of the 220 kV network. REE also operates as system operator and is responsible for technical management of the system and for monitoring transmission. Under the country's energy plan, REE plans to invest in strengthening the mainland grid, connecting new plants and improving interconnection throughout the country. Cartagena has two agreements in place with the REE: one governing the construction of the interconnection and the other specifying the specific terms and conditions of access.

        In September 2002, the Spanish Cabinet approved a 10-year energy plan which focuses on meeting the country's energy future energy requirements. The plan also reflects reliance on Special Systems which represents energy output from the facilities supplied by renewable energy sources, waste and cogeneration plants and provides for new renewable tariffs (Royal Decree 661/207) and favorable regulation.

        Turkey.     The wholesale generation and distribution market in Turkey is primarily a bi-lateral market dominated by state-owned entities. The state-owned Electricity Generation Company ("EUAS") and its subsidiaries, comprise approximately 23 GW of generation capacity and represent 48% of the market. Private producer's account for another 35% and auto-producers and other industrial parties, the remaining 17%. The transmission network is owned and controlled by TEIAS, the State Transmission Company. TETAS, the Wholesale Market Pool, sets wholesale price based on average procurement costs from EUAS, auto-producers and Build Own Operate/Build Own Transfer/Transfer of Operating Rights producers. This wholesale price represents the buying price for TEDAS, the State Distribution Company, which controls distribution in 20 out of 21 regions. There is also a balancing spot market, with prices typically 20% higher than TETAS, which is growing and has a capacity of 70 Gigawatt hours ("GWh") of daily trade. Distribution companies can procure 100% of their needs from TETAS, but can also source up to 15% from other sources. Additionally, eligible customers, using greater than 3 GWh annually, can contract through channels other than TEDAS.

        Retail electricity prices are determined by the distribution company or companies and approved by the electricity regulator, EMRA.

        Turkey has introduced a "renewable" feed-in tariff that sets a floor for renewable generation (wind and run off river hydro) for the first 10 years of operation. The floor is between 5.0 – 5.5 € cents per kWh and decreed by EMRA each year. AES's Turkey hydro assets fall under the renewable feed-in tariffs.

        In efforts to move to a fully liberalized market, Turkey began a formal tender process to privatize three of its distribution companies owned by the State Distribution Company in 2006, but then postponed the process indefinitely. The Turkish government has also announced plans to privatize all the state-owned generation assets by 2009, except for large hydro plants.

Asia & Middle East

        China.     In 2002, a new industry regulator, China's National Electricity Regulatory Commission (CERC) was established to promulgate the rules for and supervise the operation of the electric power industry and to administer electric power service licenses.

        In 2005, with a view to implementing power industry reform, the National Development and Reform Commission (NDRC) released interim regulations governing on-grid tariffs, along with two other regulations governing transmission and retail tariffs (the "Interim Regulations"). Pursuant to the Interim Regulations, prior to adoption of a pooling system, the on-grid tariffs shall be appraised and

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ratified by the pricing authorities by reference to the economic life of power generation projects and determined in accordance with the principle of allowing independent power producers to cover reasonable costs and to obtain reasonable returns. Such costs were defined to be the average costs in the industry and reasonable returns will be calculated on the basis of the interest rate of China's long-term Treasury bond plus certain percentage points. At this stage it is uncertain when the foregoing provision will be implemented or whether it will have a material adverse effect on the Company's businesses. In the long-term, foreign investors may be under pressure to renegotiate their PPAs.

        China's central government also issued a policy allowing the on-grid tariffs to be pegged to the fuel price in the case of significant fluctuations in fuel price. Seventy percent (70%) of the increase in fuel costs may be passed through in the tariff. Pursuant to this policy, the tariffs of our coal-fired facilities in China were increased in 2005 and 2006 to alleviate the escalation of fuel price.

        In March 2007, the Anhui Development and Reform Commission, ("ARDC") issued a notice to our Hefei business in China, that the State Council had made a decision to shut down small, inefficient, generation facilities in the Anhui Province by 2010 that were adding to the high level of pollution in China. As a result Hefei, an 115MW oil-fueled generation facility, will be shut down by the government in March 2008. The plant will become the property of the Anhui Province and AES Hefei will receive termination compensation of approximately $30 million (net of liquidation and termination costs). At this time neither party has any legal obligations related to this transaction, therefore AES will continue to reflect Hefei's results of operations within continuing operations of AES Corporation.

        Negotiations with the offtaker and the government are close to the final stage. The offtaker has agreed in principle to pay a termination fee to Hefei in March 2008. It is expected that Hefei will sign the termination agreement with the offtaker in March 2008 under the provincial government's supervision.

        In May 2007, NDRC and State Environmental Protection Administration of China also issued a regulation requiring that all new built coal-fuel power plants have to install and operate FGD equipment, and the operational coal-fuel power plants also need to complete the FGD equipment installation. All plants which have installed and operated FGD equipment will be granted on-grid tariff premium of RMB 0.15/MWH.

        India.     India's power sector is regulated by the Central Electricity Regulatory Commission ("CERC") at the national level and respective State Electricity Regulatory Commissions ("SERCs") at the state level. CERC is responsible for regulating interstate generation and central transmission, while intra-state generation, distribution and transmission are regulated by SERCs.

        In 2003, the Government of India enacted the Electricity Act 2003 to establish a framework for a multi-seller-multi-buyer model for the electricity industry and introduced significant changes in India's electricity sector. In accordance with the Electricity Act the Government of India came out with the National Electricity Policy in February 2005 and in January 2006 published the National Tariff Policy. The policies established deadlines to implement different provisions of the Electricity Act. However, the pace of actual implementation of the reform process is contingent on the respective state governments and SERCs as electricity is a "concurrent" subject in India's constitution.

        Under the Electricity Act, there is no license required to set up generation plants and generators are allowed to sell to state utilities, traders, and open access consumers. The access to consumers is subject to regulatory provisions on transmission corridor availability and payment of cross subsidy surcharge.

Environmental and Land Use Regulations

        Overview.     The Company is subject to various international, national, state and local environmental and land use laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharge of effluents into water and the use of water, waste disposal, remediation,

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noise pollution, contamination at current or former facilities or waste disposal sites, wetlands preservation and endangered species. Many of the countries in which the Company does business also have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from, such assets. In addition, international projects funded by the World Bank are subject to World Bank environmental standards, which tend to be more stringent than local country standards. The Company often has used advanced environmental technologies (such as circulating fluidized bed ("CFB") coal technologies or advanced gas turbines) in order to minimize environmental impacts.

        Environmental laws and regulations affecting electric power generation facilities are complex, change frequently and have become more stringent over time. The Company has incurred and will continue to incur capital costs and other expenditures to comply with environmental laws and regulations. See Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Expenditures in this Form 10-K for more detail. If these regulations change or the enforcement of these regulations becomes more rigorous, the Company and its subsidiaries may be required to make significant capital or other expenditures to comply. There can be no assurance that the businesses operated by the subsidiaries of the Company would be able to recover any of these compliance costs from their counterparties or customers such that the Company's consolidated results of operations, financial condition and cash flows would not be materially adversely affected.

        Various licenses, permits and approvals are required for our operations. Failure to comply with permits or approvals, or with environmental laws, can result in fines, penalties, capital expenditures, interruptions or changes to our operations. While the Company has at times been out of compliance with environmental laws and regulations, past non-compliance has not resulted in the revocation of material permits or licenses and has not had a material adverse effect on our business, financial conditions or results of operations and we have expeditiously corrected the non-compliance as required. See Item 3 Legal Proceedings in this Form 10-K for more detail with respect to environmental disclosure.

        Greenhouse Gas Laws, Protocols and Regulations.     In 2006, the Company's subsidiaries operated businesses which had total approximate CO ₂ emissions of 84 million metric tonnes (ownership adjusted and including approximately 6 million metric tonnes from EDC which the Company sold in 2007). Approximately 38 million metric tonnes of the 84 million metric tonnes were emitted in the United States (both figures ownership adjusted). The following is an overview of both the regulations that currently apply to our businesses and those that may be imposed over the next few years. Such regulations could have a material adverse effect on the electric power generation businesses of the Company's subsidiaries and on the Company's consolidated results of operations, financial condition and cash flows. In addition, while the Company is attempting to build a climate solutions business which would develop GHG credits for use by the Company and/or for sale, as set forth in the Risk Factor entitled " Our Alternative Energy businesses face uncertain operational risks ," there is no guarantee that the business will be successful. And even if our climate solutions business is successful, the level of benefit is unclear with regard to the impact of legislation or litigation concerning GHG emissions.

International

        In July 2003, the European Community "Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading" was created, which requires member states to limit emissions of CO ₂ from large industrial sources within their countries. To do so, member states are required to implement EC-approved national allocation plans ("NAPs"). Under the NAPs, member states are responsible for allocating limited CO ₂ allowances within their borders. Directive 2003/87/EC does not dictate how these allocations are to be made, and NAPs that have been submitted thus far have varied their allocation methodologies. For these and other reasons, uncertainty remains with respect to the implementation of the European Union Emissions Trading System ("EU ETS") that commenced in January 2005. The European Union has announced that it intends to keep the EU ETS in place after 2012, even if the

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Kyoto Protocol is not extended. The Company's subsidiaries operate seven electric power generation facilities and another subsidiary has one under construction within six member states which have adopted NAPs to implement Directive 2003/87/EC. Based on its current analyses, the Company does not expect that achieving and maintaining compliance with the NAPs to which its subsidiaries are subject will have a material impact on its consolidated operations or results. In particular, the risk and benefit associated with achieving compliance with applicable NAPs at several facilities of the Company's subsidiaries are not the responsibility of the Company's subsidiaries as they are subject to contractual provisions that transfer the costs associated with compliance to contract counterparties. Certain Company subsidiaries will, however, bear some or all of the risk and benefit associated with compliance with applicable NAPs at certain facilities. Based upon anticipated: operations, CO ₂ emission allowance allocations, and the costs to acquire offsets and emission allowances for compliance purposes, the Company's subsidiaries have not incurred material costs to comply with Directive 2003/87/EC and applicable NAPs.

        On February 16, 2005, the "Kyoto Protocol to the United Nations Framework Convention on Climate Change" (the "Kyoto Protocol") became effective. The Kyoto Protocol requires the 40 developed countries that have ratified it (40 in total) to substantially reduce their GHG emissions, including CO ₂ . The vast majority of developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements. Many of the countries in which the Company's subsidiaries operate have no reduction obligations under the Kyoto Protocol. In addition, of the 28 countries that the Company's subsidiaries currently operate in, all but three—the United States (including Puerto Rico), Kazakhstan and Turkey—have ratified the Kyoto Protocol. We are targeting production of approximately 24 million tonnes of issuable CO ₂ equivalent GHG offsets by 2011 in Asia, Africa, Europe and Latin America by developing and operating projects under the Clean Development and Joint Implementation Mechanisms of the Kyoto Protocol. There is no guarantee that we will be successful in this business. To date, compliance with the Kyoto Protocol and EU ETS has not had a material adverse effect on the Company's consolidated results of operations, financial condition and cash flows. In December 2007, a United Nations Climate Change Conference was held in Bali, Indonesia. Over 180 countries sent representatives and a majority agreed to negotiate further reductions in GHG emissions for the period beginning after 2012 when Kyoto Protocol expires. The negotiations are expected to conclude prior to 2009. At present, the Company cannot predict whether compliance with the Kyoto Protocol or any agreements reached at the Climate Change Conference will have a material impact on the Company.

        Even though it has been announced that the EU ETS will remain in place even if the Kyoto Protocol expires in 2012, there remains significant uncertainty with respect to the implementation of NAPs post-2012. The EU has indicated that a portion of the emission allowances given to member states will need to be auctioned under the NAPs and the Company cannot predict with any certainty if compliance with such programs in 2012 and beyond will have a material adverse effect on its consolidated operations or results.

United States

        Currently in the United States there are no federal mandatory GHG emissions reduction programs (including CO ₂ ) affecting the electric power generation facilities of the Company's subsidiaries. The U.S. Congress is debating a number of proposed GHG legislative initiatives, but to date there have been no new federal laws in this area. Although several bills have been introduced in the U.S. Congress that would require reductions in CO ₂ emissions, the Company is not able to predict whether any federal mandatory CO ₂ emissions reduction program will be adopted and implemented in the immediate future. The Company will continue to monitor new developments with respect to the possible federal regulation of CO ₂ emissions from electricity power generation facilities.

        On April 2, 2007, the U.S. Supreme Court issued its decision in a case involving the regulation of CO ₂ emissions from motor vehicles under the U.S. Clean Air Act. The Court ruled that CO ₂ is a

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pollutant which potentially could be subject to regulation under the U.S. Clean Air Act and that the U.S. Environmental Protection Agency (the "U.S. EPA") has a duty to determine whether CO ₂ emissions contribute to climate change or to provide some reasonable explanation why it will not exercise its authority. The U.S. EPA has not yet made any such determination, and current federal policy regarding CO ₂ emissions favors voluntary reductions, increased operating efficiency and continued research and technology development. However, the Court's decision and stimulus from regulators, politicians, non-governmental organizations, private parties and the courts and other factors could lead to a determination by the U.S. EPA to regulate CO ₂ emission from mobile and stationary sources, including electric power generation facilities. The Company will continue to monitor developments with respect to the regulation of CO ₂ emissions under the U.S. Clean Air Act.

        Ten northeastern states have entered into a memorandum of understanding under which the states coordinate to establish rules that require the reduction in CO ₂ emissions from power plant operations within those states. This initiative is called the Regional Greenhouse Gas Initiative ("RGGI"). A number of these states in which our subsidiaries have generating facilities, including Connecticut, Maryland, New York and New Jersey, are in the process of implementing rules to effectuate RGGI. Six of the ten states have issued draft regulations to implement RGGI for public comment. As proposed, RGGI is scheduled to become effective January 1, 2009 through various individual state laws and/or regulations. If RGGI is duly effectuated in each state, its laws and regulations will impose a cap on baseline CO ₂ emissions during the 2009 through 2014 period, and mandate a ten percent reduction in CO ₂ emissions during the 2015 to 2019 period. RGGI establishes a cap-and-trade program whereby power plants will require a carbon allowance for each ton of CO ₂ . As currently proposed, it is anticipated that a significant portion of the allowances will be distributed through an auction process, which would require fossil fuel fired generating units to purchase allowances instead of direct allocations to affected generators.

        The Company's Eastern Energy business is located in New York. On October 24, 2007, the State of New York, a RGGI participant, released its proposed rule to implement its state program as part of RGGI. Public comments on the rule were due on December 24, 2007. Under the proposed New York implementing rule, each budgeted source of CO ₂ emissions will be required to surrender one CO ₂ allowance for each CO ₂ metric tonne emitted during a three-year compliance period. All power generating facilities in the State of New York would be subject to the rule. Unlike the previously implemented Federal SO ₂ and NOx cap-and-trade emissions programs, under the New York proposed rule, all allowances would be auctioned (rather than allocated to affected generating units) except for several small set aside accounts. Accordingly, the proposed rule, if implemented as proposed, would require that CO ₂ emitters acquire CO ₂ allowances either from the proposed auction or in the secondary emissions trading market. The details of the proposed auction mechanism, such as whether the auction would be regional or state-by-state, the frequency of the auctions, whether the allowance value will include a minimum reserve price, auction participant guidelines, creation of a fungible RGGI allowance emission unit that is legally tradable and enforceable across state borders and detailed market monitoring rules, are still being determined by New York State agencies.

        The Company's Thames business is located in Connecticut. The State of Connecticut passed legislation, effective July 1, 2007, which requires the Connecticut Department of Environmental Protection to auction, rather than allocate, CO ₂ emission allowances required by electric power generation facilities to comply with RGGI. The agency proposed regulations to implement RGGI on January 8, 2008. As in New York, these regulations and the auction mechanism are still being developed.

        The Company's Warrior Run business is located in Maryland. In April 2006, the Maryland General Assembly passed the Maryland Health Air Act which, among other thing things, required the State of Maryland to join RGGI. The Maryland Department of Environment ("MDE") proposed regulations to implement RGGI on February 1, 2008. The proposed rule would require 100% of the allowances the State receives to be auctioned. The proposed regulations, however, include a safety valve to control the

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economic impact of the CO ₂ cap-and-trade program. If the auction closing price reaches $7, up to 50% of a year's allowances will be reserved for purchase by electric power generation facilities located within Maryland at $7 per allowance, regardless of auction prices.

        The Company's Red Oak business is located in New Jersey. The State of New Jersey adopted the Global Warming Response Act in July 2007 which established goals for the reduction of GHG emissions in the State. In furtherance of these goals, in January 2008, additional legislation authorized the New Jersey Department of Environmental Protection to allocate or auction allowances under RGGI and established requirements for the agency to follow if allowances are conveyed to electricity generators using an auction. The agency has not yet proposed its regulation to implement RGGI. The Global Warming Response Act also directed the New Jersey Board of Utility Control to adopt an emissions portfolio standard or other mechanism to regulate any additional importation of power into the State as a result of RGGI.

        In 2006, of the approximately 38 million metric tonnes of CO ₂ emitted in the United States by the businesses operated by our subsidiaries (ownership adjusted), approximately 12 million metric tonnes were emitted in U.S. states participating in RGGI. We believe that due to the absence of allowance allocations, RGGI as currently contemplated could have an adverse impact on the Company's consolidated results of operations, financial condition and cash flows. For forecasting purposes, the Company has modeled the impact of CO ₂ compliance for 2009-2012 for its businesses that are subject to RGGI and that may not be able to pass through compliance costs. The model utilizes an allowance price of $3.05 per metric ton under RGGI. The source of this per tonne price estimate was the average price of a CO ₂ emissions voluntary compliance instrument on the Chicago Climate Exchange for the six month period ending November 15, 2007. The model also assumes, among other things, that RGGI will be structured solely on the public auction of allowances and that certain costs will be recovered by our subsidiaries. Based on these assumptions, the Company estimates that the RGGI compliance costs could be approximately $30 million per year in 2009-2012. Given all of the uncertainties surrounding RGGI, including those discussed in the "Business—Regulatory Matters—Environmental and Land Use Regulations" section of this 10-K and the fact that the assumptions utilized in the model may prove to be incorrect, there is a significant risk that our actual compliance costs under RGGI will differ from our estimates by a material amount.

        The Company's Southland and Placerita businesses are located in California. On September 27, 2006, the Governor of California signed the Global Warming Solutions Act of 2006, also called Assembly Bill 32 ("A.B. 32"). A.B. 32 directs the California Air Resources Board to promulgate regulations that will require the reduction of CO ₂ and other GHG emissions to 1990 levels by 2020. On January 25, 2007, the California Public Utility Commission adopted a CO ₂ emission performance standard applicable to all electricity generated within the state or delivered into the State. In addition, on February 8, 2008, the California Public Utility Commission issued a proposed recommendation that the State develop a GHG emission cap-and-trade program applicable to entities which "deliver" electricity into California. This program is expected to become effective in 2012.

        In February 2007, the governors of the Western U.S. states (Arizona, New Mexico, California, Washington and Oregon) established the Western Climate Initiative ("WCI"). The WCI has since been joined by two other states (Utah and Montana) and two Canadian provinces (British Columbia and Manitoba). Participating states and provinces have agreed to cut GHG emissions to 15% below 2005 levels by 2020 and they are considering the implementation of a cap-and-trade program for the electricity industry to achieve this reduction. The actual regulatory design of this program is not yet known.

        The Company owns IPL which is located in Indiana. On November 15, 2007, nine Midwestern state governors (including the governor of Indiana) and the premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord ("MGGRA") committing the participating states and province to reduce GHG emissions through the implementation of a cap-and-trade program.

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        The Company owns a power generation facility in Hawaii. On June 30, 2007, the governor of Hawaii signed GHG legislation. By December 1, 2009, Hawaii's Greenhouse Gas Emissions Reduction Task Force will deliver to the legislature a work plan and regulatory scheme designed to reduce emissions of greenhouse gases to 1990 levels by 2020.

        At this time, other then the estimated impact of CO ₂ compliance noted above for certain of its businesses that are subject to RGGI, the Company has not estimated the costs of compliance with other potential U.S. federal, state or regional CO ₂ emissions reductions legislation or initiatives, such as A.B. 32, WCI, MGGRA and potential Hawaii regulations, due to the fact that these proposals are in earlier stages of development and any final regulations, if adopted, could vary drastically from current proposals. Although complete specific implementation measures for any federal regulations, RGGI, A.B. 32, WCI, MGGRA and the Hawaiian regulations have yet to be finalized, these GHG-related initiatives may potentially affect a number of the Company's U.S. subsidiaries. Any federal, state or regional legislation or regulations adopted in the U.S. that would require the reduction of GHG emissions could have a material adverse effect on the Company's consolidated results of operations, financial condition and cash flows.

        The possible impact of any future federal legislation or regulations or any regional or state proposal will depend on various factors, including but not limited to:

•

the geographic scope of legislation and/or regulation (e.g., federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;



•

the level of reductions of CO ₂ being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated CO ₂ reduction (e.g., 10% reduction from 1990 CO ₂ emission levels, 20% reduction from 2000 CO ₂ emission levels, etc.);



•

the legislative structure (e.g., a CO ₂ cap-and-trade program, a carbon tax, CO ₂ emission limits, etc.);



•

in any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;



•

the price of offsets and emission allowances in the secondary market, including any price floors on the costs of offsets and emission allowances and price caps on the cost of offsets and emission allowances;



•

the operation of and emissions from regulated units;



•

the permissibility of using offsets to meet reduction requirements (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects) and the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);



•

whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;



•

how the price of electricity is determined at the affected businesses, including whether the price includes any costs resulting from any new CO ₂ legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;



•

any impact on fuel demand and volatility that may affect the market clearing price for power;

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•

the effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;



•

the availability and cost of carbon control technology; and



•

any opportunities to change the use of fuel at the generation facilities of our subsidiaries or opportunities to increase efficiency.

NY Consent Decree

        In 2005, the Company entered into a Consent Decree (the "2005 Consent Decree") with the State of New York, and New York State Electric and Gas Corporation ("NYSEG") which resolves violations of Clean Air Act requirements alleged to have occurred prior to the Company's acquisition of the Greenidge, Westover, Jennison and Hickling plants. Under the terms of the 2005 Consent Decree, the Company is required to undertake projects to reduce emissions of air pollutants ("Upgrade Projects") or to cease operations of electric generating units at the plants. The Company completed an Upgrade Project at Greenidge, is undertaking an Upgrade Project at Westover and has ceased operations of the electric generating units at Hickling and Jennison. In accordance with the 2005 Consent Decree, the Company is required to provide notifications to the New York State Department of Environmental Conservation ("NYSDEC") regarding the status of the Upgrade Projects and upon completion, to propose new final emissions limits for NYSDEC's approval. The Company has received NYSDEC approval for proposed final emissions limits applicable to AES Greenidge and will submit proposals for new final emission limits to NYSDEC for approval after the Upgrade Project at Westover is complete.

        Other Air Emission Regulations.     The U.S. Clean Air Act and various state laws and regulations regulate emissions of air pollutants, including sulfur dioxide ("SO ₂ "), NOx and particulate matter ("PM"). The applicable rules and the steps taken by the Company to comply are discussed in further detail below.

        Regarding NOx emissions, the U.S. EPA has required adjustments to state implementation plans (the "NOx SIP Call") so that coal-fired electric generating facilities in 21 U.S. states and the District of Columbia had to either (i) reduce their NOx emissions to levels equal to allowances under the plan or (ii) purchase NOx emissions allowances from other operators to meet actual emissions levels by May 31, 2004.

        Subsequently, the U.S. EPA finalized two rules that are relevant to our U.S. coal-fired power plants. The first rule, the "Clean Air Interstate Rule" ("CAIR"), was promulgated on March 10, 2006 and will require additional allowance surrender for SO ₂ and NOx emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR will be implemented in two phases. The first phase will begin in 2009 and 2010 for NOx and SO ₂ , respectively. A second phase with additional allowance surrender obligations for both air emissions begins in 2015. To implement the required emission reductions for this rule, the states will establish emission allowance-based "cap-and-trade" programs. CAIR has been challenged in federal court. No decisions have been rendered to date on the challenge.

        The second rule, the Clean Air Mercury Rule ("CAMR"), was promulgated on March 15, 2006 and as proposed required reductions of mercury emissions from coal-fired power plants in two phases. The first phase was to begin in 2010 and require nationwide reduction of coal-fired power plant mercury emissions from 48 to 38 tons per year. The second phase was to begin in 2018 and require nationwide reduction of mercury emissions from these sources from 38 tons per year to 15 tons per year. CAMR also established stringent mercury emission performance standards for new coal-fired power plants. However, on February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit ruled that CAMR as promulgated violated the Clean Air Act and vacated the rule. At this time it is not known whether the U.S. EPA will attempt to appeal the decision to the U.S. Supreme Court.

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        Also, a number of states have indicated that they intend to impose more stringent emission limitations on power plants within their states rather than promulgate rules consistent with the CAIR and CAMR cap-and-trade programs. In response to CAIR, CAMR and potentially more stringent U.S. state initiatives on SO ₂ and NOx emissions, the Company completed installing selective catalytic reduction ("SCR") and other NOx control technologies at three coal-fired units of our subsidiary, Indianapolis Power and Light ("IPL"). In addition, the Company completed a multi-pollutant control project at its Greenidge power plant in the state of New York and is scheduled to complete construction of a similar project at its Westover power plant in the state of New York by the end of 2008. In addition, a flue gas desulphurization scrubber upgrade project was completed at the IPL Petersburg power plant, and construction of an SCR system at our Deepwater petroleum coke-fired power plant near Houston, Texas was completed in March 2007.

        While the exact impact and cost of CAIR, any new federal mercury rules and any related state proposals cannot be established until, in the case of CAIR, the states complete the process of assigning emission allowances to our affected facilities, and in the case of the other rules, until they are promulgated, there can be no assurance that the Company's business, financial conditions or results of operations would not be materially and adversely affected by these new rules.

        NYSDEC previously promulgated regulations requiring electric generators to reduce SO ₂ emissions by 50% below current Clean Air Act standards. The SO ₂ regulations began to be phased in beginning on January 1, 2006 with implementation to have been completed by January 1, 2008. These regulations also establish stringent NOx reduction requirements year-round, rather than just during the summertime ozone season. As a result, in order to operate the Company's four electric generation facilities located in New York, installation of pollution control technology will likely be required.

        In July 1999, the U.S. EPA published the "Regional Haze Rule" to reduce haze and protect visibility in designated federal areas. On June 15, 2005, U.S. EPA proposed amendments to the Regional Haze Rule that, among other things, set guidelines for determining when to require the installation of "best available retrofit technology" ("BART") at older plants. The amendment to the Regional Haze Rule required states to consider the visibility impacts of the haze produced by an individual facility, in addition to other factors, when determining whether that facility must install potentially costly emissions controls. The Regional Haze Rule was further amended on October 6, 2006 when U.S. EPA promulgated a rule allowing states to impose alternatives to BART, including emissions trading, if such alternatives were demonstrated to be more effective than BART. States were required to submit their regional haze state implementation plans to the U.S. EPA by December 2007.

        In Europe the Company is, and will continue to be, required to reduce air emissions from our facilities to comply with applicable EC Directives, including Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants (the "LCPD"), which sets emission limit values for NOx, SO ₂ , and particulate matter for large-scale industrial combustion plants for all member states. Until June 2004, existing coal plants could "opt-in" or "opt-out" of the LCPD emissions standards. Those plants that opted out will be required to cease all operations by 2015 and may not operate for more than 20,000 hours after 2008. Those that opted-in, like the Company's AES Kilroot facility in the United Kingdom, must invest in abatement technology to achieve specific SO ₂ reductions. Kilroot is installing a new flue gas desulphurization system that is scheduled for commission in 2008. The Company's other coal plants in Europe are either exempt from the Directive due to their size or have opted-in but will not require any additional abatement technology to comply with the LCPD.

        Water Discharges.     The Company's facilities are subject to a variety of rules governing water discharges. In particular the Company is evaluating the impact of the U.S. Clean Water Act Section 316(b) rule regarding existing power plant cooling water intake structures issued by the U.S. EPA in 2005 (69 Fed. Reg. 41579, July 9, 2004) and the subsequent Circuit Court of Appeals decision

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which vacated significant portions of the rule (Docket Nos. 04-6692 to 04-6699). The rule as originally issued would affect 12 of the Company's U.S. power plants, the rule's requirements would be implemented via each plant's National Pollutant Discharge Elimination System ("NPDES") water quality permit renewal process, and these permits are usually processed by state water quality agencies. To protect fish and other aquatic organisms, the 2004 rule requires existing steam electric generating facilities to utilize the best technology available for cooling water intake structures. To comply it must first prepare a Comprehensive Demonstration Study to assess each facility's effect on the local aquatic environment. Since each facility's design, location, existing control equipment and results of impact assessments must be taken into consideration, costs will likely vary. The timing of capital expenditures to achieve compliance with this rule will vary from site to site. However, as a result of the 2007 United States Court of Appeals for the Second Circuit decision (Docket Nos. 04-6692 to 04-6699) remanding major parts of the 2005 rule back to U.S. EPA, there could be further delays in implementing the rule at those affected facilities located in states which have either not been delegated authority to implement Section 316(b) of the U.S. Clean Water Act or are awaiting more specific direction from the U.S. EPA before proceeding. The U.S. EPA is currently drafting a new rule to address the Second Circuit's decisions and a draft of the new rule is expected to be issued later this year. Certain states in which the Company operates power generation facilities, such as New York State, have been delegated authority and are moving forward with best technology available determinations in the absence of any final rule from U.S. EPA. At present, the Company cannot predict whether compliance with the anticipated new 316(b) rule will have a material impact on our operations or results.

        Waste Management.     In the course of operations, the Company's facilities generate solid and liquid waste materials requiring eventual disposal. With the exception of coal combustion products ("CCP"), its wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCP, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities include CCP, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl ("PCB") contaminated liquids and solids. The Company endeavors to ensure that all its solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations.

Subsequent Events

        On February 4, 2008, we entered into a stock purchase agreement with Kazakhmys. Under the agreement, we will sell to Kazakhmys two indirect wholly-owned subsidiaries with operations in Kazakhstan, AES Ekibastuz LLP and Maikuben West LLP, which generated total revenues of approximately $185 million for the year ended December 31, 2007. We will receive consideration of approximately $1.1 billion at closing and will have the opportunity to receive additional consideration of up to approximately $380 million under earn-out provisions, a management fee and a capital expenditure program bonus, for a total consideration of up to $1.48 billion. The management agreement, also entered into on February 4, 2008, has a three year term and runs through December 2010.

        We are retaining our facilities in Eastern Kazakhstan including Sogrinsk CHP and Ust-Kamenogorsk CHP its facilities under concession agreements, Shulbinsk HPP and Ust-Kamenogorsk HPP; and our energy trading business, Nurenergoservice L.L.P. The sale is subject to certain regulatory and third-party approvals and to customary purchase price adjustments. The transaction is expected to close by the end of the second quarter of 2008.

        In March 2007, the Anhui Development and Reform Commission, ("ARDC") issued a notice to our Hefei business in China, that the State Council had made a decision to shut down small, inefficient, generation facilities in the Anhui Province by 2010 that were adding to the high level of pollution in

45

China. As a result Hefei, an 115 MW oil-fueled generation facility, will be shut down by the government in March 2008. The plant will become the property of the Anhui Province and AES Hefei will receive termination compensation of approximately $30 million (net of liquidation and termination costs). At this time neither party has any legal obligations related to this transaction, therefore AES will continue to reflect Hefei's results of operations within continuing operations of AES Corporation.

        In early February 2008, the Company signed an agreement with National Power Corporation ("NPC"), a state owned utility, to purchase a 600 MW coal-fired generation facility in Masinloc, Philippines for $930 million. The purchase will be primarily financed by non-recourse debt. The 10 year old plant, which is currently partially operational, consists of two turbines; one turbine is currently in working condition while the second turbine will require maintenance to return it to a working condition. The plant will require an additional investment over the next six to 12 months to bring it up to the required operational standard. The Masinloc plant is not currently compliant with government mandated environmental regulations. Masinloc will receive permits from the Philippine government to allow for the continued operation of the plant during its environmental clean-up period. The sale is expected to close in April 2008.

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