EXHIBIT 99.1

ITEM 1. BUSINESS

Overview

We are a global power company. We own a portfolio of electricity generation and distribution businesses on five continents in 28 countries, with total capacity of approximately 40,500 Megawatts (“MW”) and distribution networks serving over 12 million people as of December 31, 2010. In addition, we have more than 2,000 MW under construction in six countries. Our global workforce of approximately 29,000 people helps provide 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 three decades we have been committed to providing safe and reliable energy.

We own and 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 within a defined service area.

Our assets are diverse with respect to fuel source and type of market, which helps reduce certain types of operating risk. Our portfolio employs a broad range of fuels, including coal, gas, fuel oil, biomass and renewable sources such as hydroelectric power, wind and solar, which reduces the risks associated with dependence on any one fuel source. Our presence in mature markets helps reduce the volatility associated with our businesses in faster-growing emerging markets. In addition, our Generation portfolio is largely contracted, which reduces the risk related to market prices of electricity and fuel. We also attempt to limit risk by hedging some of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. However, our business is still subject to these and other risks, which are further described in Item 1A.—Risk Factors of the 2010 Form 10-K.

Our goal is to maximize value for our shareholders through continued focus on increasing the profitability of our existing portfolio and increasing cash flow while managing our risk and employing rigorous capital allocation. We will continue to seek prudent expansion of our traditional Generation and Utilities lines of business, along with expansion of wind, solar and energy storage, through acquisitions or greenfield developments. Portfolio management remains an area of focus through which we have sold and expect to continue to sell or monetize a portion of certain businesses or assets when market values appear attractive. Furthermore, we will continue to focus on improving our business operations and management processes, including our internal controls over financial reporting.

Key Lines of Business

AES’ primary sources of revenue and gross margin today are from Generation and Utilities. 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, 2010, 2009 and 2008, respectively, is shown below. Operating results for integrated utilities, which have both Generation and Utilities, are reflected in the Utilities amounts below.

Revenue

($ in billions)

Gross Margin

($ in billions)

⁽¹⁾  Utilities gross margin includes the margin from generation businesses owned by the Company and from whom the utility purchases energy.

Generation

We currently own or operate a generation portfolio of approximately 34,100 MW, excluding the generation capabilities of our integrated utilities, consisting of 100 Generation facilities in 25 countries on five continents at our generation businesses. We also have approximately 1,700 MW of capacity currently under construction in four countries. 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 in terms of capacity. Our Generation business uses a wide range of technologies and fuel types including coal, combined-cycle gas turbines, hydroelectric power and biomass. Generation revenue was $7.0 billion, $5.6 billion and $6.7 billion for the years ended December 31, 2010, 2009 and 2008, respectively.

Performance drivers for our Generation businesses include, among other factors, plant reliability, fuel costs, power prices, volume and fixed-cost management. Growth in the Generation business is largely tied to securing new power purchase agreements (“PPAs”), expanding capacity in our existing facilities and building or acquiring new power plants.

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The majority of the electricity produced by our Generation businesses is sold under long-term PPAs, to wholesale customers. In 2010, approximately 69% of the revenue from our Generation business was from plants that operate under PPAs of three 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 arrangements where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. These long-term contractual agreements help reduce the volatility of our cash flows and earnings and also 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 it has negotiated.

Our Generation businesses with long-term contracts face most of their competition from other utilities and independent power producers (“IPPs”) 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 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, directly in the spot market or, in some cases, at regulated prices. 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. Competitive factors for these facilities include price, reliability, operational cost and third-party credit requirements.

Utilities

AES utility businesses distribute power to over 12 million people in seven countries on five continents and consist primarily of 14 companies owned or operated under management agreements, each of which operate in defined service areas. These businesses also include 15 generation plants in two countries with generation capacity totaling approximately 4,600 MW. These businesses have a variety of structures ranging from pure distribution businesses to fully integrated utilities, which generate, transmit and distribute power. For instance, our wholly owned subsidiary in the U.S., Indianapolis Power & Light (“IPL”), has the exclusive right to provide retail services to approximately 470,000 customers in Indianapolis, Indiana. Eletropaulo Metropolitana Electricidad de São Paulo S.A (“AES Eletropaulo” or “Eletropaulo”), serving the São Paulo metropolitan region for over 100 years, has approximately six million customers and is the largest electricity distribution company in Brazil in terms of revenue and electricity distributed. In Cameroon, we are the primary generator and distributor of electricity and in El Salvador we provide distribution services to serve more than 77% of the country’s electricity customers. Utilities revenue was $9.1 billion, $7.8 billion and $7.8 billion for the years ended December 31, 2010, 2009 and 2008, respectively.

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, regulations and variations in weather conditions in the areas in which they operate.

Utilities face relatively little direct competition due to significant barriers to entry which are present in these markets. 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. Competition is a factor in efforts to acquire existing businesses. In this arena, we compete against a number of other market participants, some of which have greater financial resources, have been engaged in distribution related businesses

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for longer periods of time 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.

Renewables and Other Initiatives

In recent years, as demand for renewable sources of energy has grown, we have placed increasing emphasis on developing projects in wind, solar and other renewable initiatives including energy storage. In 2005, we started a wind generation business (“AES Wind Generation”), which currently has 20 plants in operation in five countries totaling approximately 1,800 MW in generation capacity and is one of the largest producers of wind power in the U.S. In addition, 264 MW are under construction in four countries. In March 2008, we formed AES Solar Energy LLC (“AES Solar”), a joint venture with Riverstone Holdings, LLC (“Riverstone”), a private equity firm, which has since commenced commercial operations of nine plants totaling 37 MW of solar projects in France, Greece and Spain. We have a few projects producing GHG credits in Asia, Europe and Latin America. We also have a line of business to develop and implement utility scale energy storage systems (such as batteries), which store and release power when needed. While none of these initiatives are currently material to our operations, we believe that as these businesses grow, they may become a material contributor to our operations. However, there are risks associated with these initiatives, which are further described in Item 1A.—Risk Factors of the 2010 Form 10-K. As further described in “Our Organization and Segments” below, some of these projects are managed within the region in which they are located, while others are managed as separate business units and reported as set forth below.

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 the 2010 Form 10-K include the following:

• risks associated with our disclosure controls and internal controls over financial reporting;

• risks related to our high level of indebtedness;

• risks associated with our ability to raise needed capital;

• external risks associated with revenue and earnings volatility;

• risks associated with our operations; and

• risks associated with governmental regulation and laws.

The categories of risk identified above are discussed in greater detail in Item 1A.—Risk Factors of the 2010 Form 10-K. These risk factors should be read in conjunction with Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related notes included elsewhere in this report.

Our Organization and Segments

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. In addition, 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 into geographic regions, and each region is led by a regional president or other senior executive responsible for managing those businesses. The regional presidents report to our Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). Both our CEO and COO are based in Arlington, Virginia.

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The Company’s segment reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively, “EMEA”), which reflects how we manage the business internally. Additionally, AES Wind Generation is managed within our North America region. For financial reporting purposes, the Company has six reportable segments which include:

• Latin America—Generation;

• Latin America—Utilities;

• North America—Generation;

• North America—Utilities;

• Europe—Generation;

• Asia—Generation.

Corporate and Other—The Company’s Europe Utilities, Africa Utilities, Africa Generation and AES Wind Generation businesses as well as the Company’s renewables initiatives are reported within “Corporate and Other” because they do not require separate disclosure under segment reporting accounting guidance. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion of the Company’s segment structure used for financial reporting purposes.

The following describes our businesses as they are aligned in our segment reporting structure for financial reporting purposes.

Latin America

Our Latin America operations accounted for 71%, 72% and 72% of consolidated AES revenue in 2010, 2009 and 2008, respectively. The following table provides highlights of our Latin America operations:

Countries	Argentina, Brazil, Chile, Colombia, Dominican Republic, El Salvador and Panama
Generation Capacity	11,907 Gross MW
Utilities Penetration	8.6 million customers (49,280 Gigawatt Hours (“GWh”))
Generation Facilities	55 (including 3 under construction)
Utilities Businesses	8
Key Generation Businesses	Gener, Tietê and Alicura
Key Utilities Businesses	Eletropaulo and Sul

The graph below shows the breakdown between our Latin America Generation and Utilities segments as a percentage of total Latin America revenue and gross margin for the years ended December 31, 2010, 2009, and 2008. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 8-K for information on revenue from external customers, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment.

Revenue ($ in billions)   Gross Margin ($ in billions)  

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Latin America Generation. Our largest generation business in Latin America, AES Tietê (“Tietê”), located in Brazil, represents approximately 18% of the total generation capacity in the state of São Paulo and is the tenth largest generator in Brazil. AES holds a 24% economic interest in Tietê. In Argentina, we are the third largest private power generator contributing 11% of the country’s total power generation capacity. In Chile, we are the second largest generator of power. We currently have three new generation plants under construction—two coal plants in Chile and one hydro plant in Panama with a combined generation capacity of 1,011 MW.

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

Generation

Business	Location	Fuel	Gross MW		AES Equity Interest (Percent, Rounded)			Year Acquired or Began Operation
Alicura	Argentina	Hydro		1,050		99	%		2000
Central Dique	Argentina	Gas/Diesel		68		51	%		1998
Gener—TermoAndes	Argentina	Gas/Diesel		643		71	%		2000
Los Caracoles(1)	Argentina	Hydro		125		0	%		2009
Paraná-GT	Argentina	Gas/Diesel		845		99	%		2001
Quebrada de Ullum(1)	Argentina	Hydro		45		0	%		2004
Rio Juramento—Cabra Corral	Argentina	Hydro		102		99	%		1995
Rio Juramento—El Tunal	Argentina	Hydro		10		99	%		1995
San Juan—Sarmiento	Argentina	Gas/Diesel		33		99	%		1996
San Juan—Ullum	Argentina	Hydro		45		99	%		1996
San Nicolás	Argentina	Coal/Gas/Oil		675		99	%		1993
Tietê(2)	Brazil	Hydro		2,657		24	%		1999
Uruguaiana	Brazil	Gas		639		46	%		2000
Gener—Electrica Santiago(3)	Chile	Gas/Diesel		479		64	%		2000
Gener—Electrica Ventanas(4)	Chile	Coal		272		71	%		2010
Gener—Energía Verde(5)	Chile	Biomass/Diesel		49		71	%		2000
Gener—Gener(6)	Chile	Hydro/Coal/Diesel		953		71	%		2000
Gener—Guacolda(7),(8)	Chile	Coal/Pet Coke		608		35	%		2000
Gener—Norgener	Chile	Coal/Pet Coke		277		71	%		2000
Chivor	Colombia	Hydro		1,000		71	%		2000
Andres	Dominican Republic	Gas		319		100	%		2003
Itabo(9)	Dominican Republic	Coal		295		50	%		2000
Los Mina	Dominican Republic	Gas		236		100	%		1996
Bayano	Panama	Hydro		260		49	%		1999
Chiriqui—Esti	Panama	Hydro		120		49	%		2003
Chiriqui—La Estrella	Panama	Hydro		48		49	%		1999
Chiriqui—Los Valles	Panama	Hydro		54		49	%		1999
				11,907

⁽¹⁾  AES operates these facilities through management or operations and maintenance (“O&M”) agreements and owns no equity interest in these businesses.

⁽²⁾  Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava, Promissão and seven other small hydroelectric plants below Tietê’s wholly-owned subsidiary “PCH Minas Ltda”.

⁽³⁾  Gener—Electrica Santiago plants: Nueva Renca and Renca.

⁽⁴⁾  Gener—Electrica Ventanas plant: Nueva Ventanas.

⁽⁵⁾  Gener—Energia Verde Plants: Constitución, Laja and San Francisco de Mostazal.

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⁽⁶⁾  Gener—Gener plants: Alfalfal, Laguna Verde, Laguna Verde Turbogas, Los Vientos, Maitenas, Queltehues, Santa Lidia, Ventanas and Volcán.

⁽⁷⁾  Gener—Guacolda plants: Guacolda 1, Guacolda 2, Guacolda 3 and Guacolda 4.

⁽⁸⁾  Unconsolidated entities, the results of operations of which are reflected in Equity in Earnings of Affiliates.

⁽⁹⁾  Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine).

Generation under construction

Business	Location	Fuel	Gross MW		AES Equity Interest (Percent, Rounded)			Expected Year of Commercial Operations
Angamos	Chile	Coal		518		71	%		2011
Campiche	Chile	Coal		270		71	%		2013
Changuinola I	Panama	Hydro		223		100	%		2011
				1,011

Latin America Utilities. Each of our Utilities businesses in Latin America sells electricity under regulated tariff agreements and has transmission and distribution capabilities but none of them has generation capability. AES Eletropaulo, a consolidated subsidiary of which AES owns a 16% economic interest and which has served the São Paulo, Brazil area for over 100 years, has approximately six million customers and is the largest electricity distribution company in Brazil in terms of revenue and electricity distributed. Pursuant to its concession agreement, 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 17% of Brazil’s GDP and 40% of the population in the State of São Paulo. AES Sul (“Sul”), a wholly-owned subsidiary, serves over one million customers. In El Salvador, our Utilities businesses provide electricity to over 81% of the country, serving more than one million customers.

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

Distribution

Business	Location		Approximate Number of Customers Served as of 12/31/2010		GWh Sold in 2010		AES Equity Interest (Percent, Rounded)			Year Acquired
Edelap		Argentina		329,000		2,776		90	%		1998
Edes		Argentina		172,000		894		90	%		1997
Eletropaulo		Brazil		5,832,000		33,860		16	%		1998
Sul		Brazil		1,181,474		8,320		100	%		1997
CAESS		El Salvador		516,000		2,060		75	%		2000
CLESA		El Salvador		304,000		786		64	%		1998
DEUSEM		El Salvador		62,000		108		74	%		2000
EEO		El Salvador		229,000		476		89	%		2000
				8,625,474		49,280

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North America

Our North America operations accounted for 17%, 19% and 19% of consolidated revenue in 2010, 2009 and 2008, respectively. The following table provides highlights of our North America operations:

Countries	U.S., Puerto Rico and Mexico
Generation Capacity	13,396 Gross MW
Utilities Penetration	470,000 customers (16,537 GWh)
Generation Facilities	19
Utilities Businesses	1 integrated utility (includes 4 generation plants)
Key Generation Businesses	Eastern Energy, Southland and TEG/TEP
Key Utilities Business	IPL

The graph below shows the breakdown between our North America Generation and Utilities segments as a percentage of total North America revenue and gross margin for the years ended December 31, 2010, 2009 and 2008. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 8-K for information on revenue from external customers, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment.

Revenue ($ in billions)	Gross Margin ($ in millions)

North America Generation. Approximately 86% of the generation capacity is supported by long-term power purchase or tolling agreements. Our North America Generation business consists of six gas-fired, ten coal-fired and three petroleum coke-fired plants in the United States, Puerto Rico and Mexico.

Our largest generation business is AES Southland. This business operates three gas-fired plants, representing generation capacity of 4,327 MW, in the Los Angeles basin under a long-term tolling agreement. In addition, in the western New York power market, AES Eastern Energy operates four of our coal-fired plants, Cayuga, Greenidge, Somerset and Westover, representing generation capacity of 1,169 MW, providing power to this market under short-term contracts, as well as in the spot electricity market.

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

Generation

Business	Location	Fuel	Gross MW		AES Equity Ownership (Percent, Rounded)			Year Acquired or Began Operation
Mérida III	Mexico	Gas		484		55	%		2000
Termoelectrica del Golfo (TEG)	Mexico	Pet Coke		230		99	%		2007
Termoelectrica del Peñoles (TEP)	Mexico	Pet Coke		230		99	%		2007
Southland—Alamitos	USA—CA	Gas		2,047		100	%		1998
Southland—Huntington Beach	USA—CA	Gas		904		100	%		1998
Southland—Redondo Beach	USA—CA	Gas		1,376		100	%		1998
Thames	USA—CT	Coal		208		100	%		1990
Hawaii	USA—HI	Coal		203		100	%		1992
Warrior Run	USA—MD	Coal		205		100	%		2000
Red Oak	USA—NJ	Gas		832		100	%		2002
Cayuga(1)	USA—NY	Coal		306		100	%		1999
Greenidge(1)	USA—NY	Coal		106		100	%		1999
Somerset(1)	USA—NY	Coal		675		100	%		1999
Westover(1)	USA—NY	Coal		82		100	%		1999
Shady Point	USA—OK	Coal		360		100	%		1991
Beaver Valley	USA—PA	Coal		125		100	%		1985
Ironwood	USA—PA	Gas		710		100	%		2001
Puerto Rico	USA—PR	Coal		454		100	%		2002
Deepwater	USA—TX	Pet Coke		160		100	%		1986
				9,697

⁽¹⁾  In March 2011, the Company met the held for sale criteria and expects to dispose of these businesses within the next twelve months. Until the businesses are sold, they will be reported as held for sale businesses and their earnings will be reported as part of discontinued operations.

North America 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 generates, transmits, distributes and sells electricity to approximately 470,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL owns and operates four generation facilities that provide more than 96% of the electricity it distributes. Two of the generation facilities are 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 capacity is 3,699 MW. Approximately 45% 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, commercial and all other which made up 37%, 40%, 15% and 8%, respectively, of North America Utilities revenue for 2010.

IPL’s generation facilities

Business	Location	Fuel	Gross MW	AES Equity Interest (Percent, Rounded)			Year Acquired or Began Operation
IPL(1)	USA—IN	Coal/Gas/Oil	3,699		100	%		2001

⁽¹⁾  IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg.

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Distribution

Business	Location	Approximate Number of Customers Served as of 12/31/2010		GWh Sold in 2010		AES Equity Interest (Percent, Rounded)			Year Acquired
IPL	USA—IN		470,000		16,537		100	%		2001

Europe

The following table provides highlights of our Europe operations:

Countries	Czech Republic, Hungary, Jordan, Kazakhstan, Netherlands, Spain, Turkey, Ukraine and the United Kingdom
Generation Capacity	7,986 Gross MW
Utilities Penetration	1.8 million customers (9,904 GWh)
Generation Facilities	21 (including 3 under construction)
Utilities Businesses	4
Key Generation Businesses	Ballylumford, Cartagena, Kilroot, Tisza II
Key Utilities Businesses	Kievoblenergo and Rivneenergo

Our Utilities operations in Europe are discussed further under Corporate and Other below.

Europe Generation. Our Generation operations in Europe accounted for 8%, 6% and 7% of our consolidated revenue in 2010, 2009 and 2008, respectively. In 2007, we began commercial operation of AES Cartagena (“Cartagena”), our first power plant in Spain, with capacity of 1,199 MW. As a result of the new accounting guidance for variable interest entities, the Company consolidated Cartagena effective January 1, 2010. In prior periods, the results of operations for Cartagena were included in the Equity in Earnings of Affiliates line item on the Consolidated Statements of Operations. Today, AES operates four power plants in Kazakhstan which account for 8% of the country’s total installed generation capacity. In September 2009, AES completed construction and launched commercial operation of the 380 MW combined-cycle Amman East power plant in Jordan. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 8-K for revenue, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment. Key business drivers of this segment are: foreign currency exchange rates, new legislation and regulations including those related to the environment.

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Set forth below is a list of our Europe Generation facilities:

Generation

Business	Location		Fuel		Gross MW		AES Equity Interest (Percent, Rounded)			Year Acquired or Began Operation
Bohemia		Czech Republic		Coal/Biomass		50		100	%		2001
Borsod(1)		Hungary		Biomass/Coal		71		100	%		1996
Tisza II		Hungary		Gas/Oil		900		100	%		1996
Tiszapalkonya(1)		Hungary		Coal/Biomass		90		100	%		1996
Amman East		Jordan		Gas		380		37	%		2008
Shulbinsk HPP(2)		Kazakhstan		Hydro		702		0	%		1997
Sogrinsk CHP		Kazakhstan		Coal		301		100	%		1997
Ust—Kamenogorsk HPP(2)		Kazakhstan		Hydro		331		0	%		1997
Ust—Kamenogorsk CHP		Kazakhstan		Coal		1,354		100	%		1997
Elsta(3)		Netherlands		Gas		630		50	%		1998
Cartagena		Spain		Gas		1,199		71	%		2006
Damlapinar(3)(4)		Turkey		Hydro		16		51	%		2010
Girlevik II-Mercan(3)		Turkey		Hydro		12		51	%		2007
Kepezkaya(3)(4)		Turkey		Hydro		28		51	%		2010
Yukari-Mercan(3)		Turkey		Hydro		14		51	%		2007
Ballylumford		United Kingdom		Natural Gas		1,246		100	%		2010
Kilroot(5)		United Kingdom		Coal/Gas/Oil		662		99	%		1992
						7,986

⁽¹⁾ In March 2011, the Company met the held for sale criteria and expects to dispose of these businesses within the next twelve months. Until the businesses are sold, they will be reported as held for sale businesses and their earnings will be reported as part of discontinued operations.

⁽²⁾ AES operates these facilities under concession agreements until 2017.

⁽³⁾ Unconsolidated entities, the results of operations of which are reflected in Equity in Earnings of Affiliates.

⁽⁴⁾ Joint Venture with I.C. Energy.

⁽⁵⁾ Includes Kilroot Open Cycle Gas Turbine (“OCGT”).

Generation under construction

Business	Location		Fuel		Gross MW		AES Equity Interest (Percent, Rounded)			Expected Year of Commercial Operation
Maritza East(1)		Bulgaria		Coal		670		100	%		2011
Kumkoy(2)		Turkey		Hydro		18		51	%		2011
Niksar(2)		Turkey		Hydro		40		51	%		2011
						728

⁽¹⁾  Construction of the Maritza East facility is currently on hold. For further discussion please see Item 7.—Management’s Discussion and Analysis—Key Trends and Uncertainties in this Form 8-K and Item 1A.—Risk Factors, “Our business is subject to substantial development uncertainties” in the 2010 Form 10-K.

⁽²⁾  Joint Venture with I.C. Energy. The joint venture is an unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates.

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Asia

Our Asia operations accounted for 4%, 3% and 2% of consolidated revenue in 2010, 2009 and 2008, respectively. Asia’s Generation business operates 9 power plants with a total capacity of 4,103 MW in four countries. In Asia, AES operates generation facilities only. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 8-K for revenue, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment. The following table provides highlights of our Asia operations:

Countries	China, India, the Philippines and Sri Lanka
Generation Capacity	4,103 Gross MW
Utilities Penetration	None
Generation Facilities	9
Utilities Businesses	None
Key Businesses	Yangcheng and Masinloc

Asia Generation. In 2010, the Company closed the sales of our businesses in Oman, Pakistan and Qatar. See Note 21—Discontinued Operations and Held for Sale Businesses in Item 8 of this Form 8-K for further information on these sales. More than half of our remaining generation capacity in Asia is located in China. In 1996, AES joined with Chinese partners to build Yangcheng, the first “coal-by-wire” power plant with the generation capacity of 2,100 MW. In April 2008, the Company completed the purchase of a 92% interest in a 660 MW coal-fired thermal power generation facility in Masinloc, Philippines (“Masinloc”).

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

Generation

Business	Location		Fuel		Gross MW		AES Equity Interest (Percent, Rounded)			Year Acquired or Began Operation
Aixi		China		Coal		51		71	%		1998
Chengdu(1)		China		Gas		50		35	%		1997
Cili		China		Hydro		25		51	%		1994
JHRH(1)		China		Hydro		379		35	%		2010
Wuhu(1),(2)		China		Coal		250		25	%		1996
Yangcheng(1)		China		Coal		2,100		25	%		2001
OPGC(1)		India		Coal		420		49	%		1998
Masinloc		Philippines		Coal		660		92	%		2008
Kelanitissa		Sri Lanka		Diesel		168		90	%		2003
						4,103

⁽¹⁾ Unconsolidated entities, the results of operations of which are reflected in Equity in Earnings of Affiliates.

⁽²⁾ AES agreed to sell its 25% equity interest in this business on August 11, 2010. The disposal was approved by the government authority on December 6, 2010.

Corporate and Other

“Corporate and Other” includes the net operating results from our Utilities businesses in Africa and Europe, Africa Generation and AES Wind Generation and other renewables projects. These operations do not require separate segment disclosure. The following provides additional details about our Utilities businesses in Africa and Europe, Africa generation and AES Wind Generation, which are reported within “Corporate and Other” for financial reporting purposes.

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Europe Utilities. Our distribution businesses in the Ukraine and Kazakhstan together serve approximately 1.8 million customers.

Distribution

Business	Location		Approximate Number of Customers Served as of 12/31/2010		GWh Sold in 2010		AES Equity Interest (Percent, Rounded)			Year Acquired
Eastern Kazakhstan REC(1)(2)		Kazakhstan		459,000		3,444		0	%
Ust-Kamenogorsk Heat Nets(1)(3)		Kazakhstan		96,000		—		0	%
Kievoblenergo		Ukraine		861,828		4,557		89	%		2001
Rivneenergo		Ukraine		405,934		1,903		84	%		2001
				1,822,762		9,904

⁽¹⁾  AES operates these businesses through management agreements and owns no equity interest in these businesses.

⁽²⁾  Shygys Energo Trade, a retail electricity company, is 100% owned by Eastern Kazakhstan REC (“EK REC”) and purchases distribution service from EK REC and electricity in the wholesale electricity market and resells to the distribution customers of EK REC.

⁽³⁾  Ust-Kamenogorsk Heat Nets provide transmission and distribution of heat with a total heat generating capacity of 224 Gcal.

Africa Utilities. AES owns a 56% interest in an integrated utility, Société Nationale d’Electricité (“Sonel”). Sonel generates, transmits and distributes electricity to over half a million people and is the sole distributor of electricity in Cameroon.

Set forth below is a list of the generation and distribution facilities of Sonel:

Sonel’s generation facilities

Business	Location		Fuel		Gross MW		AES Equity Interest (Percent, Rounded)			Year Acquired or Began Operation
Sonel(1)		Cameroon		Hydro/Diesel/Heavy Fuel Oil		936		56	%		2001

⁽¹⁾  Sonel plants: Bafoussam, Bassa, Djamboutou, Edéa, Lagdo, Limbé, Logbaba I, Logbaba II, Oyomabang I, Oyomabang II, Song Loulou, and other small remote network units.

Sonel’s distribution facility

Business	Location		Approximate Number of Customers Served as of 12/31/2010		GWh Sold in 2010		AES Equity Interest (Percent, Rounded)			Year Acquired
Sonel		Cameroon		660,484		3,345		56	%		2001

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Africa Generation. Set forth below is a list of our generation facilities in Africa.

Generation

Business	Location		Fuel		Gross MW		AES Equity Interest (Percent, Rounded)			Year Acquired or Began Operation
Dibamba		Cameroon		Heavy Fuel Oil		86		56	%		2009
Ebute		Nigeria		Gas		294		95	%		2001
						380

Wind Generation. We own and operate 1,538 MW of wind generation capacity and operate an additional 215 MW of capacity through operating and management agreements. Our wind business is located primarily in North America where we operate wind generation facilities that have generation capacity of 1,269 MW.

Set forth below is a list of AES Wind Generation facilities:

Generation

Business	Location		Power Source		Gross MW		AES Equity Interest (Percent, Rounded)			Year Acquired or Began Operation
St. Nikola		Bulgaria		Wind		156		89	%		2010
Dong Qi(1),(3)		China		Wind		49		49	%		2010
Huanghua I(1),(3)		China		Wind		49		49	%		2009
Huanghua II(1),(3)		China		Wind		49		49	%		2010
Hulunbeier(1),(3)		China		Wind		49		49	%		2008
InnoVent(2),(3)		France		Wind		75		40	%		2003-2009
St. Patrick		France		Wind		35		100	%		2010
North Rhins		Scotland		Wind		22		100	%		2010
Altamont		USA—CA		Wind		40		100	%		2005
Mountain View I & II(4)		USA—CA		Wind		67		100	%		2008
Palm Springs		USA—CA		Wind		30		100	%		2005
Tehachapi		USA—CA		Wind		58		100	%		2007
Storm Lake II(4)		USA—IA		Wind		78		100	%		2007
Lake Benton I(4)		USA—MN		Wind		106		100	%		2007
Condon(4)		USA—OR		Wind		50		100	%		2005
Armenia Mountain(4)		USA—PA		Wind		101		100	%		2009
Buffalo Gap I(4)		USA—TX		Wind		121		100	%		2006
Buffalo Gap II(4)		USA—TX		Wind		233		100	%		2007
Buffalo Gap III(4)		USA—TX		Wind		170		100	%		2008
Wind generation facilities(5)		USA		Wind		215		0	%		2005
						1,753

⁽¹⁾  Joint Venture with Guohua Energy Investment Co. Ltd.

⁽²⁾  InnoVent plants: Bignan, Chepy, Croixrault-Moyencourt, Frenouville, Gapree, Grand Fougeray, Guehenno, Hargicourt, Hescamps, LePortal, Les Diagots, Nibas, Plechatel, Saint-Hilaire la Croix and Valhoun. InnoVent owns various percentages of underlying projects.

⁽³⁾  Unconsolidated entities, the results of operations of which are reflected in Equity in Earnings of Affiliates.

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⁽⁴⁾  AES owns these assets together with third party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as Noncontrolling Interest in the Company’s Consolidated Balance Sheets.

⁽⁵⁾ AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.

AES Wind Generation projects under construction

Business	Location		Power Source		Gross MW		AES Equity Interest (Percent, Rounded)			Expected Year of Commercial Operation
Chen Qi(1)		China		Wind		49		49	%		2011
InnoVent(2)		France		Wind		29		40	%		2011
Saurashtra		India		Wind		39		100	%		2011
Mountain View IV		US-CA		Wind		49		100	%		2011
Laurel Mountain		US-WV		Wind		98		100	%		2011
						264

⁽¹⁾  Joint Venture with Guohua Energy Investment Co. Ltd.

⁽²⁾  InnoVent plants: Allery, Audrieu, Lamballe, Lefaux and Vron. InnoVent owns various percentages of underlying projects.

Other. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting. Therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue and gross margin. AES Solar was formed in March 2008 to develop, own and operate solar installations. Since its launch, AES Solar has commenced commercial operations of 37 MW of solar projects in France, Greece and Spain, has 75 MW under construction in Italy, and has development potential in Bulgaria, India and the U.S.

“Corporate and Other” also includes general and administrative expenses related to corporate staff functions and initiatives, executive management, business development, finance, legal, human resources and information systems which are not allocable to our business segments and the effects of eliminating transactions, such as self insurance charges, between the operating segments and corporate. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 8-K for information on revenue from external customers, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment.

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Financial Data by Country

The table below presents information, by country, about our consolidated operations for each of the three years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment as of December 31, 2010 and 2009, respectively. Revenue is recognized in the country in which it is earned and assets are reflected in the country in which they are located.

	Revenue						Property, Plant  & Equipment, net
	2010		2009		2008		2010		2009
	(in millions)
United States(1)	$	2,193	$	2,089	$	2,155	$	6,165	$	6,323
Non-U.S.:
Brazil		6,473		5,394		5,501		6,413		5,799
Chile		1,355		1,239		1,349		2,560		2,321
Argentina		887		684		949		459		448
El Salvador		648		619		484		261		254
Dominican Republic		535		429		601		625		634
Philippines(2)		501		250		148		784		765
Cameroon		422		370		379		823		742
Spain(3)		411		—		—		667		—
Mexico		409		329		463		786		802
Colombia		393		347		291		387		390
United Kingdom		385		241		342		527		433
Ukraine		356		286		403		86		80
Hungary(4)		252		259		367		73		182
Puerto Rico		253		267		251		596		609
Panama		194		168		210		921		834
Kazakhstan		138		123		234		63		48
Jordan		120		104		47		224		231
Sri Lanka		100		109		184		69		74
Bulgaria(5)		44		—		—		1,825		1,835
Qatar(6)		—		—		—		—		—
Pakistan(7)		—		—		—		—		—
Oman(8)		—		—		—		—		—
Other Non-U.S.		112		133		150		298		285
Total Non-U.S.		13,988		11,351		12,353		18,447		16,766
Total	$	16,181	$	13,440	$	14,508	$	24,612	$	23,089

⁽¹⁾  Excludes revenue of $422 million, $456 million and $590 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $2 million and $693 million as of December 31, 2010, and 2009, respectively, related to Eastern Energy, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

⁽²⁾  Masinloc was acquired in April 2008; 2008 revenue represents results for a partial year.

⁽³⁾  Cartagena was consolidated effective January 1, 2010 upon implementation of the variable interest entity accounting guidance.

⁽⁴⁾  Excludes revenue of $44 million, $58 million and $99 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $7 million and $14 million as of December 31, 2010, and 2009, respectively, related to Borsod and Tiszapalkonya, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

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⁽⁵⁾  Maritza East and our wind project in Bulgaria were under development and therefore not operational as of December 31, 2009. Our wind project in Bulgaria started operations in 2010.

⁽⁶⁾  Excludes revenue of $129 million, $163 million and $161 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $501 million as of December 31, 2009 related to Ras Laffan, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

⁽⁷⁾  Excludes revenue of $299 million, $470 million and $607 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $36 million as of December 31, 2009 related to Lal Pir and Pak Gen, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

⁽⁸⁾  Excludes revenue of $62 million, $101 million and $105 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $311 million as of December 31, 2009, related to Barka, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth our selected financial data as of the dates and for the periods indicated. You should read this data together with Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and the notes thereto included in Item 8 of this Form 8-K. The selected financial data for each of the years in the five year period ended December 31, 2010 have been derived from our audited Consolidated Financial Statements. Our historical results are not necessarily indicative of our future results.

Acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the Consolidated Financial Statements included in Item 8.—Financial Statements and Supplementary Data of this Form 8-K for further explanation of the effect of such activities. Please also refer to Item 1A.—Risk Factors of the 2010 Form 10-K and Note 24—Risks and Uncertainties to the Consolidated Financial Statements included in Item 8 of this Form 8-K for certain risks and uncertainties that may cause the data reflected herein not to be indicative of our future financial condition or results of operations.

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SELECTED FINANCIAL DATA

	Year Ended December 31,
Statement of Operations Data	2010			2009			2008			2007			2006
	(in millions, except per share amounts)
Revenue	$	16,181		$	13,440		$	14,508		$	12,135		$	10,266
Income from continuing operations(1)		1,501			1,828			1,847			600			445
Income from continuing operations attributable to The AES Corporation, net of tax		495			729			1,088			214			23
Discontinued operations, net of tax		(486	)		(71	)		146			(309	)		202
Extraordinary items, net of tax		—			—			—			—			22
Net income (loss) attributable to The AES Corporation	$	9		$	658		$	1,234		$	(95	)	$	247
Basic (loss) earnings per share:
Income from continuing operations attributable to The AES Corporation, net of tax	$	0.64		$	1.09		$	1.62		$	0.32		$	0.03
Discontinued operations, net of tax		(0.63	)		(0.10	)		0.22			(0.46	)		0.31
Extraordinary items, net of tax		—			—			—			—			0.03
Basic earnings (loss) per share	$	0.01		$	0.99		$	1.84		$	(0.14	)	$	0.37
Diluted (loss) earnings per share:
Income from continuing operations attributable to The AES Corporation, net of tax	$	0.64		$	1.09		$	1.61		$	0.32		$	0.03
Discontinued operations, net of tax		(0.63	)		(0.11	)		0.21			(0.46	)		0.31
Extraordinary items, net of tax		—			—			—			—			0.03
Diluted earnings (loss) per share	$	0.01		$	0.98		$	1.82		$	(0.14	)	$	0.37
	December 31,
Balance Sheet Data:	2010			2009			2008			2007			2006
	(in millions)
Total assets	$	40,511		$	39,535		$	34,806		$	34,453		$	31,274
Non-recourse debt (long-term)	$	12,372		$	12,121		$	11,063		$	10,422		$	9,123
Non-recourse debt (long-term)—Discontinued operations	$	172		$	743		$	806		$	908		$	1,059
Recourse debt (long-term)	$	4,149		$	5,301		$	4,994		$	5,332		$	4,790
Cumulative preferred stock of a subsidiary	$	60		$	60		$	60		$	60		$	60
Retained earnings (accumulated deficit)	$	620		$	650		$	(8	)	$	(1,241	)	$	(1,093	)
The AES Corporation stockholders’ equity	$	6,473		$	4,675		$	3,669		$	3,164		$	2,979

⁽¹⁾  Includes pretax impairment expense of $412 million, $142 million, $175 million, $408 million and $ 17 million for the years ended December 31, 2010, 2009, 2008, 2007 and 2006, respectively.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of Our Business

We are a global power company. We operate two primary lines of business. 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, other intermediaries and certain end-users. 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 within a defined service area. For the year ended December 31, 2010, our Generation and Utilities businesses comprised approximately 43% and 57% of our consolidated revenue, respectively.

We are also continuing to expand our wind and solar generation businesses. These initiatives are not material contributors to our operating results at this time, but we believe that certain of these initiatives may become material in the future. For additional information regarding our business, see Item 1.—Business of this Form 8-K.

Our Organization and Segments. Our management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The financial reporting segment structure uses our management reporting structure as its foundation and reflects how we manage the business internally. Based on our application of the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, we have concluded that the Company has the following six reportable segments:

• Latin America—Generation;

• Latin America—Utilities;

• North America—Generation;

• North America—Utilities;

• Europe—Generation;

• Asia—Generation.

We report the Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation and Climate Solutions operating segments within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our financial statement presentation of reportable segments, individually or in the aggregate. “Corporate and Other” also includes corporate overhead costs which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

During the second quarter of 2010, the Company modified its internal reporting structure to move the management of the Company’s generation business in Jordan, Amman East, from Asia to Europe. Accordingly, Amman East is now reported within the Europe—Generation segment. All prior periods have been retrospectively restated to reflect this change and conform to current period presentation.

Key Drivers of Our Results of Operations. Our Generation and Utilities businesses are distinguished by the nature of their customers, operational differences, cost structure, regulatory environment and risk exposure. As a result, each line of business has slightly different drivers which affect operating results. Performance drivers for our Generation businesses include, among other things, plant reliability and efficiency, power prices, volume,

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management of fixed and variable operating costs, management of working capital including collection of receivables, and the extent to which our plants have hedged their exposure to currency and commodities such as fuel. For our Generation businesses which sell power under short-term contracts or in the spot market, the most crucial factors are the current market price of electricity and the marginal costs of production. Growth in our Generation business is largely tied to securing new PPAs, expanding capacity in our existing facilities and building or acquiring new power plants. Performance drivers for our Utilities businesses include, but are not limited to, reliability of service; management of working capital, including collection of receivables; negotiation of tariff adjustments; compliance with extensive regulatory requirements; and in developing countries, reduction of commercial and technical losses. The operating results of our Utilities businesses are sensitive to changes in economic growth and weather conditions in areas in which they operate. In addition to these drivers, as further explained below, the Company also has exposure to currency exchange rate fluctuations.

One of the key factors which affect our Generation business is our ability to enter into contracts for the sale of electricity and the purchase of fuel used to produce that electricity. Long-term contracts are intended to reduce exposure to volatility associated with fuel prices in the market and the price of electricity by fixing the revenue and costs for these businesses. The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. In turn, most of these businesses enter into long-term fuel supply contracts or fuel tolling arrangements where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. While these long-term contractual agreements reduce exposure to volatility in the market price for electricity and fuel, the predictability of operating results and cash flows vary by business based on the extent to which a facility’s generation capacity and fuel requirements are contracted and the negotiated terms of these agreements. Entering into these contracts exposes us to counterparty credit risk. For further discussion of these risks, see “Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks” in Item 1A.—Risk Factors of the 2010 Form 10-K.

When fuel costs increase, many of our businesses are able to pass these costs on to their customers. Generation businesses with long-term contracts in place do this by including fuel pass-through or fuel indexing arrangements in their contracts. Utilities businesses can pass costs on to their customers through increases in current or future tariff rates. Therefore, in a rising fuel cost environment, the increased fuel costs for these businesses often result in an increase in revenue to the extent these costs can be passed through (though not necessarily on a one-for-one basis). Conversely, in a declining fuel cost environment, the decreased fuel costs can result in a decrease in revenue. Increases or decreases in revenue at these businesses that have the ability to pass through costs to the customer have a corresponding impact on cost of sales, to the extent the costs can be passed through, resulting in a limited impact on gross margin, if any. Although these circumstances may not have a large impact on gross margin, they can significantly affect gross margin as a percentage of revenue. As a result, gross margin as a percentage of revenue is a less relevant measure when evaluating our operating performance. To the extent our businesses are unable to pass through fuel cost increases to their customers, gross margin may be adversely affected.

Global diversification also helps us mitigate risk. Our presence in mature markets helps mitigate the exposure associated with our businesses in emerging markets. Additionally, our portfolio employs a broad range of fuels, including coal, gas, fuel oil, water (hydroelectric power), wind and solar, which reduces the risks associated with dependence on any one fuel source. However, to the extent the mix of fuel sources enabling our generation capabilities in any one market is not diversified, the spread in costs of different fuels or the availability of natural resources such as water for hydroelectric power production or wind may also influence the operating performance and the ability of our subsidiaries to compete within that market. For example, in a market where gas prices fall to a low level compared to coal prices, power prices may be set by low gas prices which can affect the profitability of our coal plants in that market. In certain cases, we may attempt to hedge fuel prices to manage this risk, but there can be no assurance that these strategies will be effective.

We also attempt to limit risk by hedging much of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. However, we only hedge a portion of our currency and commodity risks, and our businesses are still subject to these risks, as further

20

described in Item 1A.—Risk Factors of the 2010 Form 10-K, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” Commodity and power price volatility could continue to impact our financial metrics to the extent this volatility is not hedged. For a discussion of our sensitivities to commodity, currency and interest rate risk, see Item 7A.—Quantitative and Qualitative Disclosures About Market Risk in the 2010 Form 10-K.

Due to our global presence, the Company has significant exposure to foreign currency fluctuations. The exposure is primarily associated with the impact of the translation of our foreign subsidiaries’ operating results from their local currency to U.S. Dollars that is required for the preparation of our consolidated financial statements. Additionally, there is foreign currency transaction exposure when an entity enters into transactions, including debt agreements, in currencies other than their functional currency. These risks are further described in Item 1A.—Risk Factors of the 2010 Form 10-K, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” During 2010, changes in foreign currency exchange rates had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could continue to be affected.

Another key driver of our results is our ability to bring new businesses into commercial operation successfully. We currently have approximately 1,300 MW of projects under construction in eight countries. Our prospects for improved operating results and cash flows are dependent upon successful completion of these projects on time and within budget. However, as disclosed in Item 1A.—Risk Factors of the 2010 Form 10-K, “Our business is subject to substantial development uncertainties,” construction is subject to a number of risks, including risks associated with site identification, financing, permitting and our ability to meet construction deadlines. Delays or the inability to complete projects and commence commercial operations can result in increased costs, impairment of assets and other challenges involving partners and counterparties to our construction agreements, PPAs and other agreements.

Our gross margin is also impacted by the fact that in each country in which we conduct business, we are subject to extensive and complex governmental regulations, such as regulations governing the generation and distribution of electricity, and environmental regulations which affect most aspects of our business. Regulations differ on a country by country basis (and even at the state and local municipality levels) and are based upon the type of business we operate in a particular country, and affect many aspects of our operations and development projects. Our ability to negotiate tariffs, enter into long-term contracts, pass through costs related to capital expenditures and otherwise navigate these regulations can have an impact on our revenue, costs and gross margin. Environmental and land use regulations, including existing and proposed regulation of GHG emissions, could substantially increase our capital expenditures or other compliance costs, which could in turn have a material adverse affect on our business and results of operations. For a further discussion of the Regulatory Environment, see Note 12—Contingencies—Environmental, included in Item 8.—Financial Statements of this Form 8-K and Item 1.—Business—Regulatory Matters—Environmental and Land Use Regulations and Item 1A.—Risk Factors—Risks Associated with Government Regulation and Laws of the 2010 Form 10-K.

Key Drivers of Results in 2010

In 2010, the Company’s gross margin and cash flow from operations increased $582 million and $1.3 billion, respectively, while net income attributable to The AES Corporation decreased $649 million compared to the prior year.

During 2010, our North American generation businesses continued to face challenges associated with relatively lower gas prices and a decline in power prices relative to coal and other fuel. In particular, lower gas and power prices have affected the generation volume and financial results of our coal-fired plants in New York, currently classified as held for sale, and our petroleum coke-fired plant in Texas which are merchant businesses

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and not subject to PPAs. We expect this trend to continue. In 2010, these challenges were partially mitigated by hedging arrangements. In North America, current dark spreads and the corresponding forward curves do not present a long-term opportunity to engage in hedging activity for 2011 and we have very limited hedges in place. As short-term opportunities occur or should dark spreads improve, the Company may engage in additional hedging in 2011. As a result of these and other challenges that arose from new regulatory concerns, we impaired $1.1 billion of assets and goodwill in North America as described in Impairments below. In addition, AES Thames, our 208 MW coal-fired generation business in Connecticut, filed for bankruptcy protection in January 2011.

Despite these challenges, many of our financial measures have improved when compared to 2009. Gross margin increased due to the favorable impact of foreign currency translation caused by a weaker U.S. dollar compared to most foreign currencies in 2010 and better operating performance at certain businesses. For instance, certain of the Company’s Latin American businesses experienced continued increases in market demand due to the local economic recovery in Latin America. The Company also benefited from higher demand and favorable market conditions at Masinloc, our generation business in the Philippines. Masinloc’s higher availability enabled the Company to benefit from increased contract and spot market sales and favorable market prices in the Philippines. In addition, cash provided by operating activities increased due to the improved operating results at Latin America generation businesses and Masinloc; contributions from the consolidation of Cartagena and the Ballylumford acquisition in 2010, and changes in working capital in Latin America.

Despite the increase in gross margin in 2010, net income attributable to The AES Corporation decreased primarily from the impact of long-lived asset impairments recognized related to four businesses: Eastern Energy in New York (currently classified as held for sale), Southland in California, Tisza II in Hungary and Deepwater in Texas. These were partially offset by gains from the sale of our discontinued businesses in Oman and Qatar and a decrease in goodwill impairment charges.

In 2011, we expect to face continued challenges in our business, including the trends in North America described above. In addition, the impact of fluctuating foreign exchange rates and commodity prices on our operations may continue into 2011. In 2011, the components of the tariff reset in Brazil and its potential impact on our Brazilian utilities are uncertain at this time and we expect continued challenges in our merchant businesses such as those in the U.S., Hungary and Northern Ireland. However, management expects that improved operating performance at certain businesses and growth from new businesses acquired, that commenced operations in 2010 or are expected to commence operations in 2011, may lessen or offset the impact of these challenges described above, as they did in 2010. However, if these favorable effects do not occur, or if the challenges described above or elsewhere in this section impact us more than we currently anticipate, or if volatile foreign currencies and commodities move unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our gross margin and net income attributable to The AES Corporation. In addition, we do not expect the trend of an increase in net cash provided by operating activities realized in 2010 to continue in 2011. Such cash flows may be influenced by the operating challenges presented above and will also not include the cash flows from operations which were sold in 2010 or the increases experienced from the cash flows provided by the initial consolidation of Cartagena, the acquisition of Ballylumford and several working capital transactions at our Latin American utilities in 2010 as discussed in Capital Resources and Liquidity.

The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation, diluted earnings per share from continuing operations, Adjusted Earnings per Share (a non-GAAP measure) and net cash provided by operating activities for the year ended December 31, 2010 compared to 2009 and 2008 and should be read in conjunction with our Consolidated Results of Operations and Segment Analysis discussion within Management’s Discussion and Analysis of Financial Condition.

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Performance Highlights

	Year Ended December 31,
	2010		2009		2008
	(in millions, except per share amounts)
Revenue	$	16,181	$	13,440	$	14,508
Gross Margin	$	3,988	$	3,406	$	3,417
Net Income Attributable to The AES Corporation	$	9	$	658	$	1,234
Diluted Earnings per Share from Continuing Operations	$	0.64	$	1.09	$	1.61
Adjusted Earnings Per Share (a non-GAAP measure)(1)	$	1.00	$	1.07	$	0.94
Net Cash Provided by Operating Activities	$	3,510	$	2,201	$	2,165

⁽¹⁾  See reconciliation and definition below under Non-GAAP Measure.

Year Ended December 31, 2010

Revenue increased $2.7 billion, or 20%, to $16.2 billion in 2010 compared with $13.4 billion in 2009. Key drivers of the increase included:

• the favorable impact of foreign currency of $809 million;

• increased volume and rates at our Brazilian utilities attributable to increased demand due to the recovery of the local economy and the favorable impact of the June 2009 tariff reset;

• the impact of the consolidation of Cartagena, in Spain, in accordance with the new consolidation accounting guidance which became effective January 1, 2010;

• the favorable impact of rates at our generation businesses in Argentina;

• higher generation rates and volume at Masinloc in the Philippines;

• higher demand at Gener in Chile;

• the impact of the Company’s new business in Northern Ireland, acquired in August 2010;

• higher demand and rates at Indianapolis Power and Light; and

• higher volume in Ukraine.

Gross margin increased $582 million, or 17%, to $4.0 billion in 2010 compared with $3.4 billion in 2009. Key drivers of the increase included:

• the favorable impact of foreign currency of $216 million;

• an increase in demand at our generation and utilities businesses in Latin America;

• higher generation rates and volume at Masinloc in the Philippines; and

• the impact of the consolidation of Cartagena, in Spain, in accordance with the new consolidation accounting guidance which became effective January 1, 2010.

These increases were partially offset by an increase in fixed costs in Latin America, largely driven by bad debt recoveries and a reduction in bad debt expense in Brazil in 2009 that did not recur.

Net income attributable to The AES Corporation decreased $649 million to $9 million in 2010, compared to $658 million in 2009. Key drivers of the decrease included:

• Impairment losses in New York related to our Eastern Energy facilities which are classified as held for sale, in California related to our Southland (Huntington Beach) generation facility, in Hungary related to our Tisza II generation facility and in Texas related to our Deepwater facility;

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• A decrease in gain on sale of investments due to the sale of our businesses in Northern Kazakhstan which occurred in 2009; and

• A decrease in other income due to the reduction in interest and penalties in 2009 associated with federal tax debts at Eletropaulo and Sul as a result of the Programa de Recuperacao Fiscal (“REFIS”) program and a favorable court decision in 2009 enabling Eletropaulo to receive reimbursement of excess non-income taxes paid from 1989 to 1992 in the form of tax credits to be applied against future tax liabilities.

These decreases were partially offset by:

• The gain on sale of discontinued operations related to the sale of Barka which occurred in August 2010;

• An increase in net equity in earnings of affiliates partially offset by income tax expense related to the sale of the Company’s indirect investment in Companhia Energética de Minas Gerais (“CEMIG”);

• Lower impairment expenses related to a goodwill impairment of our business in Kilroot that occurred in 2009;

• Lower income tax expense due to 2010 asset impairments primarily recorded at certain U.S subsidiaries as referenced above; and

• An increase in gross margin as described above.

Net cash provided by operating activities increased $1.3 billion, or 59%, to $3.5 billion in 2010 compared with $2.2 billion in 2009. This net increase was primarily due to the following:

• an increase of $837 million at our Latin American Utilities businesses due to increased tax payments in 2009 associated with a tax amnesty program of $326 million, higher working capital requirements during 2009 related to payments on the settlement of swap agreements of $65 million and in 2010, a $50 million decrease in employer contributions to pension plans and lower payments for contingencies;

• an increase of $215 million at our Latin American Generation businesses due to the higher gross margin in 2010 combined with improved working capital mainly as a result of higher collections of value added taxes and accounts receivable;

• an increase of $99 million at Masinloc in the Philippines due to higher gross margin; and

• an increase of $58 million as a result of our consolidation of Cartagena in 2010 and the acquisition of Ballylumford in Northern Ireland.

These increases were partially offset by:

• a decrease of $184 million in operating cash flows from discontinued operations compared to 2009. In 2010, net cash provided by operating activities of discontinued and held for sale businesses was $93 million, including $33 million from businesses sold in 2010.

In 2010 the increase in net cash provided by operating activities at our Latin American Utilities businesses included several items such as the tax amnesty program and settlement of swap agreements, as described above, that are not expected to recur. In addition, 2010 net cash provided by operating activities benefited from the one time cash savings related to the utilization of tax credits received as a result of the REFIS program. As such, the Company does not expect the trend of an increase in net cash provided by operating activities realized in 2010 to continue in 2011.

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Year Ended December 31, 2009

Revenue decreased $1.1 billion, or 7%, to $13.4 billion in 2009 compared with $14.5 billion in 2008. Key drivers of the decrease included:

• the unfavorable impact of foreign currency of $981 million, largely driven by the Brazilian Real;

• the impact of lower spot and contract energy prices at our generation business in Chile;

• decreases in volume at Uruguaiana due to the renegotiation of its power sales agreements in 2009 to reduce the energy volume sold, Tisza II in Hungary and lower dispatch in Northern Ireland due to unfavorable gas prices compared to coal; and

• lower energy prices and volume at our generation businesses in the Dominican Republic.

These decreases were partially offset by an increase in tariff rates at our utilities businesses in Latin America primarily reflecting the recovery of energy purchases that were passed through to our customers.

Gross margin decreased $11 million, or 0%, to $3.4 billion in 2009 compared with $3.4 billion in 2008. Key drivers of the decrease included:

• the unfavorable impact of foreign currency of $218 million, largely driven by the Brazilian Real;

• lower energy prices and higher purchased energy costs at our generation businesses in the Dominican Republic and Argentina;

• increased pension costs in Brazil and the U.S.; and

• the unfavorable impact of mark-to-market derivative adjustments in Hawaii.

These decreases were partially offset by:

• improved operating performance at our generation businesses in Chile and the Philippines;

• higher tariffs at our utilities businesses in Latin America;

• bad debt recoveries and a reduction in bad debt expense in Brazil; and

• the favorable impact of a full year of operations in 2009 at our businesses in Jordan and the Philippines.

Net income attributable to The AES Corporation decreased $576 million to $658 million in 2009, compared to $1.2 billion in 2008. Key drivers of the decrease included:

• a gain recognized in 2008 from the sale of two wholly-owned subsidiaries in Northern Kazakhstan partially offset by a performance incentive bonus recognized in 2009 for management services provided to these subsidiaries and a settlement upon termination of the management agreement in 2009;

• the reduction in gross margin in 2009 as described above; and

• higher impairment expenses in 2009 as a result of an impairment of goodwill at Kilroot in Northern Ireland, and an impairment recognized on our assets in Pakistan which is reflected in discontinued operations, offset by a decline in long-lived asset impairment compared to 2008.

These decreases were partially offset by:

• a reduction in foreign currency transaction losses on net monetary position as a result of reduced losses at our businesses in Chile and the Philippines;

• a reduction in interest expense due primarily to lower interest rates and debt balances in Brazil and favorable foreign currency translation; and

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• lower income tax expenses driven in part by lower pre-tax income and a decrease in the effective tax rate from 28% in 2008 to 25% in 2009 due, in part, to tax benefits recorded in 2009 upon the release of valuation allowances at U.S. and Brazilian subsidiaries, $165 million of non-taxable income recognized in Brazil as a result of the REFIS program in 2009 and an increase in U.S. taxes on distributions from the Company’s primary holding company in the second quarter of 2008.

In 2008, the $905 million gain recognized on the sale of our two Northern Kazakhstan businesses had a significant impact on net income attributable to The AES Corporation. In 2009, the Company recognized a performance incentive bonus of $80 million in the first quarter for management services provided to these sold businesses, reflected as other income. Additionally, in the second quarter of 2009, the Company recognized an additional gain on the sale of the businesses of $98.5 million upon the termination of the management agreement. While the Company engages in the sale of assets and businesses from time to time, the gain or loss recognized in any such sale will depend on a number of factors related to the asset or business that may be sold. Therefore, the Company does not believe that the decline in net income between 2008 and 2009 represents a trend. All of the amounts related to our two Northern Kazakhstan businesses were reported in continuing operations and will not recur in 2010 or future years.

Net cash from operating activities increased $36 million, or 2%, to $2.2 billion in 2009 compared with $2.2 billion in 2008. This net increase was primarily due to the following:

• an increase of $238 million at our Latin American Generation businesses due to improved working capital management;

• an increase of $148 million at our Asia Generation businesses due to improved working capital management and improved gross margin; and

• an increase of $111 million at our Europe Generation businesses primarily due to the collection of the $80 million Kazakhstan management performance incentive bonus in the first quarter 2009.

These increases were partially offset by:

• a decrease of $391 million at our Latin American Utilities businesses due to increased working capital requirements, including the payment of the settlement of a swap agreement, increased tax payments associated with a tax amnesty program and increased payments related to the settlement of contingencies and energy purchases, partially offset by increased operating results; and

• a decrease of $79 million at our North America Generation businesses, primarily due to reduced operating results.

Non-GAAP Measure

We define adjusted earnings per share (“Adjusted EPS”) as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) mark-to-market amounts related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) significant gains or losses due to dispositions and acquisitions of business interests, (d) significant losses due to impairments, and (e) costs due to the early retirement of debt. The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. AES believes that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to mark-to-market gains or losses related to derivative transactions, currency gains or losses, losses due to impairments and strategic decisions to dispose or acquire business interests or retire debt, which affect results in a given period or periods. Adjusted EPS should not be construed as an alternative to diluted earnings per share from continuing operations, which is determined in accordance with GAAP.

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Reconciliation of Adjusted Earnings Per Share

	Year Ended December 31,
	2010			2009			2008
Diluted earnings (loss) per share from continuing operations	$	0.64		$	1.09		$	1.61
Derivative mark-to-market (gains) losses(1)		—			0.01			0.05
Currency transaction (gains) losses(2)		(0.04	)		(0.05	)		0.17
Disposition/acquisition (gains) losses		—	(3)		(0.19	)(4)		(1.27	)(5)
Impairment losses		0.37	(6)		0.21	(7)		0.13	(8)
Debt retirement (gains) losses		0.03	(9)		—			0.25	(10)
Adjusted earnings per share	$	1.00		$	1.07		$	0.94

⁽¹⁾  Derivative mark-to-market (gains) losses were net of $0.00 income tax per share in 2010, 2009 and 2008.

⁽²⁾  Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00, $0.01 and $0.00 in 2010, 2009 and 2008, respectively.

⁽³⁾  The Company has not adjusted for the gain or the related tax effect from the sale of its indirect investment in CEMIG, disclosed in Note 7—Investments in and Advances to Affiliates included in Item 8 of this form 8-K, in its determination of Adjusted EPS because the gain was recognized by an equity method investee. The Company does not adjust for transactions of its equity method investees in its determination of adjusted EPS.

⁽⁴⁾  Amount includes: Kazakhstan gain of $98 million, or $0.15 per share, related to the termination of a management agreement as well as a gain of $13 million, or $0.02 per share, related to the reversal of a withholding tax contingency. In addition, there was a gain on sale associated with the shutdown of the Hefei plant in China of $14 million, or $0.02 per share. There were no taxes associated with any of these transactions.

⁽⁵⁾  Amount includes: Net gain on Kazakhstan sale of $905 million, or $1.31 per share, and net loss on sale of subsidiary interests in Gener of $31 million, or $0.04 per share. There was no income tax impact associated with these transactions.

⁽⁶⁾  Amount primarily includes asset impairments at Southland (Huntington Beach) of $200 million, Tisza of $85 million, and Deepwater of $79 million ($130 million, or $0.17 per share, $69 million, or $0.09 per share, and $51 million, or $0.07 per share, net of income tax, respectively) and goodwill impairment at Deepwater of $18 million (or $0.02 per share, with no income tax impact).

⁽⁷⁾  Amount includes: Goodwill impairments at Kilroot of $118 million, or $0.18 per share, and in the Ukraine of $4 million, or $0.01 per share; write-off of development project costs in Latin America and Asia of $19 million ($11 million net of noncontrolling interests, or $0.01 per share) and an impairment of $10 million, or $0.01 per share, of the Company’s investment in a company developing “blue gas” (coal to gas) technology. There was no income tax impact associated with any of these transactions.

⁽⁸⁾  Amount includes: Impairment charges primarily associated with development projects in North America of $75 million ($34 million net of noncontrolling interests and income tax, or $0.06 per share); Uruguaiana asset write-down of $36 million ($17 million net of noncontrolling interest, or $0.02 per share); South Africa peaker development cost write-off of $31 million ($28 million net of income tax, or $0.04 per share) and a nontaxable impairment of the Company’s investment in “blue gas” (coal to gas) technology of $10 million, or $0.01 per share. Impairment losses are net of an income tax benefit of $0.02 per share in 2008.

⁽⁹⁾  Amount includes loss on retirement of debt at the Parent Company of $15 million, at Andres of $10 million, and at Itabo of $8 million ($10 million, or $0.01 per share, net of income tax at the Parent Company, $0.01 per share at Andres, and $4 million, or $0.01 per share, net of noncontrolling interest at Itabo).

⁽¹⁰⁾  Amount includes: $55 million ($34 million net of income tax, or $0.05 per share) loss on the retirement of Parent Company debt; $131 million, or $0.19 per share, which represented the tax impact on the repatriation of a portion of the Kazakhstan sale proceeds that were used to fund the early retirement of Parent Company debt; and $14 million ($9 million net of income tax, or $0.01 per share) of debt refinancing at IPALCO. Debt retirement (gains) losses are net of an income tax benefit of $0.04 per share in 2008.

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Management’s Priorities

Management continues to focus on the following priorities:

• Execution of our balanced capital allocation strategy including funds received in 2010 from asset and equity sales:

• investing in value-accretive projects;

• delevering to increase financial flexibility, reduce risk and to create future borrowing capacity; and

• executing its stock repurchase program; from July through December 2010 we have repurchased a total of $99 million, or approximately 8.4 million shares of AES common stock, at an average price per share of $11.86, including commissions.

• Improvement of operations in the existing portfolio;

• Achieve cost savings through the alignment of overhead costs with business requirements, systems automation and optimal allocation of business development spending;

• Strategic portfolio management of existing projects including restructuring and potential sales of certain North American generation subsidiaries;

• Completion of an approximately 1,300 MW active construction program on time and within budget;

• Achieving commercial operation at Maritza in Bulgaria. At the end of 2010, the Company experienced certain commissioning delays, as further described in Key Trends and Uncertainties—Development below; and

• Integration of new projects. During 2010, the following projects were acquired or commenced commercial operations:

Project	Location	Fuel	Gross MW		AES Equity Interest (Percent, Rounded)
Ballylumford	United Kingdom	Gas		1,246		100	%
JHRH(1)	China	Hydro		379		35	%
Nueva Ventanas	Chile	Coal		272		71	%
St. Nikola	Bulgaria	Wind		156		89	%
Guacolda 4(2)	Chile	Coal		152		35	%
Dong Qi(3)	China	Wind		49		49	%
Huanghua II(3)	China	Wind		49		49	%
St. Patrick	France	Wind		35		100	%
North Rhins	Scotland	Wind		22		100	%
Kepezkaya	Turkey	Hydro		28		51	%
Damlapinar(4)	Turkey	Hydro		16		51	%

⁽¹⁾  Jianghe Rural Electrification Development Co. Ltd. (“JHRH”) and AES China Hydropower Investment Co. Ltd. entered into an agreement to acquire a 49% interest in this joint venture in June 2010. Acquisition of 35% ownership was completed in June 2010 and the transfer of the remaining 14% ownership, which is subject to approval by the Chinese government, is expected to be completed in May 2011.

⁽²⁾  Guacolda is an equity method investment indirectly held by AES through Gener. The AES equity interest reflects the 29% noncontrolling interests in Gener.

⁽³⁾  Joint venture with Guohua Energy Investment Co. Ltd.

⁽⁴⁾  Joint Venture with I.C. Energy.

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Key Trends and Uncertainties

Our operations continue to face many risks as discussed in Item 1A.—Risk Factors of the 2010 Form 10-K. Some of these challenges are also described above in Key Drivers of Results in 2010. We continue to monitor our operations and address challenges as they arise.

Development. During the past year, the Company has successfully acquired and completed construction of a number of projects, totaling approximately 2,404 MW, including the acquisition of Ballylumford in the United Kingdom and completion of construction of a number of projects in Europe, Chile and China. However, as discussed in Item 1A.—Risk Factors—Our business is subject to substantial development uncertainties of the 2010 Form 10-K, our development projects are subject to uncertainties. Certain delays have occurred at the 670 MW Maritza coal-fired project in Bulgaria, and the project had not begun commercial operations. As noted in Note 10—Debt included in Item 8 of this Form 8-K, as a result of these delays the project debt is in default and the Company is working with its lenders to resolve the default. In addition, as noted in Item 3.—Legal Proceedings of the 2010 Form 10-K, the Company is in litigation with the contractor regarding the cause of delays. At this time, we believe that Maritza will commence commercial operations for at least some of the project’s capacity by the second half of 2011. However, commencement of commercial operations could be delayed beyond this time frame. There can be no assurance that Maritza will achieve commercial operations, in whole, or in part, by the second half of 2011, resolve the default with the lenders or prevail in the litigation referenced above, which could result in the loss of some or all of our investment or require additional funding for the project. Any of these events could have a material adverse effect on the Company’s operating results or financial position.

Global Economic Conditions. During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Although the economic conditions in several of these countries have improved in recent months, our businesses could be impacted in the event these recent trends do not continue.

Our business or results of operations could be impacted if our subsidiaries are unable to access the capital markets on favorable terms or at all, are unable to raise funds through the sale of assets or are otherwise unable to finance or refinance their activities. The Company could also be adversely affected if capital market disruptions result in increased borrowing costs (including with respect to interest payments on the Company’s or our subsidiaries’ variable rate debt) or if commodity prices affect the profitability of our plants or their ability to continue operations. Additionally, the Company could be adversely affected if general economic or political conditions in the markets where our subsidiaries operate deteriorate, resulting in a reduction in cash flow from operations, a reduction in the availability and/or an increase in the cost of capital, or if the value of our assets remain depressed or decline further. Any of the foregoing events or a combination thereof could have a material impact on the Company, its results of operations, liquidity, financial covenants, and/or its credit rating.

Our subsidiaries are subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, hedging agreements and other contractual arrangements) to deliver contracted commodities or services at the contracted price or to satisfy their financial or other contractual obligations. The Company has not suffered any material effects related to its counterparties during 2010. However, if macroeconomic conditions impact our counterparties, they may be unable to meet their commitments which could result in the loss of favorable contractual positions, which could have a material impact on our business.

In addition, during the past year, certain European countries have faced a sovereign debt crisis and it is possible that other nations could be affected. This crisis has resulted in an increased risk of default by governments and the implementation of austerity measures in countries. If the crisis continues, worsens, or spreads, there could be a material adverse impact on the Company. Our businesses may be impacted if they are unable to access the capital markets, face increased taxes or labor costs, or if governments fail to fulfill their obligations to us or adopt austerity measures which adversely impact our projects. In addition, as noted in the

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Risk Factor included in Item 1A. of the 2010 Form 10-K titled, “Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges,” our renewables businesses are dependent on favorable regulatory incentives, including subsidies, which are provided by sovereign governments. If these subsidies or other incentives are reduced or repealed, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, in whole or in part, this could impact the ability of the affected businesses to continue to grow their operations. For example, the Spanish government recently issued a decree which limits the feed-in-tariff and number of photovoltaic hours eligible for the tariff, which could adversely impact AES Solar in Spain. For further information on the decree see Item 1.— Regulatory—Spain of the 2010 Form 10-K. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries. For further information on the importance of long-term contracts and our counterparty credit risk, see the Risk Factor from the 2010 Form 10-K titled, “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations…”. As a result of any of the foregoing events, we may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. The Company’s investment in AES Solar, whose primary operations are in Europe, at December 31, 2010 was $312 million.

For a discussion of the risks associated with commodity prices, see “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” in Item 1A.—Risk Factors of the 2010 Form 10-K. It is also possible that commodity or power price volatility could continue to impact our financial results. As noted in Key Drivers of Results in 2010 of this Form 8-K and Item 7A.—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of the 2010 Form 10-K, the Company’s North American businesses continue to face pressure as a result of high coal prices relative to natural gas, which has affected the results of certain of our coal plants in the region, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts. If these conditions continue or worsen, these businesses may need to restructure their obligations or seek additional funding (including from the Parent) or face the possibility that they may be unable to meet their obligations and continue operations. Presently, Eastern Energy (currently classified as held for sale), Deepwater and Thames are seeking to restructure their financial obligations and/or place certain of their plants in protective layup status to mitigate operating risks caused by high fuel costs and other competitive pressures. There can be no assurance the Company will be successful in these efforts.

The Company presently manages its commodity risk with hedging activities to mitigate earnings volatility. However, at present in North America, dark spreads and the corresponding forward curves do not currently present an opportunity to engage in additional hedging activity for 2011. As a result, there are hedging arrangements in place for only a relatively small portion of 2011. As short-term opportunities occur or should dark spreads improve, the Company may engage in additional hedging in 2011. Specifically, the operating results of the Company’s Eastern Energy generation business in New York, which is reflected on the Consolidated Statements of Operations within discontinued operations, could be adversely impacted by continued higher coal prices relative to electricity prices if hedging continues to be uneconomic.

If global economic conditions worsen, it could also affect the rates we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our rates based on prevailing market conditions as PPAs, concession agreements or other contracts come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual rate or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.

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Impairments.

Long-lived assets. The global economic conditions and other adverse factors discussed above heighten the risk of a significant asset impairment. Examples of conditions that could be indicative of impairment which would require us to evaluate the recovery of a long-lived asset or asset group include:

• current period operating or cash flow losses combined with a history of operating or cash flow losses or a projection that demonstrates continuing losses associated with the use of a long-lived asset group;

• a significant adverse change in legal factors, including changes in environmental or other regulations or in the business climate that could affect the value of a long-lived asset group, including an adverse action or assessment by a regulator; and

• a significant adverse change in the extent or manner in which a long-lived asset group is being used or in its physical condition.

As further described in Item 1.—Regulatory Matters—United Kingdom of the 2010 Form 10-K, the Northern Ireland Authority for Utility Regulation (“NIAUR”) had the right to require the termination of the long-term PPAs under which Kilroot, our generation business in the United Kingdom, supplies electricity to NIE Energy as early as 2010. One of the conditions to the early termination was 180 days’ notice, which was provided to Kilroot on April 30, 2010. At March 31, 2010, management evaluated Kilroot’s long-lived assets for potential impairment assuming the early termination of the PPA and concluded that no impairment existed at that time. On October 28, 2010, Kilroot received final notice from NIAUR directing Kilroot and NIE Energy to terminate the PPA effective November 1, 2010. Kilroot may not be able to replace the contract on competitive terms and, upon cancellation of the PPA effective November 1, 2010, became a merchant plant. It will operate under the gross mandatory pool of the SEM in Northern Ireland. There have been no additional impairment indicators since March 31, 2010.

AES Eastern Energy (“AEE”), currently classified as held for sale, operates four coal-fired power plants: Cayuga, Greenidge, Somerset and Westover, representing generation capacity of 1,169 MW in the western New York power market. During 2010, the power prices in the New York power market trended downward, similar to North America natural gas prices. The New York Independent System Operator (“NYISO”) continues to move forward with the potential addition of a new capacity zone, which is expected to put further downward pressure on the capacity prices paid to the AEE facilities. In November 2010, legislation was proposed in the state of New Jersey for the addition of state subsidized capacity additions serving to lower PJM capacity price expectations. Similar changes to capacity pricing may be made in the future in New York. Continued pressure on energy prices, driven by falling natural gas prices and state actions, indicate that capacity prices are unlikely to reach levels significantly in excess of those achieved historically. Accordingly, management’s view of long-term capacity markets in western New York was revised downward. In December 2010, management revised its cash flow forecasts based on these developments and forecasted continuing negative operating cash flow and losses through 2034. The forecasted energy prices are such that a hedge strategy significantly beyond those in place at December 31, 2010 would not be economical. Additionally, on November 15, 2010, Standard & Poor’s downgraded the bond rating of AEE from BB to B+. Collectively, in the fourth quarter of 2010, these events were considered an impairment indicator for the AES New York asset group, of which AEE is the most significant component and necessitated an impairment evaluation of the asset group.

The long-lived asset group subject to the impairment evaluation was determined to include all of the generating plants of AEE. This determination was based on the assessment of the plants’ inability to generate independent cash flow. When the recoverability test of the asset group was performed, management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was not recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. While there were numerous assumptions that impact the fair value, potential state actions that impact capacity pricing and forward energy prices were the most significant.

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In determining the fair value of the asset group, the three valuation approaches prescribed by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered the most appropriate and resulted in a zero fair value. Any salvage value of the asset group is expected to be offset by environmental and other remediation costs. Accordingly, the long-lived asset group was considered fully impaired and $827 million of impairment expense was recognized in the fourth quarter of 2010, which has been reflected in Income from operations of discontinued operations on the Consolidated Statement of Operations.

In March 2010, Deepwater, our 160 MW petroleum coke (“pet coke”)-fired merchant power plant located in Texas, experienced deteriorating market conditions due to increasing pet coke prices and diminishing power prices. As a result, Deepwater incurred an operating loss for the period and forecasted short term losses. These conditions gradually worsened in the second quarter of 2010 and management determined it could not operate the plant at certain times during the year without generating negative operating margin.

As the contraction of energy margin continued in the second quarter of 2010, management determined the collective events to be an indicator of impairment and performed an impairment evaluation of Deepwater’s goodwill and recoverability test for the long-lived asset group. Based on the results of these tests, in the second quarter of 2010, management concluded no impairment was necessary. In the third quarter of 2010, these downward trends continued and management, after determining that there was an indicator of impairment, performed another impairment evaluation of Deepwater’s goodwill and a recoverability test of the long-lived asset group. The results in the third quarter indicated no impairment was necessary for the asset group, but the goodwill associated with the reporting unit was deemed to be impaired and the $18 million goodwill balance was written-off during the quarter ended September 30, 2010.

In the fourth quarter of 2010, further adverse trends in energy and pet coke pricing curves were observed in management’s review of external market analyses. The most significant impact on the forecasted energy prices reviewed by management in November 2010 related to the general external market consensus that Federal CO₂ cap and trade legislation was less likely, resulting in a drop in long-term energy price projections. At that time, Deepwater’s revised forecasts indicated that Deepwater would have operating losses which would extend beyond 2020 and negative cash flows through 2019. Management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was no longer recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. In determining the fair value of the asset group, all three valuation approaches described by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered most appropriate. On that basis, the carrying value of the asset group was determined to be impaired and $79 million of impairment expense was recognized in the fourth quarter of 2010.

In May 2010, the California State Water Board approved a policy to reduce the number of marine animals killed by seawater cooling systems in coastal power plants in California. At that time, since the policy required the approval of California’s Office of Administrative Law, it was unclear whether the policy would be approved and what form the regulations would take. In September 2010, the Office of Administrative Law in California approved the policy that will require the Company to change the process through which it uses ocean water to cool the generation turbines at its Alamitos, Huntington Beach and Redondo Beach (collectively “Southland”) gas-fired generation facilities in California. The policy requires compliance with the new regulations by December 31, 2020. The change in the water cooling process will result in significant future capital expenditures to ensure compliance with the new regulations. This was considered as an impairment indicator for the long-lived asset groups. The recoverability test of the long-lived asset groups indicated that the carrying amount of the Huntington Beach asset group was not recoverable on an undiscounted cash flows basis. To assist management in determining the fair value of the asset group, an independent valuation firm was engaged. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. The carrying amount of the

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Huntington Beach asset group exceeded its fair value by $200 million which was recognized as an impairment expense. The carrying amounts of the Alamitos and Redondo Beach long-lived asset groups were determined to be recoverable on an undiscounted cash flows basis at September 30, 2010 and no impairment was necessary.

During the third quarter of 2010, we also recognized impairment on the long-lived assets at our Tisza II generation plant in Hungary. Tisza II operates under an annual contract with an off-taker. In the third quarter of 2010, when Tisza II began the negotiation of its 2011 contract, future undiscounted cash flows of the plant were no longer expected to recover the long-lived assets group’s carrying amount due to prevailing market rates, higher generation costs and lower demand expectations. Accordingly, the Company measured the fair value of the long-lived asset group and recorded an impairment expense of $85 million, representing the excess of carrying amount over the fair value at September 30, 2010.

Goodwill. The Company seeks business acquisitions as one of its growth strategies. We have achieved significant growth in the past as a result of several business acquisitions, which also resulted in the recognition of goodwill. As noted in Item 1A.—Risk Factors of the 2010 Form 10-K, there is always a risk that “Our acquisitions may not perform as expected.” The benefits of goodwill are typically realized through the future operating results of an acquired business. Management believes that the recoverability of goodwill is positively correlated with the economic environments in which our acquired businesses operate and a severe economic downturn could negatively impact the recoverability of goodwill. Also, the evolving environmental regulations, including GHG regulations, around the globe continue to increase the operating costs of our generation businesses. In extreme situations, the environmental regulations could even make a once profitable business uneconomical. In addition, most of our generation businesses have a finite life and as the acquired businesses reach the end of their finite lives, the carrying amount of goodwill is gradually recovered through their periodic operating results. The accounting guidance, however, prohibits the systematic amortization of goodwill and rather requires an annual impairment evaluation. Thus, as some of our acquired businesses approach the end of their finite lives, they may incur goodwill impairment charges even if there are no discrete adverse changes in the economic environment.

As noted in Long-lived assets above, adverse market conditions at Deepwater were also considered an interim impairment indicator for its goodwill. Accordingly, in the second and third quarters of 2010, interim goodwill impairment evaluations were performed at the Deepwater reporting unit level. The reporting unit passed Step 1 of goodwill impairment evaluation in the second quarter and no impairment was recognized. In the third quarter, however, the reporting unit failed Step 1 of goodwill impairment evaluation. Upon measurement of impairment loss in Step 2, the entire $18 million goodwill balance was considered impaired and recognized as goodwill impairment.

In the fourth quarter of 2010, the Company completed its annual goodwill impairment evaluation and did not have any reporting units that were considered “at risk.” A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. While there were no potential impairment indicators that could result in the recognition of goodwill impairment for any of these reporting units, it is possible we may incur goodwill impairment on these reporting units in future years if any of the following events occur: a significant adverse change in business climate or legal factors, an adverse action or assessment by a regulator, a sale of assets at less than carrying amount, unanticipated competition, a loss of key personnel, an acquisition not performing as expected, changing environmental regulations that significantly increase the cost of doing business, or a business reaches the end of its finite life. The likelihood of the occurrence of these events may increase because of the challenging global macroeconomic conditions.

Regulatory—Environment. The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. For a description of material regulations faced by the Company, see Item 1.—Business—Regulatory Matters of the

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2010 Form 10-K. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our United States or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors, “Our businesses are subject to stringent environmental laws and regulations”, “Our businesses are subject to enforcement initiatives from environmental regulatory agencies” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows” set forth in the 2010 Form 10-K.

Recent Events

Subsequent to December 31, 2010, the Company continued to repurchase stock under the stock repurchase program announced on July 7, 2010. The Company has repurchased 1,026,610 shares at a cost of $13 million in 2011, bringing the cumulative total through February 22, 2011 to 9,409,435 shares at a total cost of $112 million (average price of $11.92 per share including commissions). As of February 22, 2011, $388 million of the $500 million authorized remained available under the stock repurchase program. For additional information, see Note 14—Equity included in Item 8 of this Form 8-K.

On February 1, 2011, AES Thames, LLC (“Thames”), our 208 MW coal-fired plant in Connecticut, filed petitions for bankruptcy protection under Chapter 11 in the U. S. Bankruptcy Court. The bankruptcy is due, in part, to the increased cost of energy production. The bankruptcy protection is not expected to have a material impact on the Company’s financial position or the results of operations.

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Consolidated Results of Operations

	Year Ended December 31,
Results of operations	2010			2009			2008			$ change 2010 vs. 2009			$ change 2009 vs. 2008
	(in millions, except per share amounts)
Revenue:
Latin America Generation	$	4,281		$	3,651		$	4,468		$	630		$	(817	)
Latin America Utilities		7,222			6,092			5,907			1,130			185
North America Generation		1,551			1,483			1,644			68			(161	)
North America Utilities		1,145			1,068			1,079			77			(11	)
Europe Generation		1,318			762			1,044			556			(282	)
Asia Generation		618			375			345			243			30
Corporate and Other(1)		1,065			871			1,012			194			(141	)
Eliminations(2)		(1,019	)		(862	)		(991	)		(157	)		129
Total Revenue	$	16,181		$	13,440		$	14,508		$	2,741		$	(1,068	)
Gross Margin:
Latin America Generation	$	1,497		$	1,357		$	1,398		$	140		$	(41	)
Latin America Utilities		1,072			918			886			154			32
North America Generation		417			417			499			—			(82	)
North America Utilities		249			239			261			10			(22	)
Europe Generation		310			244			283			66			(39	)
Asia Generation		240			93			(10	)		147			103
Corporate and Other(3)		186			118			62			68			56
Eliminations(4)		17			20			38			(3	)		(18	)
General and administrative expenses		(392	)		(339	)		(369	)		(53	)		30
Interest expense		(1,506	)		(1,462	)		(1,746	)		(44	)		284
Interest income		410			346			515			64			(169	)
Other expense		(238	)		(106	)		(161	)		(132	)		55
Other income		104			460			372			(356	)		88
Gain on sale of investments		—			131			909			(131	)		(778	)
Loss on sale of subsidiary stock		—			—			(31	)		—			31
Goodwill impairment		(21	)		(122	)		—			101			(122	)
Asset impairment expense		(391	)		(20	)		(175	)		(371	)		155
Foreign currency transaction gains (losses) on net monetary position		(33	)		34			(183	)		(67	)		217
Other non-operating expense		(7	)		(12	)		(15	)		5			3
Income tax expense		(596	)		(580	)		(719	)		(16	)		139
Net equity in earnings of affiliates		183			92			33			91			59
Income from continuing operations		1,501			1,828			1,847			(327	)		(19	)
Income (loss) from operations of discontinued businesses		(506	)		77			179			(583	)		(102	)
Gain (loss) from disposal of discontinued businesses		64			(150	)		6			214			(156	)
Net income		1,059			1,755			2,032			(696	)		(277	)
Noncontrolling interests:
Income from continuing operations attributable to noncontrolling interests		(1,006	)		(1,099	)		(759	)		93			(340	)
(Income) loss from discontinued operations attributable to noncontrolling interests		(44	)		2			(39	)		(46	)		41
Net income attributable to The AES Corporation	$	9		$	658		$	1,234		$	(649	)	$	(576	)
Per Share Data:
Basic income per share from continuing operations	$	0.64		$	1.09		$	1.62		$	(0.45	)	$	(0.53	)
Diluted income per share from continuing operations	$	0.64		$	1.09		$	1.61		$	(0.45	)	$	(0.52	)

⁽¹⁾  Corporate and Other includes revenue from our generation and utilities businesses in Africa, utilities businesses in Europe, Wind Generation and other renewables initiatives.

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⁽²⁾  Represents inter-segment eliminations of revenue related to transfers of electricity from Tietê (generation) to Eletropaulo (utility).

⁽³⁾  Corporate and Other gross margin includes gross margin from our generation and utilities businesses in Africa, utilities businesses in Europe, Wind Generation and other renewables initiatives.

⁽⁴⁾  Represents inter-segment eliminations of gross margin related to corporate charges for self insurance premiums.

Segment Analysis

Latin America—Generation

The following table summarizes revenue and gross margin for our Generation segment in Latin America for the periods indicated:

	For the Years Ended December 31,
	2010		2009		2008		% Change 2010 vs. 2009			% Change 2009 vs. 2008
	($’s in millions)
Latin America Generation
Revenue	$	4,281	$	3,651	$	4,468		17	%		-18	%
Gross Margin	$	1,497	$	1,357	$	1,398		10	%		-3	%

Fiscal Year 2010 versus 2009

Excluding the favorable impact of foreign currency translation and remeasurement of $133 million, generation revenue for 2010 increased $497 million, or 14%, from 2009 primarily due to:

• higher spot prices of $221 million associated with increased fuel prices in Argentina;

• higher volume of $139 million at Gener in Chile due to higher demand;

• higher volume and ancillary services of $115 million, and higher contract prices from PPAs indexed to gas and higher spot prices of $27 million in the Dominican Republic;

• higher contract prices of $58 million in Colombia and Tietê in Brazil;

• the positive impact of $28 million resulting from the final settlement of the power sales agreement between Sul and Uruguaiana, our businesses in Brazil; and

• higher volume of $21 million in Panama due to higher water inflows into the system.

These increases were partially offset by:

• lower volume sold at Uruguaiana of $53 million as a result of renegotiation of its power sales agreements;

• lower volume due to unfavorable hydrology in Colombia and Argentina of $41 million;

• lower contract prices at Gener of $32 million; and

• lower contract prices on PPAs indexed to international coal prices in the Dominican Republic of $22 million.

Excluding the favorable impact of foreign currency translation and remeasurement of $106 million, generation gross margin for 2010 increased $34 million, or 3%, from 2009 primarily due to:

• higher spot prices in Argentina of $69 million;

• higher volume and ancillary services in the Dominican Republic of $55 million;

• higher contract prices of $33 million in Colombia;

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• the positive impact of $28 million resulting from the final settlement of the power sales agreement between Sul and Uruguaiana, as mentioned above; and

• higher volume of $23 million in Panama.

These increases were partially offset by:

• higher fuel and purchased energy prices at Gener of $48 million;

• the net effect of lower PPA prices and higher fuel costs in the Dominican Republic of $38 million;

• the impact of a reversal of bad debt expense during the first quarter of 2009 of $36 million at Uruguaiana as a result of the renegotiation of one of its power sales agreements; and

• higher fixed costs of $30 million at Gener primarily due to higher employee costs, increased maintenance expenses and costs incurred due to construction delays at Campiche.

For the year ended December 31, 2010, revenue increased 17% while gross margin increased 10%, primarily due to higher spot purchases and fuel prices at Gener and the reversal of bad debt expense as a result of the renegotiation of one of the power sales agreements at Uruguaiana in the first quarter of 2009.

Fiscal Year 2009 versus 2008

Excluding the unfavorable impact of foreign currency translation and remeasurement of $181 million, driven by Brazil and Argentina, generation revenue for 2009 decreased $636 million, or 14%, from 2008 primarily due to:

• lower spot and contract prices of $295 million at Gener;

• lower volume of $227 million at Uruguaiana as a result of the renegotiation of its power sales agreements in 2009 to reduce the energy volume sold; and

• lower energy prices and volume of $174 million in the Dominican Republic.

These decreases were partially offset by:

• an increase of $100 million due to fewer outages at Gener and in Argentina in 2009; and

• higher prices of energy sold of $66 million at Tietê.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $94 million, driven by Brazil and Argentina, generation gross margin for 2009 increased $53 million, or 4%, from 2008 primarily due to:

• higher prices of energy sold of $66 million at Tietê;

• fewer outages of $60 million at Gener and in Argentina;

• lower diesel consumption, partially offset by higher energy purchases and higher gas consumption, at Gener of $47 million;

• lower volume of energy purchased at Uruguaiana of $44 million as a result of the renegotiated power sales agreements; and

• the favorable impact of $28 million of a decrease in bad debt expense at Uruguaiana as a result of the renegotiated power sales agreements.

These increases were partially offset by:

• the unfavorable impact of lower energy prices of $75 million in the Dominican Republic;

• lower volume and energy prices of $66 million in Argentina;

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• higher purchased energy prices of $48 million at Uruguaiana; and

• lower spot sales of $48 million at Panama.

For the year ended December 31, 2009, revenue decreased by 18% while gross margin decreased 3%, primarily due to reduced energy purchases, fewer outages and lower bad debt expense.

Latin America—Utilities

The following table summarizes revenue and gross margin for our Utilities segment in Latin America for the periods indicated:

	For the Years Ended December 31,
	2010		2009		2008		% Change 2010 vs. 2009			% Change 2009 vs. 2008
	($’s in millions)
Latin America Utilities
Revenue	$	7,222	$	6,092	$	5,907		19	%		3	%
Gross Margin	$	1,072	$	918	$	886		17	%		4	%

Fiscal Year 2010 versus 2009

Excluding the favorable impact of foreign currency translation of $697 million, primarily in Brazil, utilities revenue for 2010 increased $433 million, or 7%, from 2009 primarily due to:

• increased volume of $316 million, primarily in Brazil, due to increased market demand; and

• higher tariffs of $114 million primarily related to the July 2009 tariff reset in Brazil partially offset by the unfavorable impact on rates at Eletropaulo in Brazil of a cumulative adjustment to regulatory liabilities and higher energy prices across our Latin America utility businesses associated with energy purchases passed through to customers of $97 million.

Excluding the favorable impact of foreign currency translation of $107 million, primarily in Brazil, utilities gross margin for 2010 increased $47 million, or 5%, from 2009 primarily due to:

• increased volume of $163 million, primarily in Brazil, due to the increased market demand; and

• lower contingencies of $142 million in Eletropaulo primarily related to labor contingencies which included a one-time reversal, reflecting an agreement with Fundação CESP, the pension plan administrator, of $51 million associated with claims for past benefit obligations which will now be accounted for as a component of the pension plan.

These increases were partially offset by:

• higher fixed costs of $238 million primarily due to the recovery in 2009 of a municipality receivable previously written off in Brazil and higher salaries and other employee related costs, provisions for commercial losses, regulatory penalties and maintenance costs; and

• $28 million related to the final settlement of the power sales agreement between Sul and Uruguaiana.

Fiscal Year 2009 versus 2008

Excluding the unfavorable impact of foreign currency translation of $442 million, primarily in Brazil, utilities revenue for 2009 increased $627 million, or 11%, from 2008 primarily due to:

• higher tariffs of $560 million reflecting the recovery of energy purchases of $453 million that were passed through to customers at our utilities in Brazil and El Salvador; and

• higher volume in Brazil of $62 million.

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Excluding the unfavorable impact of foreign currency translation of $62 million, primarily in Brazil, utilities gross margin for 2009 increased $94 million, or 11%, from 2008 primarily due to:

• higher tariffs of $107 million in El Salvador and Brazil;

• a $64 million recovery of a municipality receivable previously written off;

• a non-recurring PIS/COFINS fine in 2008 of $33 million; and

• higher volume of $32 million across the region.

These increases were partially offset by:

• the unfavorable impact of higher fixed costs of $120 million mainly related to pension expense, labor contingencies and maintenance costs in Brazil.

North America—Generation

The following table summarizes revenue and gross margin for our Generation segment in North America for the periods indicated:

	For the Years Ended December 31,
	2010		2009		2008		% Change 2010 vs. 2009			% Change 2009 vs. 2008
	($’s in millions)
North America Generation
Revenue	$	1,551	$	1,483	$	1,644		5	%		-10	%
Gross Margin	$	417	$	417	$	499		0	%		-16	%

Fiscal Year 2010 versus 2009

Excluding the favorable impact of foreign currency translation of $19 million, generation revenue for 2010 increased $49 million, or 3%, from 2009 primarily due to:

• increased rates, volume and an availability bonus at TEG/TEP in Mexico of $41 million;

• higher volume, primarily due to fewer outages and higher rates, of $22 million at Merida in Mexico; and

• higher volume of $19 million at Warrior Run in Maryland due to fewer outages.

These increases were partially offset by:

• a net decrease of $18 million at Deepwater in Texas primarily due to lower volume; and

• a net decrease of $14 million in Puerto Rico primarily due to a penalty from a forced outage.

Excluding the favorable impact of foreign currency translation of $3 million, generation gross margin for 2010 decreased $3 million, or 1%, from 2009 primarily due to:

• a decrease of $16 million at Deepwater due to lower volume and rates;

• a net decrease of $11 million in Puerto Rico primarily due to a penalty from a forced outage;

• a decrease of $9 million in Hawaii due to an unfavorable impact of mark-to-market derivatives;and

• a decrease of $7 million in Puerto Rico due to higher fixed costs.

These decreases were partially offset by:

• a net increase of $26 million at TEG/TEP due to a current year availability bonus and fewer outages partially offset by higher fuel prices; and

• higher volume of $14 million at Warrior Run due to fewer outages.

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Fiscal Year 2009 versus 2008

Excluding the unfavorable impact of foreign currency translation of $44 million, primarily in Mexico, generation revenue for 2009 decreased $117 million, or 7%, from 2008 primarily due to:

• a decrease of $80 million due to a reduction in natural gas prices at Merida;

• increased outages of $22 million and $21 million at Warrior Run and TEG/TEP, respectively;

• lower rates of $20 million at Deepwater; and

• the unfavorable impact in 2009 of derivative amortization at Warrior Run of $9 million.

These decreases were partially offset by:

• an increase of $18 million at Puerto Rico due to the pass-through of higher fuel costs; and

• a $15 million revenue adjustment at Merida in 2008.

Excluding the unfavorable impact of foreign currency translation of $9 million, generation gross margin for 2009 decreased $73 million, or 15%, from 2008 primarily due to:

• a $29 million unfavorable impact of mark-to-market derivative adjustments on coal supply contracts in Hawaii as a result of a gain of $22 million in 2008 compared to a loss of $7 million in 2009;

• an increase in outages of $22 million at Warrior Run;

• the unfavorable impact of $9 million in 2009 of derivative amortization at Warrior Run; and

• lower rates of $6 million at Deepwater.

These decreases were partially offset by:

• a $15 million revenue adjustment at Merida in 2008.

For the year ended December 31, 2009, revenue decreased by 10% while gross margin decreased 16%, primarily due to the unfavorable impact of derivatives in 2009 in Hawaii that had no corresponding impact on revenue.

North America—Utilities

The following table summarizes revenue and gross margin for our Utilities segment in North America for the periods indicated:

	For the Years Ended December 31,
	2010		2009		2008		% Change 2010 vs. 2009			% Change 2009 vs. 2008
	($’s in millions)
North America Utilities
Revenue	$	1,145	$	1,068	$	1,079		7	%		-1	%
Gross Margin	$	249	$	239	$	261		4	%		-8	%

Fiscal Year 2010 versus 2009

Utilities revenue for 2010 increased $77 million, or 7%, from 2009 primarily due to:

• higher retail demand of $64 million as a result of warmer weather and higher fuel adjustment charges; and

• increased wholesale revenue of $11 million primarily due to higher prices.

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Utilities gross margin for 2010 increased $10 million, or 4%, from 2009 primarily due to:

• higher retail margin of $20 million due to increased demand;

• lower pension expense of $12 million; and

• lower emission allowance expense of $5 million.

These increases were partially offset by:

• increased maintenance expenses of $16 million due to the timing of major generating unit overhauls; and

• increased fixed costs of $14 million.

For the year ended December 31, 2010, revenue increased by 7% while gross margin increased 4%, primarily due to increased fuel and maintenance costs.

Fiscal Year 2009 versus 2008

Utilities revenue for 2009 decreased $11 million, or 1%, from 2008 primarily due to:

• lower retail volume of $31 million due primarily to milder weather and the economic recession; and

• decreased wholesale revenue of $7 million driven by lower market prices.

These decreases were partially offset by:

• $32 million of voluntary credits IPL provided to retail customers in 2008. See Item 1.—Business—Regulatory Matters—North America of the 2010 Form 10-K for further information regarding these credits.

Utilities gross margin for 2009 decreased $22 million, or 8%, from 2008 primarily due to:

• decreased wholesale margin of $16 million due to unfavorable prices; and

• increased pension expense of $25 million largely due to the decline in market value of IPL’s pension assets during 2008.

These decreases were partially offset by:

• increased retail margin of $15 million, primarily due to the $32 million of voluntary customer credits IPL issued to its retail customers in 2008, partially offset by lower retail sales volumes in 2009; and

• decreased property tax expense of $5 million.

For the year ended December 31, 2009, revenue decreased by 1% while gross margin decreased 8%, primarily due to the $25 million increase in pension expense and the $32 million of voluntary customer credits IPL issued to its retail customers in 2008, both of which had an unfavorable impact on gross margin.

Europe—Generation

The following table summarizes revenue and gross margin for our Generation segment in Europe for the periods indicated:

	For the Years Ended December 31,
	2010		2009		2008		% Change 2010 vs. 2009			% Change 2009 vs. 2008
	($’s in millions)
Europe Generation
Revenue	$	1,318	$	762	$	1,044		73	%		-27	%
Gross Margin	$	310	$	244	$	283		27	%		-14	%

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Fiscal Year 2010 versus 2009

Excluding the unfavorable impact of foreign currency translation of $37 million, generation revenue for 2010 increased $593 million, or 78%, from 2009 primarily due to:

• $409 million from the adoption of new accounting guidance on the consolidation of variable interest entities (“VIEs”) which resulted in the consolidation of Cartagena in Spain, a generation business previously accounted for under the equity method of accounting;

• $117 million from the operations of Ballylumford in the United Kingdom, which was acquired in August 2010;

• higher tariffs of $16 million at Altai in Kazakhstan;

• $15 million from a full year of combined cycle operations at our Amman East plant in Jordan, which was single cycle until August 2009; and

• higher volume of $15 million at Kilroot in the United Kingdom largely driven by coal pass-through and increased demand, partially offset by lower capacity revenue due to the termination of the long term PPA and related supplementary agreements.

Excluding the unfavorable impact of foreign currency translation of $3 million, generation gross margin for 2010 increased $69 million, or 28%, from 2009 primarily due to:

• $62 million from the consolidation of Cartagena as discussed above;

• higher tariffs and lower fixed costs at Altai of $29 million; and

• $13 million from the operations of Ballylumford since its acquisition.

These increases were partially offset by:

• lower gross margin of $28 million primarily from the termination of the long-term PPA at Kilroot; and

• lower gross margin of $8 million in Hungary primarily attributable to higher fuel costs that could not be passed through and lower sales of emission allowances.

For the year ended December 31, 2010, revenue increased 73% while gross margin increased 27%, primarily due to the consolidation of Cartagena and acquisition of Ballylumford that have a larger positive impact on revenue than gross margin, and the positive impact of higher energy revenue at Kilroot, which as a pass-through had no corresponding impact on gross margin.

Fiscal Year 2009 versus 2008

Excluding the unfavorable impact of foreign currency translation of $130 million, driven mainly by Kilroot, Hungary and Kazakhstan, generation revenue for 2009 decreased $152 million, or 15%, from 2008 primarily due to:

• lower revenue of $101 million as a result of the sale of Ekibastuz and Maikuben in May 2008;

• lower volume of $67 million at Kilroot, a coal-fired plant, mainly driven by lower dispatch due to favorable gas prices compared to coal; and

• lower volume attributable to reduced demand and the cancellation of one of our PPAs, partially offset by higher energy prices, in Hungary of $52 million.

These decreases were partially offset by:

• the benefit of new business of $50 million at Amman East, which commenced single cycle operations in July 2008; and

• higher rates of $15 million in Kazakhstan.

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Excluding the unfavorable impact of foreign currency translation of $36 million, driven mainly by Kilroot and Kazakhstan, generation gross margin for 2009 decreased $3 million, or 1%, from 2008 primarily due to:

• lower gross margin of $41 million as a result of the sale of Ekibastuz and Maikuben in May 2008; and

• an overall increase of $28 million in fixed costs across the region.

These decreases were partially offset by:

• higher energy prices, partially offset by lower volume attributable to reduced demand, in Hungary of $20 million;

• the benefit of $17 million from new business at Amman East;

• higher capacity revenue of $15 million at Kilroot; and

• higher energy prices of $12 million in Kazakhstan.

For the year ended December 31, 2009, revenue decreased 27% while gross margin decreased 14%, primarily due to sale of Ekibastuz and Maikuben in 2008, lower pass-through energy revenue at Kilroot, and lower volume in Hungary, all of which had a larger adverse impact on revenue than gross margin.

Asia—Generation

The following table summarizes revenue and gross margin for our Generation segment in Asia for the periods indicated:

	For the Years Ended December 31,
	2010		2009		2008			% Change 2010 vs. 2009			% Change 2009 vs. 2008
	($’s in millions)
Asia Generation
Revenue	$	618	$	375	$	345			65	%		9	%
Gross Margin	$	240	$	93	$	(10	)		158	%		1030	%

Fiscal Year 2010 versus 2009

Excluding the favorable impact of foreign currency translation of $28 million, generation revenue for 2010 increased $215 million, or 57%, from 2009 primarily due to:

• favorable generation rates and volume of $210 million at Masinloc in the Philippines as a result of increased market demand and improved plant availability subsequent to the completion of its overhaul at the beginning of 2010; and

• higher demand from both new and existing contract and spot customers as a result of lower supply shortages in the Philippines power market due to a strong energy growth rate.

Excluding the favorable impact of foreign currency translation of $13 million, generation gross margin for 2010 increased $134 million, or 144%, from 2009 primarily due to a combination of higher availability attributable to improved plant operations, higher market demand and favorable spot prices at Masinloc.

For the year ended December 31, 2010, revenue increased 65% while gross margin increased 158%, primarily due to the positive influence on gross margin due to favorable spot rates and operational efficiencies resulting from the Masinloc plant overhauls in late 2009 and early 2010, which led to higher availability and allowed for more efficient operations that have materially improved the operating results for 2010 as compared to 2009.

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Fiscal Year 2009 versus 2008

Excluding the unfavorable impact of foreign currency translation of $23 million, primarily in the Philippines and Sri Lanka, generation revenue for 2009 increased $53 million, or 15%, from 2008 primarily due to:

• the benefit of $46 million of our new business Masinloc, which was acquired in April 2008;

• increased revenue of $70 million in 2009 at Masinloc due to improved rates and volume as a result of improved availability and new customer contracts; and

• $18 million from a one-time favorable energy sales settlement at Masinloc.

These increases were partially offset by:

• the decrease in revenue of $71 million at Kelanitissa in Sri Lanka primarily due to a decline in fuel costs which are largely passed through to the customer and higher outages in 2009 as compared to 2008 partially offset by higher capacity revenue.

Excluding the unfavorable impact of foreign currency translation of $6 million, primarily in the Philippines, generation gross margin for 2009 increased $109 million, or 1,090%, from 2008 primarily due to:

• the impact of our new business at Masinloc of $23 million;

• a $91 million increase at Masinloc due to higher contract sales, where margins are more favorable than spot sales, lower fuel prices, improved availability and the favorable energy sales settlement described above; and

• higher capacity revenue at Kelanitissa of $10 million.

These increases were partially offset by:

• higher fixed costs of $20 million at Masinloc.

For the year ended December 31, 2009, revenue increased 9% while gross margin increased 1,030%, primarily due to higher contract margins at Masinloc as a result of improved operations, availability and lower fuel prices, as well as the larger relative impact on gross margin from the one-time favorable energy sales settlement described above.

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Corporate and Other

Corporate and other includes the net operating results from our generation and utilities businesses in Africa, utilities businesses in Europe, AES Wind Generation and renewables projects which are immaterial for the purposes of separate segment disclosure. The following table excludes inter-segment activity and summarizes revenue and gross margin for Corporate and Other entities for the periods indicated:

	For the Years Ended December 31,
	2010		2009			2008			% Change 2010 vs. 2009			% Change 2009 vs. 2008
	($’s in millions)
Revenue
Europe Utilities	$	356	$	286		$	403			24	%		-29	%
Africa Utilities		422		370			379			14	%		-2	%
Africa Generation		61		65			65			-6	%		0	%
Wind Generation		202		133			128			52	%		4	%
Corp/Other		24		17			37			41	%		-54	%
Total Corporate and Other	$	1,065	$	871		$	1,012			22	%		-14	%
Gross Margin
Europe Utilities	$	21	$	16		$	34			31	%		-53	%
Africa Utilities		65		71			30			-8	%		137	%
Africa Generation		54		41			28			32	%		46	%
Wind Generation		44		11			19			300	%		-42	%
Corp/Other		2		(21	)		(49	)		110	%		57	%
Total Corporate and Other	$	186	$	118		$	62			58	%		90	%

Fiscal Year 2010 versus 2009

Excluding the unfavorable impact of foreign currency translation of $30 million, primarily in Cameroon, Corporate and Other revenue increased $224 million for 2010, or 26% from 2009. The increase was primarily due to:

• higher volume at our utility businesses in Ukraine driven by an overall increase in market demand;

• higher volume and utility tariffs at Sonel in Cameroon driven by an increase in market demand; and

• incremental revenue from new wind generation projects that commenced operations during the year and an overall volume increase across our wind businesses.

Excluding the unfavorable impact of foreign currency translation of $9 million, primarily in Cameroon, Corporate and Other gross margin increased $77 million for 2010, or 65% from 2009. The increase was primarily due to:

• an increase in gross margin from our new wind generation projects and higher volume, as discussed above; and

• an increase in volume at Dibamba, our generation business, in Cameroon.

These increases were partially offset by:

• an increase in fixed costs at Sonel.

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Fiscal Year 2009 versus 2008

Excluding the unfavorable impact of foreign currency translation of $162 million, primarily in Ukraine, Corporate and Other revenue increased $21 million for 2009, or 2%, from 2008. The increase was primarily due to:

• higher tariffs in Ukraine of $27 million.

Excluding the unfavorable impact of foreign currency translation of $12 million, primarily in Ukraine, Corporate and Other gross margin increased $68 million for 2009, or 110%, from 2008. The increase was primarily due to:

• a decrease in fixed costs across the Africa region.

The increase was partially offset by:

• higher fuel consumption attributable to lower hydrology at Sonel.

General and Administrative Expense

General and administrative expense includes those expenses related to corporate and region staff functions and/or initiatives, executive management, finance, legal, human resources, information systems, and development costs.

General and administrative expenses increased $53 million, or 16%, to $392 million in 2010 from 2009. The increase is primarily related to business development costs associated with increased development efforts, primarily in Europe, Turkey and India.

General and administrative expenses decreased $30 million, or 8%, to $339 million in 2009 from 2008. The decrease is primarily related to 2008 professional fees associated with remediation efforts and a reduction in business development costs. The favorable variance is partially offset by an increase in costs associated with the worldwide implementation of SAP.

Interest expense

Interest expense increased $44 million, or 3%, to $1.5 billion in 2010 from 2009. This increase was primarily due to interest expense at Cartagena which is now a consolidated entity, higher interest rates at Tietê, increased debt principal at Eletropaulo and interest being expensed related to St. Nikola, our wind project in Bulgaria, due to commencement of operations in 2010. These increases were partially offset by reduced debt principal at the Parent Company.

Interest expense decreased $284 million, or 16%, to $1.5 billion in 2009 from 2008. This decrease was primarily due to lower interest rates globally due to economic conditions and inflationary adjustments to the market price index in Brazil. In addition, interest expense decreased as a result of favorable foreign currency translation, mainly in Brazil and lower interest expenses associated with decreased debt balances at Eletropaulo. These decreases were partially offset by higher interest expense at Masinloc in the Philippines which was acquired in April 2008, and interest expense at Infovias in Brazil where a fee on a non-exercised credit line was written off.

Interest income

Interest income increased $64 million, or 18%, to $410 million in 2010 from 2009. This increase was primarily due to a higher average balance in short term investments at Eletropaulo and the favorable impact of foreign currency translation in Brazil as well as the settlement of a dispute related to inflation adjustments for energy sales at Tietê. These increases were partially offset by reduced interest income from a loan to a wind development project in Brazil which was repaid in June 2010.

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Interest income decreased $169 million, or 33%, to $346 million in 2009 from 2008. This decrease was primarily due to lower interest rates and lower investment balances in Brazil, unfavorable foreign currency translation in Brazil, the impact of decreased interest rates and inflationary adjustments on accounts receivable in 2008 at Gener in Chile and a decreased cash balance at the Parent Company.

Other income

	Years Ended December 31,
	2010		2009		2008
	(in millions)
Gain on extinguishment of tax and other liabilities	$	65	$	168	$	199
Tax credit settlement		—		129		—
Performance incentive fee		—		80		—
Insurance proceeds		—		—		40
Gain on sale of assets		12		14		34
Other		27		69		99
Total other income	$	104	$	460	$	372

Other income of $104 million for the year ended December 31, 2010 was primarily related to the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and noncontrolling interest was $9 million. Other income also included a gain on sale of assets at Eletropaulo.

Other income of $460 million for the year ended December 31, 2009 included $165 million from the reduction in interest and penalties associated with federal tax debts at Eletropaulo and Sul as a result of the REFIS program and a $129 million gain related to a favorable court decision enabling Eletropaulo to receive reimbursement of excess non-income taxes paid from 1989 to 1992 in the form of tax credits to be applied against future tax liabilities. The net impact to the Company after income taxes and noncontrolling interests for these items was $44 million. In addition, the Company recognized income in 2009 of $80 million from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. The management agreement was related to the sale of these businesses in Kazakhstan in May 2008; see further discussion of this transaction in Note 22—Acquisitions and Dispositions, to the Consolidated Financial Statements included in Item 8 of this Form 8-K.

Other income of $372 million for the year ended December 31, 2008 included gains on the extinguishment of a gross receipts tax liability and a legal contingency at Eletropaulo of $117 million and $75 million, respectively, $32 million of cash proceeds related to a favorable legal settlement at Southland in California, $29 million of insurance recoveries for damaged turbines at Uruguaiana, $23 million of gains associated with a sale of land at Eletropaulo and sales of turbines at Itabo, and compensation of $18 million for the impairment associated with the settlement agreement to shut down Hefei.

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Other expense

	Years Ended December 31,
	2010		2009		2008
	(in millions)
Loss on sale and disposal of assets	$	84	$	36	$	34
Gener gas settlement		72		—		—
Loss on extinguishment of debt		37		—		70
AES Wind transaction costs		22		—		—
Other		23		70		57
Total other expense	$	238	$	106	$	161

Other expense of $238 million for the year ended December 31, 2010 included $72 million for a settlement agreement of gas transportation contracts at Gener. There were also previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business which were written off upon the expiration of the letter of intent in June 2010. In addition, there were losses on the disposal of assets at Eletropaulo, Panama, and Gener, an $18 million loss on debt extinguishment at Andres and Itabo and a $15 million loss at the Parent Company from the retirement of senior notes.

Other expense of $106 million for the year ended December 31, 2009 included a $13 million loss recognized when three of our businesses in the Dominican Republic received $110 million par value bonds issued by the Dominican Republic government to settle existing accounts receivable for the same amount from the government-owned distribution companies. The loss represented an adjustment to reflect the fair value of the bonds on the date received. Other expense also included losses on the disposal of assets at Eletropaulo and Andres and contingencies at our businesses in Kazakhstan and Alicura in Argentina.

Other expense of $161 million for the year ended December 31, 2008 included $69 million of losses on the retirement of debt at the Parent Company in connection with the refinancing in June 2008 and IPALCO associated with a $375 million refinancing in April 2008 and losses on disposal of assets primarily at Eletropaulo.

Goodwill Impairment

In 2010, the Company recognized goodwill impairment expense of $21 million. During the third quarter of 2010, Deepwater, our pet coke-fired merchant generation facility in Texas, determined that there was an interim impairment indicator for its goodwill. This determination was primarily based on management’s decision not to operate the plant for more than 30 days in the third quarter of 2010, current operating and cash flow losses, and forecasted operating and cash flow losses for the remainder of 2010 through 2014 as a result of declining trends in energy pricing curves and increasing pet coke prices. As a result, Deepwater recognized a goodwill impairment of $18 million. Deepwater is reported in the North America Generation segment.

In 2009, the Company recognized goodwill impairment expense of $122 million. This was a result of impairment at certain of our businesses in the United Kingdom and Ukraine as a result of the Company’s annual goodwill impairment evaluation as of October 1. The most significant goodwill impairment was at Kilroot, our generation business in the United Kingdom. Factors contributing to the recognition of impairment included: reduced profit expectations based on latest estimates of future commodity prices and reduced expectations on the recovery of cash flows on the existing plant following the Company’s decision to forgo capital expenditures to meet emission allowance requirements taking effect in 2024. The fair value of the Company’s reporting units are inherently sensitive to the assumptions underlying the estimates of fair value. Note 1—General and Summary of Significant Accounting Policies, Fair Value, Goodwill and Intangibles in Item 8 of this Form 8-K provides a

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more detailed discussion of those assumptions. As discussed in Key Trends and Uncertainties, in the future, the fair values of the Company’s reporting units might decline as a result of adverse changes in their operating environments or the businesses reaching the end of their finite lives, which could require the Company to record additional goodwill impairment charges.

The Company did not incur any goodwill impairment charges in 2008.

Asset Impairment Expense

As discussed in Note 19—Impairment Expense to the Consolidated Financial Statements included in Item 8 of this Form 8-K, asset impairment expense for the year 2010 was $391 million and consisted primarily of the following:

Southland—In May 2010, the California State Water Board approved a policy to reduce the number of marine animals killed by seawater cooling systems in coastal power plants in California. At that time since the policy required the approval of California’s Office of Administrative Law, it was unclear whether the policy would be approved and the exact form the regulations would take. In September 2010, the Office of Administrative Law in California approved the policy that will require the Company to change the process through which it uses ocean water to cool the generation turbines at its Alamitos, Huntington Beach and Redondo Beach (collectively “Southland”) gas-fired generation facilities in California. The policy requires compliance with the new regulations by December 31, 2020. The change in the water cooling process will result in significant future capital expenditures to ensure compliance with the new regulations and the Company determined that an indicator of impairment existed at September 30, 2010. The Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment. The asset group was determined to be at the individual plant level and based on the undiscounted cash flow analysis, the Company determined that the Huntington Beach asset group was not recoverable. The fair value of the Huntington Beach asset group was then determined using a discounted cash flow analysis. To assist management in determining the fair value of the asset group, an independent valuation firm was engaged. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. The carrying value of the Huntington Beach plant of $288 million exceeded the fair value of $88 million resulting in the recognition of asset impairment expense of $200 million. The undiscounted cash flows of the Alamitos and Redondo Beach generation facilities exceeded their respective carrying values and resulted in no impairment. Huntington Beach is reported in the North America Generation reportable segment.

Tisza II—During the third quarter of 2010, the Company entered into annual negotiations with the offtaker of its Tisza II generation plant in Hungary. As a result of these preliminary negotiations, as well as the further deterioration of the economic environment in Hungary, the Company determined that an indicator of impairment existed at September 30, 2010. Thus, the Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment and determined that based on the undiscounted cash flow analysis, the carrying amount of the Tisza II asset group was not recoverable. The fair value of the asset group was then determined using a discounted cash flow analysis. The carrying value of the Tisza II asset group of $160 million exceeded the fair value of $75 million resulting in the recognition of asset impairment expense of $85 million. Tisza II is reported in the Europe Generation reportable segment.

Deepwater—In March 2010, Deepwater, our 160 MW petcoke-fired merchant power plant located in Texas, experienced deteriorating market conditions due to increasing pet coke prices and diminishing power prices. As a result, Deepwater incurred an operating loss for the period and forecasted short term losses. These conditions gradually worsened in the second quarter of 2010 and management determined it could not operate the plant at certain times during the year without generating negative operating margin.

As the contraction of energy margin continued in the second quarter of 2010, management determined the collective events to be an indicator of impairment and performed an impairment evaluation of Deepwater’s goodwill and recoverability test for the long-lived asset group. Based on the results of these tests, in the second

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quarter of 2010, management concluded no impairment was necessary. In the third quarter of 2010, these downward trends continued and management, after determining that there was an indicator of impairment, performed another impairment evaluation of Deepwater’s goodwill and recoverability test of the long-lived asset group. The results in the third quarter indicated no impairment was necessary for the asset group, but the goodwill associated with the reporting unit was deemed to be impaired and the $18 million goodwill balance was written off during the quarter ended September 30, 2010.

In the fourth quarter of 2010, further adverse trends in energy and petcoke pricing curves were observed in management’s review of external market analyses. The most significant impact on the forecasted energy prices reviewed by management in November 2010 related to the general external market consensus that Federal CO₂ cap and trade legislation was less likely, resulting in a drop in long-term energy price projections. At that time, Deepwater’s revised forecasts indicated that Deepwater would have operating losses which would extend beyond 2020 and negative cash flows through 2019. Management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was no longer recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. In determining the fair value of the asset group, all three valuation approaches described by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered most appropriate. On that basis, the carrying value of the asset group was determined to be impaired and $79 million of impairment expense was recognized in the fourth quarter of 2010.

Asset impairment expense for the year 2009 was $20 million. In 2009, the Company recognized a pre-tax long-lived asset impairment charge of $11 million related to the Company’s Piabanha hydro project in Brazil. The Company determined that the carrying value exceeded the future discounted cash flows and abandoned the project.

Asset impairment expense for the year 2008 was $175 million. In the fourth quarter of 2008, and in response to the financial market crisis, the Company reviewed and prioritized projects in the development pipeline. From this review, the Company determined that the carrying value exceeded the future discounted cash flows for certain projects. As a result, the Company recorded an impairment charge of $75 million ($34 million, net of noncontrolling interests and income taxes) related to two liquefied natural gas projects in North America and a non-power development project at one of our facilities in North America. During 2008, the Company recognized additional impairment charges of $36 million related to long-lived assets at Uruguaiana. The impairment was triggered by a combination of gas curtailments and increases in the spot market price of energy in 2007 that continued in 2008. Following an initial impairment charge in the fourth quarter of 2007, further charges were incurred in 2008 due to fixed asset purchase agreements in place. During the first half of 2008, the Company withdrew from projects in South Africa and Israel which resulted in impairment charges of $36 million. The Company also recognized an impairment of $18 million related to the shutdown of the Hefei plant in China.

Gain on sale of investments

There was no gain on sale of investments in 2010.

Gain on sale of investments of $131 million in 2009 consisted primarily of $98 million recognized in May 2009 related to the termination of the management agreement between the Company and Kazakhmys PLC for Ekibastuz and Maikuben, a gain of $14 million from the sale of the remaining assets associated with the shutdown of the Hefei plant in China and $13 million from the reversal of a contingent liability related to the Kazakhstan sale in 2008.

Gain on sale of investments of $909 million in 2008 consisted primarily of the sale in May 2008 of two wholly owned subsidiaries in Kazakhstan, Ekibastuz and Maikuben for a net gain of $905 million.

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Loss on sale of subsidiary stock

There was no loss on sale of subsidiary stock in 2010 or 2009.

Loss on sale of subsidiary stock of $31 million in 2008 was the result of sales of AES Gener shares made by our wholly owned subsidiary Cachagua. In November 2008, Cachagua sold 9.6% of its ownership in Gener to a third party reducing its ownership in Gener to 70.6%.

Foreign currency transaction gains (losses) on net monetary position

The following table summarizes the gains (losses) on the Company’s net monetary position from foreign currency transaction activities:

	Years Ended December 31,
	2010			2009			2008
	(in millions)
AES Corporation	$	(50	)	$	13		$	38
Chile		8			65			(96	)
Philippines		8			15			(57	)
Brazil		(6	)		(9	)		(44	)
Argentina		12			(10	)		(28	)
Kazakhstan		1			(24	)		14
Colombia		(4	)		(11	)		5
Other		(2	)		(5	)		(15	)
Total(1)	$	(33	)	$	34		$	(183	)

⁽¹⁾  Includes (losses) gains of $(10) million, $(39) million and $10 million on foreign currency derivative contracts for the years ended December 31, 2010, 2009 and 2008, respectively.

The Company recognized foreign currency transaction losses of $33 million for the year ended December 31, 2010. These losses consisted primarily of losses at The AES Corporation partially offset by gains in Argentina.

• Losses of $50 million at The AES Corporation were primarily due to the devaluation of notes receivable resulting from the weakening of the Euro and British Pound, and losses on foreign exchange swaps and options, partially offset by gains on cash balances and debt denominated in British Pounds.

• Gains of $12 million in Argentina were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses due to the devaluation of the Argentine Peso by 5%, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt.

The Company recognized foreign currency transaction gains of $34 million for the year ended December 31, 2009. These gains consisted primarily of gains in Chile, the Philippines and at The AES Corporation partially offset by losses in Kazakhstan, Colombia, Argentina and Brazil.

• Gains of $65 million in Chile were primarily due to the appreciation of the Chilean Peso of 20% resulting in gains at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Peso, mainly cash and accounts receivables. This gain was partially offset by $14 million in losses on foreign currency derivatives.

• Gains of $15 million in the Philippines were primarily due to the appreciation of the Philippine Peso of 3%, resulting in gains at Masinloc (a Philippine Peso functional currency subsidiary) on the remeasurement of U.S. Dollar denominated debt.

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• Gains of $13 million at The AES Corporation were primarily due to the settlement of the senior unsecured credit facility and the revaluation of notes receivable denominated in the Euro, partially offset by losses on debt denominated in British Pounds.

• Losses of $24 million in Kazakhstan were primarily due to net foreign currency transaction losses of $12 million related to energy sales denominated and fixed in the U.S. Dollar and $12 million of foreign currency transaction losses on debt and other liabilities denominated in currencies other than the Kazakh Tenge.

• Losses of $11 million in Colombia were primarily due to the appreciation of the Colombian Peso of 9%, resulting in losses at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso denominated debt and losses on foreign currency derivatives.

• Losses of $10 million in Argentina were primarily due to the devaluation of the Argentine Peso of 10% in 2009, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt, partially offset by derivative gains.

• Losses of $9 million in Brazil were primarily due to energy purchases made by Eletropaulo denominated in U.S. Dollar, resulting in foreign currency transaction losses of $18 million, partially offset by gains of $9 million due to the appreciation in 2009 of the Brazilian Real of 25%, resulting in gains at Sul and Uruguaiana associated with U.S. Dollar denominated liabilities.

The Company recognized foreign currency transaction losses of $183 million for the year ended December 31, 2008. These losses consisted primarily of losses in Chile, the Philippines, Brazil and Argentina partially offset by gains at The AES Corporation and in Kazakhstan.

• Losses of $96 million in Chile were primarily due to the devaluation of the Chilean Peso of 28% in 2008, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Pesos, mainly cash, accounts receivable and value added tax (“VAT”) receivables.

• Losses of $57 million in the Philippines were primarily due to remeasurement losses at Masinloc (a Philippine Peso functional currency subsidiary) on U.S. Dollar denominated debt resulting from depreciation of the Philippine Peso of 14% in 2008.

• Losses of $44 million in Brazil were primarily due to the realization of deferred exchange variance on past energy purchases made by Eletropaulo denominated in U.S. Dollar.

• Losses of $28 million in Argentina were primarily due to the devaluation of the Argentine Peso of 10% in 2008, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt.

• Gains of $38 million at The AES Corporation were primarily due to debt denominated in British Pounds and gains on foreign exchange derivatives, partially offset by losses on notes receivable denominated in the Euro.

• Gains of $14 million in Kazakhstan were primarily due to net foreign currency transaction gains of $16 million related to energy sales denominated and fixed in the U.S. Dollar, offset by $5 million of foreign currency transaction losses on external and intercompany debt denominated in other than the Kazakh Tenge functional currency.

Income taxes

Income tax expense on continuing operations increased $16 million, or 3%, to $596 million in 2010. The Company’s effective tax rates were 31% for 2010 and 25% for 2009.

The net increase in the 2010 effective tax rate was primarily due to tax expense recorded in the second quarter of 2010 relating to the CEMIG sale transaction, tax benefit recorded in 2009 upon the release of valuation allowances at certain U.S. and Brazilian subsidiaries, and $165 million of non-taxable income recorded in 2009

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at Brazil as a result of the REFIS program. These items were offset by income tax benefits related to a reversal of withholding tax liabilities at certain Chilean subsidiaries. Included in the net tax expense related to the CEMIG sale transaction is tax expense on the equity earnings associated with the reversal of the net long-term liability and tax benefit related to release of a valuation allowance against certain deferred tax assets.

Income tax expense on continuing operations decreased $139 million, or 19%, to $580 million in 2009. The Company’s effective tax rates were 25% for 2009 and 28% for 2008.

The net decrease in the 2009 effective tax rate was primarily due to tax benefit recorded in 2009 upon the release of valuation allowance at certain U.S. and Brazilian subsidiaries, $165 million of non-taxable income recorded at Brazil as a result of the REFIS program in 2009 and an increase in U.S. taxes on distributions from the Company’s primary holding company in the second quarter of 2008.

Net equity in earnings of affiliates

Net equity in earnings of affiliates increased $91 million, or 99%, to $183 million in 2010 from $92 million in 2009. This increase was primarily due to a gain recognized upon the sale of our interest in CEMIG during the second quarter of 2010, partially offset by 2009 equity in earnings of Cartagena which was accounted for as a consolidated entity in 2010 and thus reported directly within revenues and expenses.

Net equity in earnings of affiliates increased $59 million, or 179%, to $92 million in 2009 from $33 million in 2008. This increase was primarily due to a cash settlement received by Cartagena, in Spain, in June 2009 for liquidated damages received related to a construction delay from December 2005 to November 2006; increased earnings at Guacolda in Chile mainly due to lower cost of coal; increased earnings of Chigen affiliates from higher tariffs partially offset by lower volume and a valuation write-off in 2008 at an affiliate in Turkey. These increases were partially offset by decreased earnings at OPGC, in India, mainly due to lower tariff and a dividend distribution tax in March 2009 and increased expenses for an equipment overhaul at Elsta in the Netherlands.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests decreased $93 million, or 8%, to $1.0 billion in 2010 from $1.1 billion in 2009. This decrease was primarily due to decreased earnings at Eletropaulo as a result of the absence of legal settlement income present in 2009, a loss on legal settlement at Gener and reduced revenues due to decreased coal prices along with higher electricity purchases at Itabo. These decreases were partially offset by the appreciation of the Brazilian Real.

Income from continuing operations attributable to noncontrolling interests increased $340 million, or 45%, to $1.1 billion in 2009 from $0.8 billion in 2008. This increase was primarily due to increases in gross margin and other income, lower interest expense and a decrease in impairments in 2009 at our Brazilian businesses, and increases in gross margin and foreign currency transaction gains at our businesses in Chile. In addition, in the fourth quarter of 2009, income from continuing operations attributable to noncontrolling interests increased $44 million at certain of our wind generation businesses as a result of a charge related to the potential future taxes that could be deemed due in the calculation of the hypothetical liquidation value of certain of our wind tax equity partnerships.

Discontinued operations

As further discussed in Note 21—Discontinued Operations and Held-for-Sale Businesses to the Consolidated Financial Statements included in Item 8 of this Form 8-K, Discontinued Operations includes the results of the following generation businesses: Eastern Energy including Cayuga, Greenidge, Somerset and Westover, in New York (held for sale in March 2011); Borsod and Tiszapalkonya, in Hungary (held for sale in March 2011); Ras Laffan, in Qatar (sold in October 2010); Barka, in Oman, (sold in August 2010); Lal Pir and Pak Gen, in Pakistan, (sold in June 2010); and Jiaozuo, in China, (sold in December 2008). Prior periods have been restated to reflect these businesses within Discontinued Operations for all periods presented.

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In 2010, loss from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $542 million and reflected the operations of our 100% stake in Eastern Energy, four coal-fired power plants in New York, our 100% stake in Borsod, a biomass and coal-fired facility in Hungary, our 100% stake in Tiszapalkonya, a multi-fuel facility in Hungary, our 55% stake in Ras Laffan, a combined cycle gas facility and water desalination plant in Qatar, our 35% stake in Barka, a combined cycle gas facility and water desalination plant in Oman and our 55% stake in Lal Pir and Pak Gen, two oil-fired facilities in Pakistan. The sale of Lal Pir and Pak Gen closed in June 2010, resulting in additional impairment expense and a loss on the sale in 2010 of $14 million, net of tax and noncontrolling interests. The Barka plant was sold in August 2010, resulting in a gain on sale of $63 million, net of tax and noncontrolling interests. The sale of Ras Laffan closed in October 2010, resulting in a gain on sale of $6 million, net of tax.

AEE operates four coal-fired power plants: Cayuga, Greenidge, Somerset and Westover, representing generation capacity of 1,169 MW in the western New York power market. During 2010, the power prices in the New York power market trended downward, similar to North America natural gas prices. The New York Independent System Operator (“NYISO”) continues to move forward with the potential addition of a new capacity zone, which is expected to put further downward pressure on the capacity prices paid to the AEE facilities. In November 2010, legislation was proposed in the state of New Jersey for the addition of state subsidized capacity additions serving to lower PJM capacity price expectations. Similar changes to capacity pricing may be made in the future in New York. Continued pressure on energy prices, driven by falling natural gas prices and state actions, indicate that capacity prices are unlikely to reach levels significantly in excess of those achieved historically. Accordingly, management’s view of long-term capacity markets in western New York was revised downward. In December 2010, management revised its cash flow forecasts based on these developments and forecasted continuing negative operating cash flow and losses through 2034. The forecasted energy prices are such that a hedge strategy significantly beyond those in place at December 31, 2010 would not be economical. Additionally, on November 15, 2010, Standard & Poor’s downgraded the bond rating of AEE from BB to B+. Collectively, in the fourth quarter of 2010, these events were considered an impairment indicator for the AES New York asset group, of which AEE is the most significant component and necessitated a recoverability test of the asset group.

The long-lived asset group subject to the impairment evaluation was determined to include all of the generating plants of AEE. This determination was based on the assessment of the plants’ inability to generate independent cash flow. When the recoverability test of the asset group was performed, management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was not recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. While there were numerous assumptions that impact the fair value, potential state actions that impact capacity pricing and forward energy prices were the most significant.

In determining the fair value of the asset group, the three valuation approaches prescribed by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered the most appropriate and resulted in a zero fair value. Any salvage value of the asset group is expected to be offset by environmental and other remediation costs. Accordingly, the long-lived asset group was considered fully impaired and $827 million of impairment expense was recognized in the fourth quarter of 2010.

In 2009, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $35 million and reflected the operations of Eastern Energy, Borsod and Tiszapalkonya, Ras Laffan, Barka, Lal Pir and Pak Gen. Loss on disposal of discontinued businesses, net of tax and loss attributable to noncontrolling interests was $105 million and represented the difference between the net book value of the Company’s interests in its Pakistan businesses and their estimated fair value.

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In 2008, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $141 million and reflected the operations of Eastern Energy, Borsod and Tiszapalkonya, Ras Laffan, Barka, Lal Pir, Pak Gen and Jiaozuo, a coal-fired generation facility in China sold in December 2008. The Company received $73 million for its 70% interest in the business. The net gain on the disposition was $7 million.

Critical Accounting Estimates

The Consolidated Financial Statements of AES are prepared in conformity with GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. AES’ significant accounting policies are described in Note 1—General and Summary of Significant Accounting Policies to the Consolidated Financial Statements included in Item 8 of this Form 8-K.

An accounting estimate is considered critical if:

• the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made;

• different estimates reasonably could have been used; or

• the impact of the estimates and assumptions on financial condition or operating performance is material.

Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could materially differ from the original estimates, requiring adjustments to these balances in future periods. Management has discussed these critical accounting policies with the Audit Committee, as appropriate. Listed below are the Company’s most significant critical accounting estimates and assumptions used in the preparation of the Consolidated Financial Statements.

Income Tax Reserves

We are subject to income taxes in both the United States and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certain of its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the tax jurisdictions when determining the adequacy of the provision for income taxes. Accounting guidance for uncertainty in income taxes prescribes a more-likely-than-not recognition threshold. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amounts of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may exceed current reserves in amounts that could be material.

On December 17, 2010, President Obama signed into law the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010 (“the Act”). The Act includes several provisions which provide for tax relief for businesses by extending certain tax benefits and credits, including the Subpart F exception for active financing income and the Controlled Foreign Corporation look-through provisions of Subpart F. This legislation resulted in a benefit for the Company’s 2010 provision for income taxes; however, there can be no assurances that the benefits of this legislation will extend beyond 2011, when it is currently scheduled to expire.

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Impairments

Our accounting policies on goodwill and long-lived assets are described in detail in Note 1—General and Summary of Significant Accounting Policies, Goodwill and Other Intangibles and Long-lived Assets, respectively, included in Item 8 of this Form 8-K. Goodwill is tested annually for impairment at the reporting unit level on October 1. In addition, goodwill is tested for impairment whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit has been reduced below its carrying amount. A long-lived asset (asset group) will be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, i.e., the future undiscounted cash flows associated with the asset are less than its carrying amount. In the event that the carrying amount of the long-lived asset (asset group) is not recoverable, an impairment evaluation is performed, in which the fair value of the asset is estimated and compared to the carrying amount. Examples of indicators that would result in an impairment test for goodwill and a recoverability test for long-lived assets include, but are not limited to, a significant adverse change in the business climate, legislation changes or a change in the extent or manner in which a long-lived asset is being used or in its physical condition. Throughout the impairment evaluation process, management makes considerable judgments; however, the fair value determination is typically the most judgmental part of an impairment evaluation.

The Company determines the fair value of a reporting unit or a long-lived asset (asset group) by applying the approaches prescribed under the fair value measurement accounting framework. Generally, the market approach and income approach are most relevant in the fair value measurement of our reporting units and long-lived assets; however, due to the lack of available relevant observable market information in many circumstances, the Company often relies on the income approach. The Company may engage an independent valuation firm to assist management with the valuation. The decision to engage an independent valuation firm considers all relevant facts and circumstances, including a cost/benefit analysis and the Company’s internal valuation knowledge of the long-lived asset (asset group) or business. The Company develops the underlying assumptions consistent with its internal budgets and forecasts for such valuations. Additionally, the Company uses an internal discounted cash flow valuation model (the “DCF model”), based on the principles of present value techniques, to estimate the fair value of its reporting units or long-lived assets under the income approach. The DCF model estimates fair value by discounting our internal budgets and cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.

Management applies considerable judgment in selecting several input assumptions during the development of our internal budgets and cash flow forecasts. Examples of the input assumptions that our budgets and forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical trends which often do not recur. The input assumptions most significant to our budgets and cash flows are based on expectations of macroeconomic factors which have been volatile recently. It is not uncommon that different market data sources have different views of the macroeconomic factors expectations and related assumptions. As a result, macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations these ranges become wide and the use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.

A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg, Capital IQ, etc.). The Company selects and uses a set of publicly traded companies from the relevant industry to estimate the discount rate inputs. Management applies judgment in the selection of such companies based on its view of the most likely market participants. It is reasonably possible that the selection of a different set of likely market participants could produce different input assumptions and result in the use of a different discount rate.

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Fair value of a reporting unit or a long-lived asset (asset group) is sensitive to both input assumptions to our budgets and cash flow forecasts and the discount rate. Further, estimates of long-term growth and terminal value are often critical to the fair value determination. As part of the impairment evaluation process, management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap between fair value and carrying amount decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment, which could be material. Our impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.

Further discussion of the impairment charges recognized by the Company can be found within Management’s Discussion and Analysis, Consolidated Results of Operations—Goodwill Impairment and Asset Impairment Expense and Note 19—Impairment Expense and Note 8— Goodwill and Other Intangible Assets to the Consolidated Financial Statements included in Item 8 of this Form 8-K.

Fair Value

Fair Value of Financial Instruments

A significant number of the Company’s financial instruments are carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period. The Company makes estimates regarding the valuation of assets and liabilities measured at fair value in preparing the Consolidated Financial Statements. These assets and liabilities include short and long-term investments in debt and equity securities, included in the balance sheet line items “Short-term investments” and “Other assets (Noncurrent)”, derivative assets, included in “Other current assets” and “Other assets (Noncurrent)” and derivative liabilities, included in “Accrued and other liabilities (current)” and “Other long-term liabilities”. The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices are not available, valuation models are applied to estimate the fair value using the available observable inputs. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. Investments are generally fair valued based on quoted market prices or other observable market data such as interest rate indices. The Company’s investments are primarily certificates of deposit, government debt securities and money market funds. Derivatives are valued using observable data as inputs into internal valuation models. The Company’s derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 4—Fair Value in Item 8 of this Form 8-K.

Accounting for Derivative Instruments and Hedging Activities

We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity and foreign currency exposures. We do not enter into derivative transactions for trading purposes.

In accordance with the accounting standards for derivatives and hedging, we recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value except where derivatives qualify and are designated as “normal purchase/normal sale” transactions. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments are recognized in the same category as generated by the underlying asset or liability.

The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure

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being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging.

The fair value measurement accounting standard provides additional guidance on the definition of fair value and defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The fair value measurement standard requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Due to the nature of the Company’s interest rate swaps, which are typically associated with non-recourse debt, credit risk for AES is evaluated at the subsidiary level rather than at the Parent Company level. Nonperformance risk on the Company’s derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally developed valuation models that utilize observable market inputs.

As a result of uncertainty, complexity and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings (both ours and our counterparty’s) and exchange rates.

The fair value of our derivative portfolio is generally determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g., Bloomberg and Platt’s). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine a financial instrument’s fair value. In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. Additionally, in the absence of quoted prices, we may rely on “indicative pricing” quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps. These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered observable market data. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.

Fair Value of Nonfinancial Assets and Liabilities

The Company adopted the fair value measurement accounting guidance for nonfinancial assets and liabilities effective January 1, 2009. The most significant of these estimates surround the fair value measurement of long-lived tangible and intangible assets when tested for impairment upon a triggering event or during the annual impairment evaluation for indefinite-lived intangible assets, including goodwill. These estimates include making assumptions regarding useful life, the impact of economic obsolescence and expected future cash flows. Additional factors are discussed above in the Impairments section.

Fair Value Hierarchy

The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices are not available, valuation models are applied to estimate the fair value using the available observable inputs. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

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To increase consistency and enhance disclosure of the fair value of financial instruments, the fair value measurement standard creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. A financial instrument’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. For more information regarding the fair value hierarchy, see Note 1—General and Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this Form 8-K.

Regulatory Assets and Liabilities

The Company accounts for certain of its regulated operations in accordance with the regulatory accounting standards. As a result, AES recognizes assets and liabilities that result from the regulated ratemaking process that would not be recognized under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery through customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or included in future rate initiatives. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.

New Accounting Pronouncements Adopted

Effective January 1, 2010, we adopted new accounting provisions related to the following topics as a result of new accounting guidance issued by the Financial Accounting Standards Board (“FASB”). The financial statement impact of these new accounting pronouncements is included in Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 8-K.

• Consolidations, Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“VIEs”). The new accounting guidance on the consolidation of VIEs requires an entity to qualitatively, rather than quantitatively, assess the determination of the primary beneficiary of a VIE. This determination is based on whether the entity has the power to direct the activities that most significantly impact the economic performance of the VIE and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Other key changes include: a requirement for the ongoing reconsideration of the primary beneficiary, the criteria for determining whether service provider or decision maker contracts are variable interests, the consideration of kick-out and removal rights in determining whether an entity is a VIE, the types of events that trigger the reassessment of whether an entity is a VIE and the expansion of the disclosures previously required. The adoption of the new accounting guidance on the consolidation of VIEs resulted in the deconsolidation of certain immaterial VIEs previously consolidated. Additionally, assets, liabilities and operating results of two of the Company’s VIEs, previously accounted for under the equity method of accounting, were required to be consolidated. Cartagena, a 71% owned generation business in Spain, and Cili, a 51% owned generation business in China, were consolidated under the new guidance.

• Accounting for Transfers of Financial Assets. The new accounting guidance on transfers of financial assets, among other things: removes the concept of a qualifying special purpose entity; introduces the concept of participating interests and specifies that in order to qualify for sale accounting a partial transfer of a financial asset or a group of financial assets should meet the definition of a participating interest; clarifies that an entity should consider all arrangements made contemporaneously with or in contemplation of a transfer and requires enhanced disclosures to provide financial statement users with greater transparency about transfers of financial assets and a transferor’s continuing involvement with transfers of financial assets accounted for as sales. Upon adoption on January 1, 2010, the Company recognized $40 million as accounts receivable and as an associated secured borrowing on its

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Consolidated Balance Sheet; both of which have since increased to $50 million as of December 31, 2010, as additional interests in receivables have been sold. While securitizing these accounts receivable through IPL Funding, a special purpose entity, IPL, the Company’s integrated utility in Indianapolis, had previously recognized the transaction as a sale, but had not recognized the accounts receivable and secured borrowing on its balance sheet.

Accounting Pronouncements Issued But Not Yet Effective

The following accounting standards have been issued, but as of December 31, 2010 are not yet effective for and have not been adopted by AES.

Accounting Standards Update (“ASU”) No. 2010-28, Intangibles—Goodwill and Other (Topic 350), When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts

In December 2010, the FASB issued ASU No. 2010-28, which amends the accounting guidance related to goodwill. The amendments in ASU No. 2010-28 modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists, eliminating an entity’s ability to assert that a reporting unit is not required to perform Step 2 because the carrying amount of the reporting unit is zero or negative despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. ASU No. 2010-28 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010, or January 1, 2011 for AES. Early adoption is prohibited. The adoption is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

Capital Resources and Liquidity

Overview. In November 2009, the Company announced a binding stock purchase agreement with CIC, to sell 125.5 million shares of AES stock to CIC, representing a 15% ownership stake in the Company. The transaction closed in March 2010 and generated $1.58 billion of new equity to fund future growth opportunities. During 2010, the Company redeemed $690 million aggregate principal of its outstanding 8.75% Second Priority Senior Secured Notes due 2013. The Notes were redeemed in May and October 2010 at a redemption price equal to 101.458% of the principal amount redeemed.

As of December 31, 2010, the Company had unrestricted cash and cash equivalents of $2.6 billion, of which approximately $1.1 billion is held at the Parent Company and qualified holding companies, and short term investments of $1.7 billion. In addition, we had restricted cash and debt service reserves of $1.2 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $14.9 billion and $4.6 billion, respectively. Of the approximately $2.6 billion of our short-term non-recourse debt, $1.2 billion is presented as current because it is due in the next twelve months and $1.4 billion relates to defaulted debt. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $463 million of our recourse debt matures within the next twelve months, which we expect to repay using cash on hand at the Parent Company or through net cash provided by operating activities. See further discussion of Parent Company Liquidity below.

The Company has two types of debt reported on its consolidated balance sheet: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for construction and acquisition of our electric power plants, wind projects and distribution facilities at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. Recourse debt is direct borrowings by the Parent Company and is used to fund development,

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construction or acquisitions, including funding for equity investments or to provide loans to the Parent Company’s subsidiaries or affiliates. This Parent Company debt is with recourse to the Parent Company and is structurally subordinated to the debt of the Parent Company’s subsidiaries or affiliates, except to the extent such subsidiaries or affiliates guarantee the Parent Company’s debt.

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks. For more information on our long-term debt, see Note 10—Debt of the Consolidated Financial Statements included in Item 8 of this Form 8-K.

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. While the Company believes that this represents an economic hedge, the Company is required to mark-to-market all of these interest rate swaps and other derivatives. Presently, the Parent Company’s only direct exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility. On a consolidated basis, of the Company’s $19.6 billion of total debt outstanding as of December 31, 2010, approximately $4.8 billion of non-recourse debt bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At December 31, 2010, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $415 million in aggregate (excluding investment commitments and those collateralized by letters of credit and other obligations discussed below).

As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other

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liquidity needs. At December 31, 2010, we had $85 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and business operations. These letters of credit were provided under the senior secured credit facility. During the year ended December 31, 2010, the Company paid letter of credit fees ranging from 3.19% to 3.75% per annum on the outstanding amounts.

We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. See Global Economic Conditions discussion above. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.

Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.

As of December 31, 2010, the Company had approximately $347 million of trade accounts receivable related to certain of its generation and utility businesses in Latin America classified as other long-term assets. These consist primarily of trade accounts receivable that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond December 31, 2011, or one year past the balance sheet date. The Company is actively collecting these receivables and does not expect any significant collection issues. Additionally, the current portion of these trade accounts receivable was $101 million at December 31, 2010.

Capital Expenditures

The Company spent $2.3 billion, $2.5 billion and $2.9 billion on capital expenditures in 2010, 2009 and 2008, respectively. A significant majority of these costs were funded with non-recourse debt consistent with our financial strategy. At December 31, 2010, the Company had a total of $432 million of availability under long-term non-recourse construction credit facilities. As more fully described in Key Trends and Uncertainties above, we have taken steps to decrease the amount of new discretionary capital spending. We expect to continue funding projects that are currently in the construction phase using existing capital provided by these non-recourse credit facilities as supplemented by internally generated cash flows, Parent Company liquidity, contribution from existing or new partners and other funding sources. As a result, property, plant and equipment and long-term non-recourse debt are expected to increase over the next few years even though the rate of discretionary spending has decreased. While we believe we have the resources to continue funding the projects in construction, there can be no assurances that we will continue to fund all these existing construction efforts.

As of December 31, 2010, the Company had $66 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding $26 million of such obligations already included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2011. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

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Environmental Capital Expenditures

The Company continues to assess the possible need for capital expenditures associated with international, federal, regional and state regulation of GHG emissions from electric power generation facilities. Currently in the United States there is no Federal legislation establishing mandatory GHG emissions reduction programs (including CO₂) affecting the electric power generating facilities of the Company’s subsidiaries. There are numerous state programs regulating GHG emissions from electric power generation facilities and there is a possibility that federal GHG legislation will be enacted within the next several years. Further, the EPA has adopted regulations pertaining to GHG emissions and has announced its intention to propose new regulations for electric generating units under Section 111 of the CAA. The EPA regulations and any subsequent Federal legislation, if enacted, may place significant costs on GHG emissions from fossil fuel-fired electric power generation facilities, particularly coal-fired facilities, and in order to comply, CO₂ emitting facilities may be required to purchase additional GHG emissions allowances or offsets under cap-and-trade programs, pay a carbon tax or install new emission reduction equipment to capture or reduce the amount of GHG emitted from the facilities, in the event that reliable technology to do so is developed. The capital expenditures required to comply with any future GHG legislation or any GHG regulations could be significant and unless such costs can be passed on to customers or counterparties, such regulations could impair the profitability of some of the electric power generation facilities operated by our subsidiaries or render certain of them uneconomical to operate, either of which could have a material adverse effect on our consolidated results of operations and financial condition.

With respect to our operations outside the United States, certain of the businesses operated by the Company’s subsidiaries are subject to compliance with EU ETS and the Kyoto Protocol in certain countries and other country-specific programs to regulate GHG emissions. 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 because of, among other factors, the cost of GHG emission allowances and/or the ability of our businesses to pass the cost of purchasing such allowances on to customers or counterparties. However, in the event that such counterparties or regulatory authorities challenge our ability to pass these costs on, there can be no assurance that the Company and/or the relevant subsidiary would prevail in any such dispute. Furthermore, even if the Company and/or the relevant subsidiary does prevail, it would be subject to the cost and administrative burden associated with such dispute.

As discussed in Item 1.—Business—Regulatory Matters—Environmental and Land Use Regulations in the 2010 Form 10-K, in the United States there presently is no federal legislation establishing mandatory GHG emission reduction programs. In 2010, the Company’s subsidiaries operated businesses which had total approximate CO₂ emissions of 77.2 million metric tonnes (ownership adjusted). Approximately 40 million metric tonnes of the 77.2 million metric tonnes were emitted in the United States (both figures ownership adjusted). Approximately 11.3 million metric tonnes were emitted in United States states participating in the RGGI. We believe that legislative or regulatory actions, if enacted, may require a material increase in capital expenditures at our subsidiaries.

In the future the actual impact on our subsidiaries’ capital expenditures from any potential federal program to regulate and reduce GHG emissions, if enacted, and the state and regional programs developed or in the process of development, or any EPA regulation of GHG emissions, will depend on a number of factors, including among others, the GHG reductions required under any such legislation or regulations, the cost of emissions reduction equipment, the price and availability of offsets, the extent to which our subsidiaries would be entitled to receive GHG emission allowances without having to purchase them, the quantity of allowances which our subsidiaries would have to purchase, the price of allowances, and our subsidiaries’ ability to recover or pass-through costs incurred to comply with any legislative or regulatory requirements that are ultimately imposed and the use of market-based compliance options such as cap-and-trade programs.

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Income Taxes

We recognized tax expense of $596 million for the year ended December 31, 2010, while our cash payments for income taxes, net of refunds, totaled $698 million. The difference resulted primarily from impairment charges recognized at certain subsidiaries in the United States, for which we recognized a benefit in our domestic tax provision. As a result, global cash tax payments exceeded the consolidated tax provision.

Consolidated Cash Flows

At December 31, 2010, cash and cash equivalents increased $772 million from December 31, 2009 to $2.6 billion. The increase in cash and cash equivalents was due to $3.5 billion of cash provided by operating activities, $2.0 billion of cash used for investing activities, $706 million of cash used for financing activities and the favorable effect of foreign currency exchange rates on cash of $8 million.

At December 31, 2009, cash and cash equivalents increased $916 million from December 31, 2008 to $1.8 billion. The increase in cash and cash equivalents was due to $2.2 billion of cash provided by operating activities, $1.9 billion of cash used for investing activities, $610 million of cash provided by financing activities and the favorable effect of foreign currency exchange rates on cash of $22 million.

	2010			2009		2008		$ Change
								2010 vs. 2009			2009 vs. 2008
	(in millions)
Net cash provided by operating activities	$	3,510		$	2,201	$	2,165	$	1,309		$	36
Net cash used in investing activities	$	2,040		$	1,917	$	3,581	$	123		$	(1,664	)
Net cash (used in) provided by financing activities	$	(706	)	$	610	$	362	$	(1,316	)	$	248

Operating Activities

Net cash provided by operating activities increased $1.3 billion, or 59%, to $3.5 billion during 2010 compared to 2009. This net increase was primarily due to the following:

• an increase of $837 million at our Latin American Utilities businesses due to increased tax payments in 2009 associated with a tax amnesty program of $326 million, higher working capital requirements during 2009 related to payments on the settlement of swap agreements of $65 million and in 2010, a $50 million decrease in employer contributions to pension plans and lower payments for contingencies;

• an increase of $215 million at our Latin American Generation businesses due to the higher gross margin in 2010 combined with improved working capital mainly as a result of higher collections of value added taxes and accounts receivable;

• an increase of $99 million at Masinloc in the Philippines due to higher gross margin; and

• an increase of $58 million as a result of our consolidation of Cartagena in 2010 and the acquisition of Ballylumford in Northern Ireland.

These increases were partially offset by:

• a decrease of $184 million in operating cash flows from discontinued operations compared to 2009. In 2010, net cash provided by operating activities of discontinued and held for sale businesses was $93 million, including $33 million from businesses sold in 2010.

In 2010 the increase in net cash provided by operating activities at our Latin American Utilities businesses included several items such as the tax amnesty program and settlement of swap agreements, as described above, that are not expected to recur. In addition, 2010 net cash provided by operating activities benefited from the one time cash savings related to the utilization of tax credits received as a result of the REFIS program. As such, the Company does not expect the trend of an increase in net cash provided by operating activities realized in 2010 to continue in 2011.

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Investing Activities

Net cash used for investing activities increased $123 million, or 6%, to $2.0 billion during 2010 compared to 2009. This increase was largely attributable to the following:

• an increase in the purchase of short-term investments of $1.6 billion during 2010 compared to 2009 primarily due to the investment of cash proceeds from debt issuances at our Brazilian subsidiaries and the purchase of time deposits at Gener in 2010. Purchases were offset by an increase in sales of short-term investments of $1.3 billion mainly due to the use of proceeds from investments for the repayment of debt instruments and dividend distributions at our Brazilian subsidiaries and the sales of time deposits at Gener;

• an increase of $406 million in funding requirements for restricted cash balances during 2010 compared to 2009. During 2010, $104 million of funds were transferred to restricted cash balances while during 2009, $302 million was transferred out of restricted cash;

• an increase of $254 million for acquisitions, net of cash acquired, primarily due to $138 million related to the acquisition of Ballylumford in Northern Ireland, $65 million related to the purchase of three wind development pipelines in the U.K. and Poland, $35 million related to the acquisition of JHRH, and $11 million related to the buyout of noncontrolling interests at Changuinola;

• an increase of $241 million in debt service reserves during 2010 compared to 2009. During 2010, $56 million of funds were transferred to debt service reserves while during 2009, $185 million was utilized for debt maturities; partially offset by

• an increase of $593 million in proceeds from the sale of businesses primarily due to proceeds of $226 million related to the sale in October 2010 of Ras Laffan in Qatar, $170 million related to the sale in August 2010 of Barka in Oman, the final settlement proceeds of $99 million received in January 2010 from the termination of a management agreement with Kazakhmys in Kazakhstan related to Ekibastuz and Maikuben which were sold in May 2008, and the net proceeds from the sale of Lal Pir and Pak Gen in Pakistan in June 2010 of $100 million;

• a decrease of $210 million in capital expenditures to $2.3 billion primarily due to a decrease in expenditures of $298 million at Gener and $250 million at our Europe Wind generation projects. These decreases were partially offset by a net increase in capital expenditures of $261 million at our Brazilian subsidiaries, $66 million at Maritza in Bulgaria, and $16 million at our U.S. Wind generation projects; and

• an increase of $132 million in proceeds related to the repayment of the loan receivable from a wind development project in Brazil. There were no proceeds from loan repayments during 2009.

Financing Activities

Net cash used for financing activities increased $1,316 million, or 216%, to $706 million during 2010 compared to net cash provided by financing activities of $610 million during 2009. This increase was primarily attributable to the following:

• a $1.7 billion increase in repayments of recourse and non-recourse debt, predominately due to increases of $760 million of recourse debt repayments at the Parent Company, $706 million at our Brazilian businesses, $279 million at our businesses in the Dominican Republic, $55 million at Masinloc in the Philippines, $44 million at New York, $40 million at our European wind businesses, $31 million at Chigen and $30 million at Cartagena, partially offset by decreases of $132 million at IPALCO and $115 at Armenia Mountain;

• a $560 million decrease in proceeds from issuances of recourse and non-recourse debt primarily due to decreases of $503 million of recourse debt at the Parent Company, $286 million at Gener, $209 million at Armenia Mountain, $208 million at our European wind businesses, $123 million at Sonel and $122 million at IPALCO, partially offset by increases of $604 million at our Brazilian businesses and $294 million at our businesses in the Dominican Republic;

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• a $399 million increase in distributions to noncontrolling interests, primarily due to $245 million at our Brazilian businesses, $84 million related to distributions in connection with the sale of discontinued operations and $69 million at Armenia Mountain;

• a $190 million decrease in contributions from noncontrolling interests primarily due to a reduction of $117 million at Armenia Mountain and $71 million at Gener; and

• a $99 million acquisition of treasury stock.

These decreases were partially offset by:

• a $1.6 billion issuance of common stock net of transaction costs to CIC; and

• a $67 million increase in net borrowings under revolving credit facilities primarily due to decreased repayments attributable to discontinued operations sold in 2010.

Contractual Obligations

A summary of our contractual obligations, commitments and other liabilities as of December 31, 2010 is presented in the table below, which excludes any businesses classified as discontinued operations or held-for-sale (in millions):

Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		5 years and more		Other		Footnote Reference(9)
Debt Obligations(1)	$	19,471	$	3,016	$	1,568	$	3,936	$	10,951	$	—		10
Interest Payments on Long-Term Debt(2)		9,395		1,342		2,500		2,028		3,525		—		n/a
Capital Lease Obligations(3)		206		17		26		21		142		—		11
Operating Lease Obligations(4)		918		56		111		104		647		—		11
Electricity Obligations(5)		52,160		3,055		6,118		5,211		37,776		—		11
Fuel Obligations(6)		8,804		1,530		1,877		1,006		4,391		—		11
Other Purchase Obligations(7)		21,040		1,628		2,603		2,752		14,057		—		11
Other Long-term Liabilities Reflected on AES’s Consolidated Balance Sheet under GAAP(8)		583		4		90		84		269		136		n/a
Total	$	112,577	$	10,648	$	14,893	$	15,142	$	71,758	$	136

⁽¹⁾  Includes recourse and non-recourse debt presented on the Consolidated Balance Sheet. Non-recourse debt borrowings are not a direct obligation of AES, the Parent Company. Recourse debt represents the direct borrowings of AES, the Parent Company. See Note 10—Debt to the Consolidated Financial Statements included in Item 8 of this Form 8-K which provides additional disclosure regarding these obligations. These amounts exclude capital lease obligations which are included in the capital lease category, see (3) below.

⁽²⁾  Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2010.

⁽³⁾  Several AES subsidiaries have leases for operating and office equipment and vehicles that are classified as capital leases within Property, Plant and Equipment. Minimum contractual obligations include $127 million of imputed interest.

⁽⁴⁾  The Company was obligated under long-term noncancelable operating leases, primarily for office rental and site leases.

⁽⁵⁾  Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties.

⁽⁶⁾  Operating subsidiaries of the Company have entered into fuel purchase contracts subject to termination only in certain limited circumstances.

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⁽⁷⁾  Amounts relate to other contractual obligations where the Company has an enforceable and legally binding agreement to purchase goods or services that specifies all significant terms, including: quantity, pricing, and approximate timing. These amounts include planned capital expenditures that are contractually obligated.

⁽⁸⁾  These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the “Other” column of the table above as the Company is not able to reasonably estimate the timing of the future payments. In addition, the amounts do not include: (1) regulatory liabilities (See Note 9—Regulatory Assets and Liabilities), (2) contingencies (See Note 12—Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 13—Benefit Plans) or (4) any taxes (See Note 20—Income Taxes) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 8-K for additional information on the items excluded. Derivatives (See Note 6—Derivative Instruments and Hedging Activities) and incentive compensation are excluded as the Company is not able to reasonably estimate the timing or amount of the future payments.

⁽⁹⁾  For further information see the note referenced below in Item 8.—Financial Statements and Supplementary Data.

Parent Company Liquidity

The following discussion of “Parent Company Liquidity” has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP, as a measure of liquidity. Cash and cash equivalents are disclosed in the Consolidated Statements of Cash Flows and the Parent Only Unconsolidated Statements of Cash Flows in Schedule I of the 2010 Form 10-K. Parent Company liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are:

• dividends and other distributions from our subsidiaries, including refinancing proceeds;

• proceeds from debt and equity financings at the Parent Company level, including availability under our credit facilities; and

• proceeds from asset sales.

Cash requirements at the Parent Company level are primarily to fund:

• interest;

• principal repayments of debt;

• acquisitions;

• construction commitments;

• other equity commitments;

• equity repurchases;

• taxes; and

• Parent Company overhead and development costs.

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The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents” at December 31, 2010 and 2009 as follows:

Parent Company Liquidity	2010			2009
	(in millions)
Cash and cash equivalents	$	2,552		$	1,780
Less: Cash and cash equivalents at subsidiaries		(1,430	)		(1,103	)
Parent and qualified holding companies cash and cash equivalents		1,122			677
Commitments under Parent credit facilities		800			785
Less: Borrowings and letters of credit under the credit facilities		(85	)		(204	)
Borrowings available under Parent credit facilities		715			581
Total Parent Company Liquidity	$	1,837		$	1,258

Recourse Debt Transactions:

During 2010, the Company redeemed $690 million aggregate principal of its 8.75% Second Priority Senior Secured Notes due 2013 (“the 2013 Notes”). The 2013 Notes were redeemed at a redemption price equal to 101.458% of the principal amount redeemed. The Company recognized a pre-tax loss on the redemption of the 2013 Notes of $15 million for the year ended December 31, 2010, which is included in “Other expense” in the accompanying Consolidated Statement of Operations.

On July 29, 2010, the Company entered into an Amendment No. 2 (the “Amendment No. 2”) to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008, among the Company, various subsidiary guarantors and various lending institutions (the “Existing Credit Agreement”) that amends and restates the Existing Credit Agreement (as so amended and restated by the Amendment No. 2, the “Fifth Amended and Restated Credit Agreement”). The Fifth Amended and Restated Credit Agreement adjusted the terms and conditions of the Existing Credit Agreement, including the following changes:

• the aggregate commitment for the revolving credit loan facility was increased to $800 million;

• the final maturity date of the revolving credit loan facility was extended to January 29, 2015;

• there were changes to the facility fee applicable to the revolving credit loan facility;

• the interest rate margin applicable to the revolving credit loan facility is now based on the credit rating assigned to the loans under the credit agreement, with pricing currently at LIBOR + 3.00%;

• there is an undrawn fee of 0.625% per annum;

• the Company may incur a combination of additional term loan and revolver commitments so long as total term loan and revolver commitments (including those currently outstanding) do not exceed $1.4 billion; and

• the negative pledge (i.e., a cap on first lien debt) of $3.0 billion.

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Recourse Debt:

Our recourse debt at year-end was approximately $4.6 billion and $5.5 billion in 2010 and 2009, respectively. The following table sets forth our Parent Company contingent contractual obligations as of December 31, 2010:

Contingent contractual obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	415		24	<$	1 - $62
Letters of credit under the senior secured credit facility		85		30	<$	1 - $26
Total	$	500		54

As of December 31, 2010, the Company had $66 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding $26 million of such obligations already included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2011. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

We have a diverse portfolio of performance related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, sponsor support and liquidated damages under power sales agreements for projects in development, in operation and under construction. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2011 or beyond, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Conditions), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A.—Risk Factors, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.” of the 2010 Form 10-K.

Various debt instruments at the Parent Company level, including our senior secured credit facility, contain certain restrictive covenants. The covenants provide for, among other items:

• limitations on other indebtedness, liens, investments and guarantees;

• limitations on dividends, stock repurchases and other equity transactions;

• restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements;

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• maintenance of certain financial ratios; and

• financial and other reporting requirements.

As of December 31, 2010, we were in compliance with these covenants at the Parent Company level.

Non-Recourse Debt:

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

• reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;

• triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;

• causing us to record a loss in the event the lender forecloses on the assets; and

• triggering defaults in our outstanding debt at the Parent Company.

For example, our senior secured credit facilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying Consolidated Balance Sheets amounts to $2.6 billion. The portion of current debt related to such defaults was $1.4 billion at December 31, 2010, all of which was non-recourse debt related to four subsidiaries—Maritza, Sonel, Kelanitissa and Aixi.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of December 31, 2010 in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.

Off-Balance Sheet Arrangements

In May 1999, our subsidiary in New York acquired six electric generating plants from New York State Electric and Gas. Concurrently, the subsidiary sold two of the plants to unrelated third parties for $666 million and simultaneously entered into a leasing arrangement with the unrelated parties. In May 2007, the subsidiary purchased 37.5% interest in a trust estate that holds the leased plants. Future minimum lease commitments under the lease agreement have been reduced by the subsidiary’s interest in the plants. We have accounted for this sale/leaseback transaction as an operating lease. We amortize the off-balance sheet lease obligation reduced by the subsidiary interest over the life of the lease, which resulted in the recognition of expense of $34 million for each of the years ended December 31, 2010, 2009 and 2008, respectively, which is classified as “income from operations of discontinued businesses” in the Consolidated Statements of Operations in Item 8 of this Form 8-K. AES is not subject to any additional liabilities or contingencies if the arrangement terminates and we believe that the dissolution of the off-balance sheet arrangement would have minimal effects on our operating cash flows.

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The terms of Eastern Energy’s credit facility include restrictive covenants such as the maintenance of certain coverage ratios. Historically, the plants have satisfied the restrictive covenants of the credit facility; however as a result of the continued pressure on energy prices and negative forecasted operating cash flow and losses previously discussed under Key Trends and Uncertainties, management does not believe that cash flow from operations, together with amounts available under existing credit facilities, will be sufficient to cover expected capital requirements over the terms of the leases. Management is exploring revenue enhancements as well as reviewing cost and debt structure for meaningful reductions that could be implemented in the future; however, in the event of a default Eastern Energy could be subject to full payment of the outstanding principal, accrued interest and termination costs under its lease arrangements and existing $200 million credit facility. In addition, the subsidiary lessor could be subject to full payment of the outstanding principal, accrued interest and make-whole premiums under its bond indenture. Also, a default by Eastern Energy or its related subsidiaries could result in the loss of AES’s ownership interest in Eastern Energy and related subsidiaries.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of The AES Corporation:

We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedules listed in the index at Item 15(a). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The AES Corporation and subsidiaries at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, in 2010 The AES Corporation and subsidiaries changed their method of accounting for the consolidation of variable interest entities with the adoption of amendments to Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 810, Consolidation, and their method of accounting for transfers and servicing of financial assets with the adoption of the amendments to FASB ASC 860, Transfers and Servicing, both effective January 1, 2010.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The AES Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

McLean, Virginia

February 25, 2011, except for the impact of matters discussed in Note 21

pertaining to discontinued operations, as to which the date is June 1, 2011

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THE AES CORPORATION

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2010 AND 2009

	2010			2009
	(in millions, except share and per share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,552		$	1,780
Restricted cash		502			339
Short-term investments		1,730			1,648
Accounts receivable, net of allowance for doubtful accounts of $307 and $289, respectively		2,316			2,078
Inventory		562			479
Receivable from affiliates		27			24
Deferred income taxes—current		306			210
Prepaid expenses		225			152
Other current assets		1,056			1,534
Current assets of discontinued and held for sale businesses		170			543
Total current assets		9,446			8,787
NONCURRENT ASSETS
Property, Plant and Equipment:
Land		1,126			1,100
Electric generation, distribution assets and other		28,172			25,972
Accumulated depreciation		(9,145	)		(8,576	)
Construction in progress		4,459			4,593
Property, plant and equipment, net		24,612			23,089
Other Assets:
Deferred financing costs, net of accumulated amortization of $287 and $286, respectively		375			376
Investments in and advances to affiliates		1,320			1,157
Debt service reserves and other deposits		653			557
Goodwill		1,271			1,299
Other intangible assets, net of accumulated amortization of $157 and $140, respectively		511			333
Deferred income taxes—noncurrent		646			586
Other		1,589			1,523
Noncurrent assets of discontinued and held for sale businesses		88			1,828
Total other assets		6,453			7,659
TOTAL ASSETS	$	40,511		$	39,535
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,053		$	1,826
Accrued interest		257			260
Accrued and other liabilities		2,662			2,296
Non-recourse debt—current, including $1,150 related to variable interest entities at December 31, 2010		2,567			1,707
Recourse debt—current		463			214
Current liabilities of discontinued and held for sale businesses		63			318
Total current liabilities		8,065			6,621
LONG-TERM LIABILITIES
Non-recourse debt—noncurrent, including $2,199 related to variable interest entities at December 31, 2010		12,372			12,121
Recourse debt—noncurrent		4,149			5,301
Deferred income taxes—noncurrent		895			1,090
Pension and other post-retirement liabilities		1,512			1,317
Other long-term liabilities		2,814			3,095
Long-term liabilities of discontinued and held for sale businesses		231			1,050
Total long-term liabilities		21,973			23,974
Contingencies and Commitments (see Notes 12 and 11)
Cumulative preferred stock of subsidiary		60			60
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 804,894,313 issued and 787,607,240 outstanding at December 31, 2010 and 677,214,493 issued and 667,679,913 outstanding at December 31, 2009)		8			7
Additional paid-in capital		8,444			6,868
Retained earnings		620			650
Accumulated other comprehensive loss		(2,383	)		(2,724	)
Treasury stock, at cost (17,287,073 and 9,534,580 shares at December 31, 2010 and 2009, respectively)		(216	)		(126	)
Total The AES Corporation stockholders’ equity		6,473			4,675
NONCONTROLLING INTERESTS		3,940			4,205
Total equity		10,413			8,880
TOTAL LIABILITIES AND EQUITY	$	40,511		$	39,535

See Accompanying Notes to these Consolidated Financial Statements

73

THE AES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008

	2010			2009			2008
	(in millions, except per share amounts)
Revenue:
Regulated	$	9,145		$	7,816		$	7,768
Non-Regulated		7,036			5,624			6,740
Total revenue		16,181			13,440			14,508
Cost of Sales:
Regulated		(6,718	)		(5,705	)		(5,564	)
Non-Regulated		(5,475	)		(4,329	)		(5,527	)
Total cost of sales		(12,193	)		(10,034	)		(11,091	)
Gross margin		3,988			3,406			3,417
General and administrative expenses		(392	)		(339	)		(369	)
Interest expense		(1,506	)		(1,462	)		(1,746	)
Interest income		410			346			515
Other expense		(238	)		(106	)		(161	)
Other income		104			460			372
Gain on sale of investments		—			131			909
Loss on sale of subsidiary stock		—			—			(31	)
Goodwill impairment		(21	)		(122	)		—
Asset impairment expense		(391	)		(20	)		(175	)
Foreign currency transaction gains (losses) on net monetary position		(33	)		34			(183	)
Other non-operating expense		(7	)		(12	)		(15	)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES		1,914			2,316			2,533
Income tax expense		(596	)		(580	)		(719	)
Net equity in earnings of affiliates		183			92			33
INCOME FROM CONTINUING OPERATIONS		1,501			1,828			1,847
Income (loss) from operations of discontinued businesses, net of income tax (benefit) expense of ($287), $22 and $59, respectively		(506	)		77			179
Gain (loss) from disposal of discontinued businesses, net of income tax expense of $132, $— and $—, respectively		64			(150	)		6
NET INCOME		1,059			1,755			2,032
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests		(1,006	)		(1,099	)		(759	)
Less: (Income) loss from discontinued operations attributable to noncontrolling interests		(44	)		2			(39	)
Total net income attributable to noncontrolling interests		(1,050	)		(1,097	)		(798	)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	9		$	658		$	1,234
BASIC EARNINGS (LOSS) PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.64		$	1.09		$	1.62
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		(0.63	)		(0.10	)		0.22
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.01		$	0.99		$	1.84
DILUTED EARNINGS (LOSS) PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.64		$	1.09		$	1.61
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		(0.63	)		(0.11	)		0.21
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.01		$	0.98		$	1.82
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	495		$	729		$	1,088
Discontinued operations, net of tax		(486	)		(71	)		146
Net income	$	9		$	658		$	1,234

See Accompanying Notes to these Consolidated Financial Statements

74

THE AES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008

	2010			2009			2008
	(in millions)
OPERATING ACTIVITIES:
Net income	$	1,059		$	1,755		$	2,032
Adjustments to net income:
Depreciation and amortization		1,178			1,049			1,001
(Gain) loss from sale of investments and impairment expense		1,313			57			(712	)
(Gain) loss on disposal and impairment write-down—discontinued operations		(209	)		150			(7	)
Provision for deferred taxes		(418	)		15			160
Contingencies		37			(122	)		52
(Gain) loss on the extinguishment of debt		34			(6	)		56
Undistributed gain from sale of equity method investment		(106	)		—			—
Noncontrolling interest of discontinued operations		—			—			(4	)
Other		(31	)		(99	)		127
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(98	)		62			(451	)
(Increase) decrease in inventory		10			(34	)		(83	)
(Increase) decrease in prepaid expenses and other current assets		430			137			(57	)
Increase in other assets		(248	)		(177	)		(467	)
Increase (decrease) in accounts payable and accrued liabilities		136			(308	)		260
Increase in income taxes and other income tax payables, net		166			88			226
Increase (decrease) in other liabilities		257			(366	)		32
Net cash provided by operating activities		3,510			2,201			2,165
INVESTING ACTIVITIES:
Capital expenditures		(2,310	)		(2,520	)		(2,850	)
Acquisitions—net of cash acquired		(254	)		—			(1,135	)
Proceeds from the sale of businesses		595			2			1,328
Proceeds from the sale of assets		23			17			105
Sale of short-term investments		5,786			4,526			5,150
Purchase of short-term investments		(5,795	)		(4,248	)		(5,469	)
(Increase) decrease in restricted cash		(104	)		302			(295	)
(Increase) decrease in debt service reserves and other assets		(56	)		185			(100	)
Affiliate advances and equity investments		(97	)		(155	)		(240	)
Proceeds from loan repayments		132			—			—
Loan advances		—			—			(173	)
Other investing		40			(26	)		98
Net cash used in investing activities		(2,040	)		(1,917	)		(3,581	)
FINANCING ACTIVITIES:
Issuance of common stock		1,567			—			—
Borrowings under the revolving credit facilities, net		78			11			298
Issuance of recourse debt		—			503			625
Issuance of non-recourse debt		1,940			1,997			2,158
Repayments of recourse debt		(914	)		(154	)		(1,037	)
Repayments of non-recourse debt		(1,945	)		(1,008	)		(1,260	)
Payments for deferred financing costs		(61	)		(91	)		(82	)
Distributions to noncontrolling interests		(1,245	)		(846	)		(597	)
Contributions from noncontrolling interests		—			190			410
Financed capital expenditures		(23	)		(18	)		(47	)
Purchase of treasury stock		(99	)		—			(143	)
Other financing		(4	)		26			37
Net cash (used in) provided by financing activities		(706	)		610			362
Effect of exchange rate changes on cash		8			22			(96	)
Total increase (decrease) in cash and cash equivalents		772			916			(1,150	)
Cash and cash equivalents, beginning		1,780			864			2,014
Cash and cash equivalents, ending	$	2,552		$	1,780		$	864
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	1,462		$	1,395		$	1,615
Cash payments for income taxes, net of refunds	$	698		$	484		$	465
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets acquired in acquisition of subsidiary	$	—		$	—		$	1,097
Liabilities assumed in acquisition of subsidiary	$	—		$	—		$	49
Assets acquired in noncash asset exchange	$	42		$	111		$	18
Assets disposed of in noncash asset exchange	$	—		$	—		$	4

See Accompanying Notes to these Consolidated Financial Statements

75

THE AES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008

	THE AES CORPORATION STOCKHOLDERS																			Noncontrolling Interests			Consolidated Comprehensive Income
	Common Stock				Treasury Stock						Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Loss
	Shares		Amount		Shares			Amount
	(in millions)
Balance at January 1, 2008		670.3	$	7		—		$	—		$	6,776		$	(1,241	)	$	(2,378	)	$	3,181
Net income		—		—		—			—			—			1,234			—			798		$	2,032
Foreign currency translation adjustment, net of income tax		—		—		—			—			—			—			(560	)		(492	)		(1,052	)
Change in unfunded pensions obligation, net of income tax		—		—		—			—			—			—			(49	)		(100	)		(149	)
Change in derivative fair value, including a reclassification to earnings, net of income tax		—		—		—			—			—			—			(31	)		(37	)		(68	)
Other comprehensive income																								(1,269	)
Total comprehensive income																							$	763
Capital contributions from noncontrolling interests		—		—		—			—			—			—			—			619
Dividends declared to noncontrolling interests		—		—		—			—			—			—			—			(574	)
Disposition of businesses		—		—		—			—			—			—			—			(37	)
Effect of pension measurement date change		—		—		—			—			—			(1	)		—			—
Acquisition of treasury stock		—		—		10.7			(144	)		—			—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		3.2		—		—			—			30			—			—			—
Stock compensation		—		—		—			—			26			—			—			—
Balance at December 31, 2008		673.5	$	7		10.7		$	(144	)	$	6,832		$	(8	)	$	(3,018	)	$	3,358
Net income		—		—		—			—			—			658			—			1,097		$	1,755
Change in fair value of available-for-sale securities, net of income tax		—		—		—			—			—			—			6			—			6
Foreign currency translation adjustment, net of income tax		—		—		—			—			—			—			271			471			742
Change in unfunded pensions obligation, net of income tax		—		—		—			—			—			—			(23	)		(116	)		(139	)
Change in derivative fair value, including a reclassification to earnings, net of income tax		—		—		—			—			—			—			40			33			73
Other comprehensive income																								682
Total comprehensive income																							$	2,437
Capital contributions from noncontrolling interests		—		—		—			—			—			—			—			195
Dividends declared to noncontrolling interests		—		—		—			—			—			—			—			(825	)
Disposition of businesses		—		—		—			—			—			—			—			(8	)
Issuance of treasury stock		—		—		(1.2	)		18			(20	)		—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		3.7		—		—			—			18			—			—			—
Stock compensation		—		—		—			—			38			—			—			—
Balance at December 31, 2009		677.2	$	7		9.5		$	(126	)	$	6,868		$	650		$	(2,724	)	$	4,205
Net income		—		—		—			—			—			9			—			1,050		$	1,059
Change in fair value of available-for-sale securities, net of income tax		—		—		—			—			—			—			(5	)		—			(5	)
Foreign currency translation adjustment, net of income tax		—		—		—			—			—			—			383			85			468
Change in unfunded pensions obligation, net of income tax		—		—		—			—			—			—			(22	)		(66	)		(88	)
Change in derivative fair value, including a reclassification to earnings, net of income tax		—		—		—			—			—			—			(120	)		(31	)		(151	)
Other comprehensive income																								224
Total comprehensive income																							$	1,283
Cumulative effect of consolidation of entities under variable interest entity accounting guidance		—		—		—			—			—			(47	)		(38	)		15
Cumulative effect of deconsolidation of entities under variable interest entity accounting guidance		—		—		—			—			—			1			—			—
Capital contributions from noncontrolling interests		—		—		—			—			—			—			—			35
Dividends declared to noncontrolling interests		—		—		—			—			—			—			—			(1,220	)
Disposition of businesses		—		—		—			—			—			—			143			(138	)
Acquisition of treasury stock		—		—		8.4			(99	)		—			—			—			—
Issuance of common stock		125.5		1		—			—			1,566			—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		2.2		—		(0.6	)		9			9			—			—			—
Stock compensation		—		—		—			—			26			—			—			—
Changes in the carrying amount of redeemable stock of subsidiaries		—		—		—			—			—			7			—			—
Acquisition of subsidiary shares from noncontrolling interests		—		—		—			—			(25	)		—			—			5
Balance at December 31, 2010		804.9	$	8		17.3		$	(216	)	$	8,444		$	620		$	(2,383	)	$	3,940

See Accompanying Notes to these Consolidated Financial Statements

76

THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009, AND 2008

1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The AES Corporation is a holding company (the “Parent Company”) that through its subsidiaries and affiliates, (collectively, “AES” or “the Company”) operates a geographically diversified portfolio of electricity generation and distribution businesses. Generally, given this holding company structure, the liabilities of the individual operating entities are not recourse to the parent and are isolated to the operating entities. Most of our operating entities are structured as corporations, therefore limiting the liability of the shareholders. The structure is generally the same regardless of whether a subsidiary is consolidated under a voting or variable interest model.

PRINCIPLES OF CONSOLIDATION—The Consolidated Financial Statements of the Company include the accounts of The AES Corporation, its subsidiaries and controlled affiliates, and variable interest entities (“VIEs”) of which the Company is the primary beneficiary. All intercompany transactions and balances have been eliminated in consolidation.

A VIE is an entity (a) that has a total equity investment at risk that is not sufficient to finance its activities without additional subordinated financial support or (b) where the group of equity holders does not have (i) the ability to make significant decisions about the entity’s activities, (ii) the obligation to absorb the entity’s expected losses or (iii) the right to receive the entity’s expected residual returns or (c) where the voting rights of some equity holders are not proportional to their obligations to absorb expected losses, receive expected residual returns, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights.

Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on the consolidation of VIEs. The new guidance requires an entity to determine qualitatively, rather than quantitatively, the primary beneficiary of a VIE. This determination is based on whether the entity has the power to direct the activities that most significantly impact the economic performance of the VIE and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Other key changes include: a requirement for the ongoing reconsideration of the primary beneficiary, the criteria used for determining whether service provider or decision maker contracts are variable interests, the consideration of kick-out and removal rights in determining whether an entity is a VIE, the types of events that trigger the reassessment of whether an entity is a VIE and expansion of the disclosures previously required.

The determination of which party has the power to direct the activities that most significantly impact the economic performance of the VIE could require significant judgment and assumptions. That determination considers the purpose and design of the business, the risks that the business was designed to create and pass along to other entities, the activities of the business that can be directed and which party can direct them, and the expected relative impact of those activities on the economic performance of the business through its life. The businesses for which significant judgment and assumptions were required were primarily certain generation businesses who have power purchase agreements (“PPAs”) to sell energy exclusively or primarily to a single counterparty for the term of those agreements. For these generation businesses, the counterparty has the power to dispatch energy and, in some instances, to make decisions regarding the sale of excess energy. As such, the counterparty has the power to direct certain activities that significantly impact the economic performance of the business primarily through the cash flows and gross margin, if any, earned by the business from the sale of energy to the counterparty and sometimes through the counterparty’s absorption of fuel price risk. However, the counterparty usually does not have the power to direct any of the other activities that could significantly impact the economic performance. These other activities include: daily operation and management, maintenance, repairs and capital expenditures, plant expansion, decisions regarding the overall financing of ongoing operations and

77

budgets and, in some instances, decisions regarding the sale of excess energy. As such, AES has the power to direct some activities of the business that significantly impact its economic performance, primarily through the cash flows and gross margin earned from capacity payments received from being available to produce energy and from the sale of energy to other entities (particularly during any period beyond the end of the power purchase agreement). For these businesses, the determination as to which set of activities most significantly impact the economic performance of the business requires significant judgment and the use of assumptions. The Company concluded that the activities directed by the counterparty were less significant than those directed by AES.

The adoption of the new accounting guidance on the consolidation of VIEs resulted in the deconsolidation of certain immaterial VIEs previously consolidated. Additionally, assets, liabilities and operating results of two of the Company’s VIEs, previously accounted for under the equity method of accounting, were required to be consolidated. Cartagena, a 71% owned generation business in Spain, and Cili, a 51% owned generation business in China, were consolidated under the new guidance. This resulted in a cumulative effect adjustment of $47 million to retained earnings as of January 1, 2010. The cumulative effect adjustment is primarily comprised of losses that were not recognized while the equity method of accounting was suspended for Cartagena. The equity method of accounting was suspended in December 2008 when the Company’s basis in its investment in Cartagena was reduced to zero. As of December 31, 2010, total assets and total liabilities related to these VIEs were $850 million and $919 million, respectively. In addition, revenue for the year ended December 31, 2010 included $416 million of revenue from these VIEs. Prior period operating results of these VIEs are reflected in “Net equity in earnings of affiliates” except for those prior periods during which the equity method of accounting was suspended.

USE OF ESTIMATES—The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Items subject to such estimates and assumptions include: the carrying value and estimated useful lives of long-lived assets; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of deferred regulatory assets; the valuation of certain financial instruments; the determination of noncontrolling interest using the hypothetical liquidation at book value (“HLBV”) method for certain wind generation partnerships; pension liabilities; environmental liabilities; and potential litigation claims and settlements.

DISCONTINUED OPERATIONS AND RECLASSIFICATIONS—A discontinued operation is a component of the Company that either has been disposed of or is classified as held for sale. A component of the Company comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the Company. In accordance with the accounting standards on the impairment or disposal of long-lived assets, the prior period Consolidated Financial Statements have been restated to reflect the businesses determined to be discontinued operations, as further discussed in Note 21—Discontinued Operations and Held for Sale Businesses. The Company has reclassified certain of its trade related payables from accrued and other liabilities to accounts payable within the Consolidated Financial Statements to conform to current year presentation.

FAIR VALUE—Fair value, as defined in the fair value measurement accounting guidance, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The Company applies the fair value measurement accounting guidance for financial assets and liabilities to determine the fair value of short and long term investments in marketable debt and equity securities, included in the consolidated balance sheet line items “Short-term investments” and “Other assets (noncurrent),” derivative assets, included in “Other current assets” and “Other assets (noncurrent)” and derivative liabilities, included in “Accrued and other liabilities (current)” and “Other long-term liabilities.” The Company applies the fair value measurement guidance for nonfinancial assets upon

78

the acquisition of a business in accordance with the accounting guidance for business combinations or in conjunction with the measurement of an impairment loss on an asset group or reporting unit under the accounting guidance for the impairment of long-lived assets or goodwill.

The fair value measurement accounting guidance requires that the Company make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity.

Fair value, where available, is based on observable quoted market prices. Where observable prices or inputs are not available, several valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity.

To increase consistency and enhance disclosure of the fair value of financial instruments, the fair value measurement accounting guidance creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:

Level 1—unadjusted quoted prices in active markets accessible by the reporting entity for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—pricing inputs other than quoted market prices included in Level 1 which are based on observable market data, that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from observable market data by correlation or other means. The fair value of most over-the-counter derivatives derived from internal valuation models using market inputs and most investments in marketable debt securities qualify as Level 2.

Level 3—pricing inputs that are unobservable, or less observable, from objective sources. Unobservable inputs are only used to the extent observable inputs are not available. These inputs maintain the concept of an exit price from the perspective of a market participant and should reflect assumptions of other market participants. An entity should consider all market participant assumptions that are available without unreasonable cost and effort. These are given the lowest priority and are generally used in internally developed methodologies to generate management’s best estimate of the fair value when no observable market data is available. The fair value of the Company’s reporting units determined using a discounted cash flows valuation model for goodwill impairment assessment and the fair value of the Company’s long-lived asset groups determined using a discounted cash flows valuation model for the long-lived asset impairment assessments qualify as Level 3.

Any transfers between the fair value hierarchy levels are recognized at the end of the reporting period.

CASH AND CASH EQUIVALENTS—The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit and short-term marketable securities, with an original or remaining maturity at the date of acquisition of three months or less, to be cash and cash equivalents. The carrying amount of such balances approximate fair value.

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RESTRICTED CASH—Restricted cash includes cash and cash equivalents which are restricted as to withdrawal or usage. The nature of restrictions includes restrictions imposed by financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves and others, as well as restrictions imposed by long-term PPAs.

INVESTMENTS IN MARKETABLE SECURITIES—Short-term investments in marketable debt and equity securities consist of securities with original or remaining maturities in excess of three months but less than one year. The Company’s marketable investments are primarily certificates of deposit, government debt securities and money market funds.

Marketable debt securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at amortized cost. Other marketable securities that the Company does not intend to hold to maturity are classified as available-for-sale or trading and are carried at fair value. Available-for-sale investments are marked-to-market at the end of each reporting period, with unrealized holding gains or losses, which represent changes in the market value of the investment, reflected in accumulated other comprehensive income (“AOCI”), a separate component of stockholders’ equity. In measuring the other-than-temporary impairment of debt securities, the Company identifies two components: 1) the amount representing the credit loss, which is recognized as “other non-operating expense” in the Consolidated Statements of Operations; and 2) the amount related to other factors, which is recognized in AOCI unless there is a plan to sell the security, in which case it would be recognized in earnings. The amount recognized in AOCI for held-to-maturity debt securities is then amortized over the remaining life of the security.

Investments classified as trading are marked-to-market on a periodic basis through the Consolidated Statements of Operations. Interest and dividends on investments are reported in interest income and other income, respectively. Gains and losses on sales of investments are determined using the specific identification method.

See Note 4—Fair Value and the Company’s fair value policy for additional discussion regarding the determination of the fair value of the Company’s investments in marketable debt and equity securities.

ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS—Accounts and Notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectable amount as appropriate. Certain of our businesses charge interest on accounts receivable either under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. In situations where the collection of interest is uncertain, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectible. Included in “Noncurrent Other Assets” are long-term financing receivables of $151 million, primarily with certain Latin American governmental bodies. These receivables have contractual maturities of greater than one year and are being collected in installments. Of the total $151 million, amounts of $81 million and $55 million, respectively, relate to our businesses in Argentina and the Dominican Republic. The remaining amount relates to our distribution businesses in Brazil.

INVENTORY—Inventory primarily consists of coal, fuel oil and other raw materials used to generate power, and spare parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost or market. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. Cost is determined under the first-in, first-out (“FIFO”), average cost or specific identification method. Generally, cost is reduced to market value if the market value of inventory has declined and it is probable that the utility of inventory, in its disposal in the ordinary course of business, will not be recovered through revenue earned from the generation of power.

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LONG-LIVED ASSETS—Long-lived assets include property, plant and equipment, assets under capital leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).

Property, plant and equipment

Property, plant and equipment are stated at cost, net of accumulated depreciation. The costs of renewals and improvements that extend the useful life of property, plant and equipment are capitalized.

Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the project is deemed probable, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Construction in progress balances are transferred to electric generation and distribution assets when an asset group is ready for its intended use. Government subsidies are recorded as a reduction to property, plant and equipment and reflected in cash flows from investing activities.

Depreciation, after consideration of salvage value and asset retirement obligations, is computed primarily using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Maintenance and repairs are charged to expense as incurred. Capital spare parts, including rotable spare parts, are included in electric generation and distribution assets. If the spare part is considered a component, it is depreciated over its useful life after the part is placed in service. If the spare part is deemed part of a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.

Intangible Assets Subject to Amortization

Finite-lived intangible assets are amortized over their useful lives which range from 1 - 89 years. The Company accounts for purchased emission allowances as intangible assets and records an expense when utilized or sold. Granted allowances are valued at zero.

Impairment of Long-lived Assets

The Company evaluates the impairment of long-lived assets (asset group) using internal projections of undiscounted cash flows when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under the relevant accounting standards. Events or changes in circumstances that may necessitate a recoverability evaluation may include but are not limited to: changes to or the passage of new legislation, changes in the relative pricing of wholesale electricity, anticipated demand and/or cost of fuel. The carrying amount of a long-lived asset (asset group) may not be recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposal of the asset (asset group). In such cases, fair value of the long-lived asset (asset group) is determined in accordance with the fair value measurement accounting guidance. The excess of carrying amount over fair value, if any, is recognized as an impairment expense. For regulated assets, an impairment expense could be reduced by the establishment of a regulatory asset, if recovery through approved rates was probable. For non-regulated assets, impairment is recognized as an expense against earnings.

DEFERRED FINANCING COSTS—Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight-line method when it does not differ materially from the effective interest method. Make-whole payments in connection with early debt retirements are classified as cash flows used in investing activities.

EQUITY METHOD INVESTMENTS—Investments in entities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in “Investments in and advances to affiliates” on the Consolidated Balance Sheets. In accordance with

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the accounting guidance for equity method investments, the Company periodically assesses the recoverability of its equity method investments. If an identified event or change in circumstances requires an impairment evaluation, management assesses the fair value based on valuation methodologies, including discounted cash flows, estimates of sale proceeds and external appraisals, as appropriate. The difference between the carrying amount of the equity method investment and its estimated fair value is recognized as impairment when the loss in value is deemed other-than-temporary and included in “Other non-operating expense” on the Consolidated Statements of Operations.

In accordance with the accounting standards for equity method investments, the Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the equity method if the investee subsequently reports net income to the extent that the Company’s share of such net income equals the share of net losses not recognized during the period in which the equity method of accounting was suspended.

GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS—In accordance with the accounting guidance on goodwill and other intangible assets, the Company recognizes goodwill as an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. The Company evaluates goodwill and indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. The Company’s annual impairment testing date is October 1^st.

Goodwill:

The Company evaluates goodwill impairment at the reporting unit level, which is an operating segment, as defined in the segment reporting accounting guidance, or one level below an operating segment, a component. In determining its reporting units, the Company starts with its segment reporting structure. Operating segments are identified and then analyzed to identify components (usually businesses) which make up these operating segments. Two or more components are combined into a single reporting unit if they share the economic similarity criteria prescribed by the accounting guidance. Assets and liabilities are allocated to a reporting unit if the assets will be employed by or a liability relates to the operations of a reporting unit or would be considered by a market participant in determining its fair value. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the synergies of the acquisition. Generally, each AES business constitutes a reporting unit.

Goodwill impairment evaluation is performed in two steps. In Step 1, the carrying amount of a reporting unit is compared to its fair value and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. In determining the implied fair value of goodwill for impairment measurement, the accounting guidance requires measuring all assets and liabilities, including unrecognized assets and liabilities, at fair value, as would be done in a business combination. When a Step 2 analysis is required to be completed, the fair value of individual assets and liabilities is determined using valuations (which in some cases may be based in part on third party valuation reports), or other observable sources of fair value, as appropriate. An impairment loss is recognized to the extent the carrying amount of goodwill exceeds its implied fair value, not to exceed the carrying value of goodwill.

Most of the Company’s reporting units are not publicly traded. Therefore, the Company estimates the fair value of its reporting units under the fair value measurement accounting guidance which requires making assumptions that a market participant would make in a hypothetical sale transaction at the testing date. The fair value of a reporting unit is estimated using internal budgets and forecasts, adjusted for any market participants’ assumptions and discounted at the rate of return required by a market participant. The Company considers both

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market and income-based approaches to determine a range of fair value, but typically concludes that the value derived using an income-based approach is more representative of fair value due to the lack of direct market comparables. The Company does use market data to corroborate and determine the reasonableness of the fair value derived from the income-based discounted cash flow analysis.

Indefinite-lived Intangible Assets:

The Company’s indefinite-lived intangible assets include items such as land use rights, easements, and concessions. These are tested for impairment on an annual basis or whenever events or changes in circumstances necessitate an evaluation for impairment in accordance with applicable accounting guidance for indefinite-lived intangible assets.

INCOME TAXES—Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more-likely-than-not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

PENSION AND OTHER POSTRETIREMENT PLANS—In accordance with the accounting guidance on defined benefit pension and other postretirement plans, the Company recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current year changes in the funded status recognized in AOCI. All plan assets are recorded at fair value. AES follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

NONCONTROLLING INTERESTS—In accordance with the accounting guidance on noncontrolling interests, such interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Stockholders’ Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income in the Consolidated Statements of Operations and Consolidated Statements of Changes in Stockholders’ Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero.

Although in general, the noncontrolling ownership interest in earnings is calculated based on ownership percentage, certain of the Company’s wind businesses use the HLBV method in consolidation. HLBV uses a balance sheet approach, which measures the Company’s equity in income or loss by calculating the change in the amount of net worth the partners are legally able to claim based on a hypothetical liquidation of the entity at the beginning of a reporting period compared to the end of that period. This method is used in AES Wind Generation partnerships which contain agreements designating different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership.

ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES—Accounts payable consists of amounts due to trade creditors related to the Company’s core business operations. The nature of these payables include amounts owed to vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and employee related costs including payroll, benefits and related taxes.

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ASSET RETIREMENT OBLIGATIONS—In accordance with the accounting standards for asset retirement obligations, the Company records the fair value of the liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.

GUARANTOR ACCOUNTING—In accordance with the accounting standards on guarantees, at the inception of a guarantee, the Company records the fair value of a guarantee as a liability, with the offset dependent on the circumstances under which the guarantee was issued.

TRANSFER OF FINANCIAL ASSETS—Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on transfers of financial assets, which among other things: removes the concept of a qualifying special purpose entity; introduces the concept of participating interests and specifies that in order to qualify for sale accounting a partial transfer of a financial asset or a group of financial assets should meet the definition of a participating interest; clarifies that an entity should consider all arrangements made contemporaneously with or in contemplation of a transfer and requires enhanced disclosures to provide financial statement users with greater transparency about transfers of financial assets and a transferor’s continuing involvement with transfers of financial assets accounted for as sales. Upon adoption on January 1, 2010, the Company recognized $40 million as accounts receivable and as an associated secured borrowing on its Consolidated Balance Sheet; both of which have since increased to $50 million as of December 31, 2010, as additional interests in receivables have been sold. While securitizing these accounts receivable through IPL Funding, a special purpose entity, IPL, the Company’s integrated utility in Indianapolis, had previously recognized the transaction as a sale, but had not recognized the accounts receivable and secured borrowing on its balance sheet. Under the facility, interests in these accounts receivable are sold, on a revolving basis, to unrelated parties (the Purchasers) up to the lesser of $50 million or an amount determinable under the facility agreement. The Purchasers assume the risk of collection on the interest sold without recourse to IPL, which retains the servicing responsibilities for the interest sold. While no direct recourse to IPL exists, IPL risks loss in the event collections are not sufficient to allow for full recovery of the retained interests. No servicing asset or liability is recorded since the servicing fee paid to IPL approximates a market rate. Under the new accounting guidance, the retained interest in these securitized accounts receivable does not meet the definition of a participating interest, thereby requiring the Company to recognize on its Consolidated Balance Sheet the portion transferred and the proceeds received as accounts receivable and a secured borrowing, respectively.

FOREIGN CURRENCY TRANSLATION—A business’ functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the U.S. Dollar translate their assets and liabilities into U.S. Dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. Dollars at the average exchange rates that prevailed during the period. Translation adjustments are included in AOCI. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in AOCI. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income.

REVENUE RECOGNITION—Revenue from Utilities is classified as regulated on the Consolidated Statements of Operations. Revenue from the sale of energy is recognized in the period during which the sale occurs. The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. Revenue from the Generation business is classified as non-regulated and is recognized based upon output delivered and

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capacity provided, at rates as specified under contract terms or prevailing market rates. The Company has businesses where it makes sales and purchases of power to and from Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”). In those instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

SHARE-BASED COMPENSATION—The Company grants share-based compensation in the form of stock options and restricted stock units. The Company accounts for stock-based compensation plans under the accounting guidance on stock-based compensation, which requires entities to recognize compensation costs relating to share-based payments in their financial statements. That cost is measured on the grant date based on the fair value of the equity or liability instrument issued and is expensed on a straight-line basis over the requisite service period, net of estimated forfeitures. Currently, the Company uses a Black-Scholes option pricing model to estimate the fair value of stock options granted to its employees.

GENERAL AND ADMINISTRATIVE EXPENSES—General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. Additionally, all costs associated with business development efforts are classified as general and administrative expenses.

REGULATORY ASSETS AND LIABILITIES—The Company accounts for certain of its regulated operations in accordance with the accounting standards on regulated operations. As a result, AES records assets and liabilities that result from the regulated ratemaking process that are not recognized under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred due to the probability of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs previously deferred ceases to be probable, the asset write-offs are recognized in continuing operations.

DERIVATIVES AND HEDGING ACTIVITIES—Derivatives primarily consist of interest rate swaps, cross currency swaps, foreign currency instruments, and commodity and embedded derivatives. The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. AES primarily uses derivative instruments to manage its interest rate, foreign currency and commodity exposures. The Company does not enter into derivative transactions for trading purposes.

Under the accounting standards for derivatives and hedging, the Company recognizes all contracts that meet the definition of a derivative, except those designated as normal purchase or normal sale at inception, as either assets or liabilities in the Consolidated Balance Sheets and measures those instruments at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Gains and losses related to derivative instruments that qualify as hedges are recognized in the same category as generated by the underlying asset or liability. Gains or losses on derivatives that do not qualify for hedge accounting are recognized as interest expense for interest rate and cross currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity derivatives.

The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective, designated and qualifies as a fair value hedge are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective, designated and qualifies as a cash flow hedge are deferred in AOCI and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is recognized in earnings immediately.

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The ineffective portion is recognized as interest expense for interest rate and cross currency hedges, foreign currency transaction gains or losses for foreign currency hedges, and non-regulated revenue or non-regulated cost of sales for commodity hedges. For all hedge contracts, the Company maintains formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If AES determines that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

For cash flow hedges of forecasted transactions, AES estimates the future cash flows of the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from AOCI into earnings.

The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.

See Note 4—Fair Value and the Company’s fair value policy for additional discussion regarding the determination of the fair value of the Company’s derivative assets and liabilities.

Accounting Pronouncements Issued But Not Yet Effective

The following accounting standards have been issued, but as of December 31, 2010 are not yet effective for and have not been adopted by AES.

Accounting Standards Update (“ASU”) No. 2010-28, Intangibles—Goodwill and Other (Topic 350), “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”

In December 2010, the FASB issued ASU No. 2010-28, which amends the accounting guidance related to goodwill. The amendments in ASU No. 2010-28 modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists, eliminating an entity’s ability to assert that a reporting unit is not required to perform Step 2 because the carrying amount of the reporting unit is zero or negative despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. ASU No. 2010-28 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010, or January 1, 2011 for AES. Early adoption is prohibited. The adoption is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

2. INVENTORY

As of December 31, 2010, 75% of the Company’s inventory was valued using average cost, 23% was determined using the FIFO method and the remaining inventory was valued using the specific identification method. The following table summarizes our inventory balances as of December 31, 2010 and 2009:

	December 31,
	2010		2009
	(in millions)
Coal, fuel oil and other raw materials	$	276	$	229
Spare parts and supplies		286		250
Total	$	562	$	479

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3. PROPERTY, PLANT & EQUIPMENT

The following table summarizes the components of the electric generation and distribution assets and other property, plant and equipment with their estimated useful lives:

	Estimated Useful  Life		December 31,
			2010			2009
			(in millions)
Electric generation and distribution facilities		3 - 62 yrs.	$	24,374		$	22,680
Other buildings		3 - 50 yrs.		2,211			1,922
Furniture, fixtures and equipment		3 - 31 yrs.		729			684
Other		1 - 50 yrs.		858			686
Total electric generation and distribution assets and other				28,172			25,972
Accumulated depreciation				(9,145	)		(8,576	)
Net electric generation and distribution assets and other(1)			$	19,027		$	17,396

⁽¹⁾  Net electric generation and distribution assets and other related to our businesses included in discontinued operations of $7 million and $1,493 million as of December 31, 2010 and 2009, respectively, were excluded from the table above and were included in the noncurrent assets of discontinued and held for sale businesses.

The amounts as of December 31, 2010 in the table above are stated net of impairment losses recognized in 2010 as further discussed in Note 19—Impairment Expense.

The following table summarizes interest capitalized during development and construction on qualifying assets for the years ended December 31, 2010, 2009 and 2008:

	December 31,
	2010		2009		2008
	(in millions)
Interest capitalized during development and construction	$	193	$	183	$	172

Recoveries of liquidated damages from construction delays and government subsidies are reflected as a reduction in the related projects’ construction costs. Approximately $12.2 billion of property, plant and equipment, net of accumulated depreciation, was mortgaged, pledged or subject to liens as of December 31, 2010.

Depreciation expense, including the amortization of assets recorded under capital leases, was $1.1 billion, $944 million and $899 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Net electric generation and distribution assets and other include unamortized internal use software costs of $170 million and $178 million as of December 31, 2010 and 2009, respectively. Amortization expense associated with software costs was $51 million, $48 million and $41 million for the years ended December 31, 2010, 2009 and 2008.

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The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation as of December 31, 2010 and 2009:

	December 31,
	2010			2009
	(in millions)
Regulated assets	$	12,488		$	11,744
Regulated accumulated depreciation		(5,123	)		(4,830	)
Regulated generation, distribution assets, and other, net		7,365			6,914
Non-regulated assets		15,684			14,228
Non-regulated accumulated depreciation		(4,022	)		(3,746	)
Non-regulated generation, distribution assets, and other, net		11,662			10,482
Net electric generation and distribution assets, and other	$	19,027		$	17,396

The following table summarizes the amounts recognized, which were related to asset retirement obligations, for the years ended December 31, 2010 and 2009:

	2010		2009
	(in millions)
Balance at January 1	$	67	$	47
Additional liabilities incurred		19		17
Accretion expense		5		3
Change in estimated cash flows		1		—
Balance at December 31	$	92	$	67

The Company’s asset retirement obligations covered by the relevant guidance primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. The fair value of legally restricted assets for purposes of settling asset retirement obligations was $12 million and $0 at December 31, 2010 and 2009, respectively.

4. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The fair value of non-recourse debt is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow analyses. See Note 10—Debt for additional information on the fair value and carrying value of debt. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards, swaps and options, and energy derivatives is the estimated net amount that the Company would receive or pay to sell or transfer the agreements as of the balance sheet date.

The estimated fair values of the Company’s assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

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The following table summarizes the carrying amount and fair value of certain of the Company’s financial assets and liabilities as of December 31, 2010 and 2009:

	December 31,
	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Assets
Marketable securities	$	1,772	$	1,772	$	1,691	$	1,691
Derivatives		124		124		120		120
Total assets	$	1,896	$	1,896	$	1,811	$	1,811
Liabilities
Debt	$	19,551	$	20,137	$	19,343	$	19,778
Derivatives		423		423		303		303
Total liabilities	$	19,974	$	20,560	$	19,646	$	20,081

Valuation Techniques:

The fair value measurement accounting guidance describes three main approaches to measuring the fair value: (1) market approach; (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach often uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and emissions allowances etc). In general, the Company determines the fair value of investments using the market approach and of derivatives using the income approach. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, fair value generated by the income approach is often selected.

Investments

The Company’s investments measured at fair value primarily consist of marketable debt and equity securities. Equity securities are measured at fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to London Inter Bank Offered Rate (“LIBOR”), a benchmark interest rate widely used by banks in the money market), or Selic (overnight borrowing rate) rates in Brazil. Fair value is determined from comparisons of market data obtained for similar assets and is considered Level 2 in the fair value hierarchy. For more detail regarding the fair value of investments see Note 5—Investments in Marketable Securities.

Derivatives

When deemed appropriate, the Company manages its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of financial and physical derivative instruments. The Company’s derivatives are primarily interest rate swaps to hedge non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations, commodity derivatives to

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hedge against commodity price fluctuations and embedded derivatives associated with commodity contracts. The Company’s subsidiaries are counterparties to various over-the-counter derivatives, which include interest rate swaps and options, foreign currency options and forwards and commodity swaps. In addition, the Company’s subsidiaries are counterparties to certain PPAs and fuel supply agreements that are derivatives or include embedded derivatives.

For the derivatives where there is a standard industry valuation model, the Company uses that model to estimate the fair value. For the derivatives (such as the PPAs and fuel supply agreements that are derivatives or include embedded derivatives) where there is not a standard industry valuation model, the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. For all derivatives, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The following are among the most common market data inputs used in the income approach: volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates and prices are generally obtained from published information provided by pricing services for an instrument with the same duration as the derivative instrument being valued. In situations where significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis, Monte Carlo simulation or prices for similarly traded instruments available in the market.

For each derivative, the income approach is used to estimate the cash flows over the remaining term of the contract. Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR) plus a spread that reflects the credit or nonperformance risk. This risk is estimated by the Company using credit spreads and risk premiums that are observable in the market, whenever possible, or estimated borrowing costs based on bank quotes, industry publications and/or information on financing closed on similar projects. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are classified as Level 2.

In certain instances, the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. In addition, in certain instances, there may not be third party data readily available which requires the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. The fair value hierarchy of an asset or a liability is based on the Level of significance of input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are transferred to Level 3 when the use of unobservable inputs becomes significant. Similarly, when the use of unobservable input becomes insignificant for Level 3 assets and liabilities, they are transferred to Level 2.

Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2. The Company has not had any Level 1 derivatives so there have not been any transfers between Levels 1 and 2.

Nonfinancial assets and liabilities

For nonrecurring measurements derived using the income approach, fair value is determined using valuation models based on the principles of discounted cash flows (“DCF”). The income approach is most often used in the impairment evaluation of long-lived tangible assets, goodwill and intangible assets. The Company has developed internal valuation models for such valuations; however, an independent valuation firm may be engaged in certain situations. In such situations, the independent valuation firm largely uses DCF valuation models as the primary measure of fair value though other valuation approaches are also considered. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever possible, the Company attempts to obtain market

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observable data to develop input assumptions. Where the use of market observable data is limited or not possible for certain input assumptions, the Company develops its own estimates of such assumptions using a variety of techniques such as regression analysis and extrapolations.

For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to find sale transactions of identical or similar assets. This approach is used in the impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.

For nonrecurring measurements derived using the cost approach, fair value is typically determined using the replacement cost approach. Under this approach, the depreciated replacement cost of assets is determined by first determining the current replacement cost of assets and then applying the remaining useful lives percentages to such cost. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment which is why its use is limited to the measurement of a few long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach. For the year ended December 31, 2010, the Company did not measure any nonfinancial assets under the cost approach.

Fair Value Considerations:

In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company’s nonperformance. The conditions and criteria used to assess these factors are:

Sources of market assumptions:

The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Platt’s). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine the fair value.

Market liquidity:

The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company’s current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of the assets traded without significantly affecting the market price. Other factors the Company considers when determining whether a market is active or inactive include the presence of government or regulatory control over pricing that could make it difficult to establish a market based price when entering into a transaction.

Nonperformance risk:

Nonperformance risk refers to the risk that the obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company or counterparty’s credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.

Nonperformance risk on the investments held by the Company is incorporated in the investment’s exit price that is derived from quoted market data that is used to mark the investment to fair value.

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The Company adjusts for nonperformance risk or credit risk on its derivative instruments by deducting a credit valuation adjustment (“CVA”). The CVA is based on the margin or debt spread of the Company or counterparty and the tenor of the respective derivative instrument. The counterparty for a derivative asset position is considered to be the bank or government sponsored banking entity or counterparty to the PPA or commodity contract. The CVA for asset positions is based on the counterparty’s credit ratings and debt spreads or, in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. The CVA for liability positions is based on the Parent Company’s or the subsidiary’s current debt spread, the margin on indicative financing arrangements, or in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. If the instrument is recourse to the Parent Company, the Parent Company’s current debt spread is used to adjust for nonperformance risk. All derivative instruments are analyzed individually and are subject to unique risk exposures.

Recurring Measurements:

The following table sets forth, by Level within the fair value hierarchy, the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2010 and 2009. Financial assets and liabilities have been classified in their entirety based on the lowest Level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.

	Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total December 31, 2010
	(in millions)
Assets
Available-for-sale securities	$	8	$	1,712	$	42	$	1,762
Trading securities		10		—		—		10
Derivatives		—		63		61		124
Total assets	$	18	$	1,775	$	103	$	1,896
Liabilities
Derivatives	$	—	$	411	$	12	$	423
Total liabilities	$	—	$	411	$	12	$	423
	Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total December 31, 2009
	(in millions)
Assets
Available-for-sale securities	$	133	$	1,501	$	42	$	1,676
Trading securities		7		—		—		7
Derivatives		—		90		30		120
Total assets	$	140	$	1,591	$	72	$	1,803
Liabilities
Derivatives	$	—	$	273	$	30	$	303
Total liabilities	$	—	$	273	$	30	$	303

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The following table presents a reconciliation of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009:

	Year Ended December 31,
	2010															2009
	Interest Rate			Cross Currency			Foreign Currency			Commodity & Other			Total			Total
	(in millions)
Balance at beginning of period(1)	$	(12	)	$	(12	)	$	—		$	24		$	—		$	(71	)
Total gains (losses) (realized and unrealized):
Included in earnings(2)		1			4			25			21			51			(18	)
Included in other comprehensive income		(12	)		13			—			—			1			134
Included in regulatory assets		(3	)		—			—			1			(2	)		—
Purchases, issuances and settlements		7			5			(1	)		(28	)		(17	)		31
Transfers of assets (liabilities) into Level 3(3)		—			—			(2	)		—			(2	)		1
Transfers of (assets) liabilities out of Level 3(3)		18			—			—			—			18			(77	)
Balance at end of period(1)	$	(1	)	$	10		$	22		$	18		$	49		$	—
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	—		$	7		$	24		$	9		$	40		$	(2	)

⁽¹⁾  Derivative assets and (liabilities) are presented on a net basis.

⁽²⁾  The gains (losses) included in earnings for these Level 3 derivatives are classified as follows: interest rate and cross currency derivatives as interest expense, foreign currency derivatives as foreign currency transaction gains (losses) and commodity and other derivatives as either non-regulated revenue, non-regulated cost of sales or other expense. See Note 6—Derivative Instruments and Hedging Activities for further information regarding the classification of gains and losses included in earnings in the Consolidated Statements of Operations.

⁽³⁾  Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2. The (assets) liabilities transferred out of Level 3 are primarily the result of a decrease in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments. Similarly, the assets (liabilities) transferred into Level 3 are primarily the result of an increase in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments.

The following table presents a reconciliation of available-for-sale securities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009:

	Year Ended December 31,
	2010		2009
	(in millions)
Balance at beginning of period(1)	$	42	$	42
Purchases, issuances and settlements		—		—
Balance at end of period	$	42	$	42
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets held at the end of the period	$	—	$	—

⁽¹⁾  Available-for-sale securities in Level 3 are auction rate securities and variable rate demand notes which have failed remarketing or are not actively trading and for which there are no longer adequate observable inputs to measure the fair value.

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Nonrecurring Measurements:

For the purpose of impairment evaluation, the Company measured fair values of long-lived assets, goodwill and intangibles assets, and assets and liabilities of discontinued operations under the fair value measurement accounting guidance. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the year and their level within the fair value hierarchy:

			Year Ended December 31, 2010
	Carrying Amount(1)		Fair Value						Gross (Gain)  Loss
			Level 1		Level 2		Level 3
	(in millions)
Long-lived assets held and used:
Southland (Huntington Beach)	$	288	$	—	$	—	$	88	$	200
Tisza II		160		—		—		75		85
Deepwater		83		—		—		4		79
Discontinued operations and
businesses held for sale:
Eastern Energy		827		—		—		—		827
Barka		20		—		124		—		(104	)
Ras Laffan		120		—		226		—		(106	)
Goodwill:
Deepwater		18		—		—		—		18
Other		3		—		—		—		3

⁽¹⁾  Carrying amount as of the month end prior to impairment.

Long-lived Assets Held and Used

In the fourth quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Deepwater, our pet-coke-fired generation facility in Texas. These long-lived assets had a carrying amount of $83 million and were written down to their fair value of $4 million. This resulted in the recognition of asset impairment expense of $79 million.

In the third quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Tisza II, our gas-fired generation plant in Hungary, and Huntington Beach, one of our gas-fired generation plants in California. These long-lived assets had carrying amounts of $160 million and $288 million, respectively, and were written down to their fair value of $75 million and $88 million, respectively. These resulted in the recognition of asset impairment expense of $85 million and $200 million, respectively.

Since the majority of significant assumptions used in the valuations were not observable, management believes that the measurements are Level 3 in the fair value hierarchy. For further discussion of these impairments, see Note 19—Impairment Expense.

Discontinued Operations and Held for Sale Businesses

The Company determined the fair value of nonfinancial assets and liabilities of our held for sale businesses during the year ended December 31, 2010. These businesses included Barka in Oman, Ras Laffan in Qatar, and Eastern Energy, our coal-fired generation plants in New York.

In the fourth quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Eastern Energy. These long-lived assets had a carrying amount of $827 million and were considered fully impaired. As a result, an impairment loss of $827 million was recognized, which is included in Income from operations of discontinued businesses in the Consolidated Statement of Operations.

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The fair value measurements of Barka and Ras Laffan were considered Level 2 as they were based on the agreed sale proceeds whereas Eastern Energy was considered a Level 3 measurement as the majority of significant assumptions used in the valuation were not observable. For further discussion, see Note 21—Discontinued Operations and Held for Sale Businesses.

Goodwill

As noted in Note 8—Goodwill and Other Intangible Assets, goodwill of $18 million related to our Deepwater business was written down to its implied fair value of zero during an interim impairment evaluation, resulting in the recognition of goodwill impairment of $18 million for the year ended December 31, 2010.

Since the majority of significant assumptions used in the valuation were not observable, management believes that the measurement is Level 3 in the fair value hierarchy. For further discussion, see Note 8—Goodwill and Other Intangible Assets.

5. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company’s investments in marketable debt and equity securities classified as trading and available-for-sale as of December 31, 2010 and 2009 by type of investment and by level within the fair value hierarchy. The security types are determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its securities.

	December 31,
	2010								2009
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)
AVAILABLE-FOR-SALE:(1)
Debt securities:
Unsecured debentures(2)	$	—	$	727	$	—	$	727	$	—	$	667	$	—	$	667
Certificates of deposit(2)		—		877		—		877		—		652		—		652
Government debt securities		—		47		—		47		—		152		—		152
Other		—		—		42		42		—		—		42		42
Subtotal		—		1,651		42		1,693		—		1,471		42		1,513
Equity securities:
Mutual funds		1		61		—		62		117		—		—		117
Common stock		7		—		—		7		16		—		—		16
Money market funds		—		—		—		—		—		30		—		30
Subtotal		8		61		—		69		133		30		—		163
Total available-for-sale		8		1,712		42		1,762		133		1,501		42	$	1,676
TRADING:
Equity securities:
Mutual funds		10		—		—		10		7		—		—		7
Total trading		10		—		—		10		7		—		—		7
TOTAL	$	18	$	1,712	$	42	$	1,772	$	140	$	1,501	$	42	$	1,683
Held-to-maturity securities(3)								—								8
Total marketable securities							$	1,772							$	1,691

⁽¹⁾  Amortized cost approximated fair value at December 31, 2010 and 2009, with the exception of certain common stock investments with a cost basis of $6 million carried at their fair value of $7 million and $16 million at December 31, 2010 and 2009, respectively.

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⁽²⁾  Unsecured debentures are instruments similar to certificates of deposit that are held primarily by our subsidiaries in Brazil. The unsecured debentures and certificates of deposit included here do not qualify as cash equivalents and meet the definition of a security under the relevant guidance and are therefore classified as available-for-sale securities.

⁽³⁾  Held-to-maturity securities are carried at amortized cost and not measured at fair value on a recurring basis. These investments consist primarily of certificates of deposit and government debt securities. The amortized cost approximated fair value of the held-to-maturity securities at December 31, 2009.

As of December 31, 2010, all available-for-sale debt securities had stated maturities less than one year, with the exception of $42 million of auction rate securities and variable rate demand notes held by IPL, a subsidiary of the Company in Indiana. These securities, classified as other debt securities in the table above, had stated maturities of greater than ten years.

During the second quarter of 2009, three of the Company’s generation businesses in the Dominican Republic exchanged $110 million of accounts receivable due from the government-owned distribution companies in the Dominican Republic for sovereign bonds of the same amount. The bonds, which were classified as available-for-sale securities, were adjusted to fair value when acquired. During the second and third quarters of 2009, the Company used a portion of the bonds with a carrying value of $31 million to settle third-party liabilities and sold the remaining bonds. As of December 31, 2009, all of the sovereign bonds had been sold or transferred.

The following table summarizes the pre-tax gains and losses related to available-for-sale securities for the years ended December 31, 2010, 2009 and 2008. There were no realized gains or losses on trading securities and there were no realized losses on the sale of available-for-sale securities. There was no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income for the years ended December 31, 2010, 2009 or 2008.

	December 31,
	2010		2009		2008
	(in millions)
Gains (losses) included in other comprehensive income	$	2	$	10	$	(2	)
Gains reclassified out of other comprehensive income into earnings		—		2		—
Proceeds from sales		5,888		4,466		5,006
Gross realized gains on sales		2		3		—

6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Risk Management Objectives

The Company is exposed to market risks associated with its enterprise-wide business activities, namely the purchase and sale of fuel and electricity as well as foreign currency risk and interest rate risk. In order to manage the market risks associated with these business activities, we enter into contracts that incorporate derivatives and financial instruments, including forwards, futures, options, swaps or combinations thereof, as appropriate. The Company applies hedge accounting for all contracts as long as they are eligible under the accounting standards for derivatives and hedging. While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting.

Interest Rate Risk

AES and its subsidiaries utilize variable rate debt financing for construction projects and operations, resulting in an exposure to interest rate risk. Interest rate swap, cap and floor agreements are entered into to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing.

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These interest rate contracts range in maturity through 2027, and are typically designated as cash flow hedges. The following table sets forth, by underlying type of interest rate index, the Company’s current and maximum outstanding notional under its interest rate derivative instruments, the weighted average remaining term and the percentage of variable-rate debt hedged that is based on the related index as of December 31, 2010 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:

	December 31, 2010
	Current				Maximum(1)				Weighted Average Remaining Term(1)		% of Debt Currently Hedged by Index(2)
Interest Rate Derivatives	Derivative Notional		Derivative Notional Translated to USD		Derivative Notional		Derivative Notional Translated to USD
	(in millions)								(in years)
LIBOR (U.S. Dollar)		2,543	$	2,543		2,671	$	2,671		10		69	%
EURIBOR (Euro)		1,233		1,651		1,233		1,651		13		72	%
LIBOR (British Pound Sterling)		44		68		44		68		10		69	%
Securities Industry and Financial Markets Association Municipal Swap Index (U.S. Dollar)		40		40		40		40		12		N/A	(3)

⁽¹⁾  The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between December 31, 2010 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The weighted average remaining term represents the remaining tenor of our interest rate derivatives weighted by the corresponding maximum notional.

⁽²⁾  Excludes variable-rate debt tied to other indices where the Company has no interest rate derivatives.

⁽³⁾  The debt that was being hedged is no longer exposed to variable interest payments, because it is now held on IPL’s behalf and no longer bears interest.

Cross currency swaps are utilized in certain instances to manage the risk related to fluctuations in both interest rates and certain foreign currencies. These cross currency contracts range in maturity through 2028. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional of its cross currency derivative instruments as of December 31, 2010 which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional as of December 31, 2010:

	December 31, 2010
Cross Currency Swaps	Notional		Notional Translated to USD		Weighted Average Remaining Term(1)		% of Debt Currently Hedged by Index(2)
	(in millions)				(in years)
Chilean Unidad de Fomento (CLF)		6	$	257		15		83	%

⁽¹⁾  Represents the remaining tenor of our cross currency swaps weighted by the corresponding notional.

⁽²⁾  Represents the proportion of foreign currency denominated debt hedged by the same foreign currency denominated notional of the cross currency swap.

Foreign Currency Risk

We are exposed to foreign currency risk as a result of our investments in foreign subsidiaries and affiliates. AES operates businesses in many foreign environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards are utilized, where possible, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2011. The following tables set forth, by type of foreign currency

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denomination, the Company’s outstanding notional over the remaining terms of its foreign currency derivative instruments as of December 31, 2010 regardless of whether the derivative instruments are in qualifying hedging relationships:

	December 31, 2010
Foreign Currency Options	Notional(1)		Notional Translated to USD(1)		Probability Adjusted Notional(2)		Weighted Average Remaining Term(3)
	(in millions)						(in years)
Brazilian Real (BRL)		208	$	120	$	30		<1
Euro (EUR)		15		21		18		<1
Philippine Peso (PHP)		266		6		1		<1
British Pound (GBP)		3		4		2		<1

⁽¹⁾  Represents contractual notionals at inception of trade.

⁽²⁾  Represents the gross notional amounts times the probability of exercising the option, which is based on the relationship of changes in the option value with respect to changes in the price of the underlying currency.

⁽³⁾  Represents the remaining tenor of our foreign currency options weighted by the corresponding notional.

	December 31, 2010
Foreign Currency Forwards	Notional		Notional Translated to USD		Weighted Average Remaining Term(1)
	(in millions)				(in years)
Chilean Peso (CLP)		89,106	$	179		<1
Colombian Peso (COP)		13,151		7		<1
Argentine Peso (ARS)		57		13		<1

⁽¹⁾  Represents the remaining tenor of our foreign currency forwards weighted by the corresponding notional.

In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives that require separate valuation and accounting due to the fact that the item being purchased or sold is denominated in a currency other than the functional currency of that subsidiary or the currency of the item. These contracts range in maturity through 2025. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional over the remaining terms of its foreign currency embedded derivative instruments as of December 31, 2010:

	December 31, 2010
Embedded Foreign Currency Derivatives	Notional		Notional Translated to USD		Weighted Average Remaining Term(1)
	(in millions)				(in years)
Philippine Peso (PHP)		21,176	$	484		3
Kazakhstani Tenge (KZT)		31,084		210		10
Argentine Peso (ARS)		331		83		9
Euro (EUR)		28		38		4
Brazilian Real (BRL)		19		11		1
Cameroon Franc (XAF)		1,755		4		2

⁽¹⁾  Represents the remaining tenor of our foreign currency embedded derivatives weighted by the corresponding notional.

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Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, fuel and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions (which provide our distribution businesses with a franchise to serve a specific geographic region), a portion of our current and expected future revenues are derived from businesses without significant long-term purchase or sales contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuel and environmental credits in competitive markets. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy can involve the use of commodity forward contracts, futures, swaps and options. Some of our businesses hedge certain aspects of their commodity risks using financial hedging instruments, as described below.

We also enter into short-term contracts for electricity and fuel in other competitive markets in which we operate. When hedging the output of our generation assets, we have power purchase agreements or other hedging instruments that lock in the spread in dollars per MWh between the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold (“Dark Spread” where the fuel is coal). The portion of our sales and fuel purchases that are not subject to such agreements will be exposed to commodity price risk.

The PPAs and fuel supply agreements entered into by the Company are evaluated to determine if they meet the definition of a derivative or contain embedded derivatives, either of which require separate valuation and accounting. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could then be net settled and meet the definition of a derivative.

Nonetheless, certain of the PPAs and fuel supply agreements entered into by certain of the Company’s subsidiaries are derivatives or contain embedded derivatives requiring separate valuation and accounting. These agreements range in maturity through 2024. The following table sets forth by type of commodity the Company’s outstanding notionals for the remaining term of its commodity derivative and embedded derivative instruments as of December 31, 2010:

	December 31, 2010
Commodity Derivatives	Notional			Weighted Average Remaining Term(1)
	(in millions)			(in years)
Natural gas (MMBtu)		34			12
Petcoke (Metric tons)		14			14
Aluminum (MWh)		17	(3)		9
Certified Emission Reductions (CER)		1			2
Financial transmission rights (MW)		—	(2)		<1

⁽¹⁾  Represents the remaining tenor of our commodity and embedded derivatives weighted by the corresponding volume.

⁽²⁾  De minimis amount.

⁽³⁾  Our exposure is to fluctuations in the price of aluminum while the notional is based on the amount of power we sell under the PPA.

In addition, as part of the settlement agreements terminating the gas transportation contracts with Gasoducto GasAndes (Argentina) S.A. and Gasoducto GasAndes (Chile) S.A. discussed in Note 12—Contingencies, we have an embedded derivative related to the dividends that could result from our 13% ownership in these two gas transportation companies.

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Accounting and Reporting

The following table sets forth the Company’s derivative instruments as of December 31, 2010 and 2009 by type of derivative and by level within the fair value hierarchy. Derivative assets and liabilities are recognized at their fair value. Derivative assets and liabilities are combined with other balances and included in the following captions in our Consolidated Balance Sheets: current derivative assets in other current assets, noncurrent derivative assets in other noncurrent assets, current derivative liabilities in accrued and other liabilities and long-term derivative liabilities in other long-term liabilities.

	December 31, 2010									December 31, 2009
	Level 1		Level 2			Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)									(in millions)
Assets
Current assets:
Foreign currency derivatives	$	—	$	4	(1)	$	3	$	7	$	—	$	6	$	—	$	6
Commodity and other derivatives		—		2			3		5		—		1		28		29
Total current assets		—		6			6		12		—		7		28		35
Noncurrent assets:
Interest rate derivatives		—		49			—		49		—		83		2		85
Foreign currency derivatives		—		4	(1)		27		31		—		—		—		—
Cross currency derivatives		—		—			12		12		—		—		—		—
Commodity and other derivatives		—		4			16		20		—		—		—		—
Total noncurrent assets		—		57			55		112		—		83		2		85
Total assets	$	—	$	63		$	61	$	124	$	—	$	90	$	30	$	120
Liabilities
Current liabilities:
Interest rate derivatives	$	—	$	137	(1)	$	—	$	137	$	—	$	118	$	7	$	125
Cross currency derivatives		—		—			2		2		—		—		—		—
Foreign currency derivatives		—		13			—		13		—		3		—		3
Commodity and other derivatives		—		—			—		—		—		—		2		2
Total current liabilities		—		150			2		152		—		121		9		130
Long-term liabilities:
Interest rate derivatives		—		246	(1)		1		247		—		150		7		157
Cross currency derivatives		—		—			—		—		—		—		12		12
Foreign currency derivatives		—		15			8		23		—		2		—		2
Commodity and other derivatives		—		—			1		1		—		—		2		2
Total long-term liabilities		—		261			10		271		—		152		21		173
Total liabilities	$	—	$	411		$	12	$	423	$	—	$	273	$	30	$	303

⁽¹⁾  Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $1 million of current assets and $4 million of noncurrent assets on foreign currency derivatives and $19 million of current liabilities and $46 million of long-term liabilities for interest rate derivatives as of December 31, 2010.

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The following table sets forth the fair value and balance sheet classification of derivative instruments as of December 31, 2010 and 2009:

	December 31, 2010								December 31, 2009
	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Total		Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total
	(in millions)								(in millions)
Assets
Other current assets:
Foreign currency derivatives	$	—		$	7	(1)	$	7	$	—	$	6	$	6
Commodity & other derivatives		—			5			5		1		28		29
Total other current assets		—			12			12		1		34		35
Other assets:
Interest rate derivatives		49			—			49		85		—		85
Foreign currency derivatives		—			31	(1)		31		—		—		—
Cross currency derivatives		12			—			12		—		—		—
Commodity & other derivatives:		—			20			20		—		—		—
Total other assets—noncurrent		61			51			112		85		—		85
Total assets	$	61		$	63		$	124	$	86	$	34	$	120
Liabilities
Accrued and other liabilities:
Interest rate derivatives	$	126	(1)	$	11		$	137	$	115	$	10	$	125
Cross currency derivatives		2			—			2		—		—		—
Foreign currency derivatives		8			5			13		2		1		3
Commodity & other derivatives		—			—			—		—		2		2
Total accrued and other liabilities		136			16			152		117		13		130
Other long-term liabilities:
Interest rate derivatives		232	(1)		15			247		141		16		157
Cross currency derivatives		—			—			—		12		—		12
Foreign currency derivatives		—			23			23		—		2		2
Commodity & other derivatives		—			1			1		—		2		2
Total other long-term liabilities		232			39			271		153		20		173
Total liabilities	$	368		$	55		$	423	$	270	$	33	$	303

⁽¹⁾  Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $1 million of current assets and $4 million of noncurrent assets on foreign currency derivatives and $19 million of current liabilities and $46 million of long-term liabilities for interest rate derivatives as of December 31, 2010.

The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements. At December 31, 2010 and 2009, we held no cash collateral that we received from counterparties to our derivative positions. As we have not received collateral, our derivative assets are exposed to the credit risk of the respective counterparty and, due to this credit

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risk, the fair value of our derivative assets (as shown in the above two tables) have been reduced by a credit valuation adjustment. Also, at December 31, 2010 and 2009, we had no cash collateral posted with (held by) counterparties to our derivative positions.

The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of December 31, 2010 for the following types of derivative instruments:

	Accumulated Other Comprehensive Income (Loss)
	(in millions)
Interest rate derivatives	$	(88	)
Cross currency derivatives	$	(4	)
Foreign currency derivatives	$	(9	)

The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for interest rate hedges and cross currency swaps, as depreciation is recognized for interest rate hedges during construction, as foreign currency transaction gains and losses are recognized for hedges of foreign currency exposure, and as electricity sales and fuel purchases are recognized for hedges of forecasted electricity and fuel transactions. These balances are included in the consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.

For the years ended December 31, 2010, 2009 and 2008, pre-tax gains (losses) of $(1) million, $0 million, and $(1) million net of noncontrolling interests, respectively, were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter.

The following table sets forth the pre-tax gains (losses) recognized in accumulated other comprehensive loss (“AOCL”) and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the years ended December 31, 2010 and 2009:

	Gains (Losses) Recognized in AOCL						Gains (Losses) Reclassified from AOCL into Earnings
	2010			2009		Consolidated Statement of Operations	2010			2009
	(in millions)						(in millions)
Interest rate derivatives	$	(243	)(3)	$	49	Interest expense	$	(108	)(1)		$(72	)(1)
						Non-regulated cost of sales		(2	)		—
						Net equity in earnings of affiliates		(1	)		—	(2)
Cross currency derivatives		11			48	Interest expense		(1	)		2
						Foreign currency transaction gains (losses)		—			43
Foreign currency derivatives		(9	)		2	Foreign currency transaction gains (losses)		(3	)		—	(2)
Commodity derivatives—electricity		(8	)		120	Non-regulated revenue		—	(4)		3	(4)
Total	$	(249	)	$	219		$	(115	)		$(24	)

⁽¹⁾  Includes amounts that were reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting. Excludes $(113) million and $(35) million related to discontinued operations for the years ended December 31, 2010 and 2009, respectively.

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⁽²⁾  De minimis amount.

⁽³⁾  Includes $(29) million related to Cartagena for the year ended December 31, 2010, which was consolidated prospectively beginning January 1, 2010 under VIE accounting guidance.

⁽⁴⁾  Excludes $11 million and $190 million related to discontinued operations for the years ended December 31, 2010 and 2009, respectively.

Amounts recognized in AOCL due to derivative instruments that currently are, or previously were (but no longer are) qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, after income taxes, during the year ended December 31, 2008 are as follows:

	Balance, January 1			Reclassification to earnings		Change in fair value			Balance, December 31
	(in millions)
2008	$	(232	)	$	76	$	(107	)	$	(263	)

The following table sets forth the pre-tax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the years ended December 31, 2010 and 2009:

	Classification in Consolidated Statement of Operations	Gains (Losses) Recognized in Earnings
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense		$(15	)	$	(8	)
	Net equity in earnings of affiliates		—	(1)		(1	)
Cross currency derivatives	Interest expense		5			(11	)
Foreign currency derivatives	Foreign currency transaction gains (losses)		—	(1)		—	(1)
Total			$(10	)		$(20	)

⁽¹⁾  De minimis amount.

The Company recognized after-tax losses of $45 million, net of noncontrolling interests, related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the year ended December 31, 2008.

The following table sets forth the pre-tax gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the years ended December 31, 2010 and 2009:

	Classification in Consolidated Statement of Operations	Gains (Losses) Recognized  in Earnings
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	(7	)		$(25	)
Foreign exchange derivatives	Foreign currency transaction gains (losses)		(36	)		(38	)
	Net equity in earnings of affiliates		(2	)		—	(1)
Commodity & other derivatives	Non-regulated revenue		21			1
	Non-regulated cost of sales		5			(30	)
	Net equity in earnings of affiliates		—	(1)		—	(1)
Total			$(19	)		$(92	)

⁽¹⁾  De minimis amount.

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The Company recognized after-tax gains of $11 million net of noncontrolling interests related to the changes in fair value of derivative instruments not in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the year ended December 31, 2008.

In addition, IPL has two derivative instruments for which the gains and losses are accounted for in accordance with accounting standards for regulated operations, as regulatory assets or liabilities. Gains and losses on these derivatives due to changes in the fair value of these derivatives are probable of recovery through future rates and are initially recognized as an adjustment to the regulatory asset or liability and recognized through earnings when the related costs are recovered through IPL’s rates. Therefore, these gains and losses are excluded from the above table. The following table sets forth the change in regulatory assets and liabilities resulting from the change in the fair value of these derivatives for the years ended December 31, 2010 and 2009:

	2010			2009
	(in millions)
(Increase) decrease in regulatory assets	$	(3	)	$	—
Increase (decrease) in regulatory liabilities	$	1		$	(4	)

Credit Risk-Related Contingent Features

Gener, our generation business in Chile, has a cross currency swap agreement with a counterparty to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. The derivative agreements contain credit contingent provisions which would permit the counterparties with which Gener is in a net liability position to require collateral credit support when the fair value of the derivatives exceeds the unsecured thresholds established in the agreement. These thresholds vary based on Gener’s credit rating. If Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparties can demand immediate collateralization of the entire mark-to-market value of the swaps (excluding credit valuation adjustments) if Gener is in a net liability position. The mark-to-market value of the swaps was in a net asset position at December 31, 2010, and in a net liability position of $12 million at December 31, 2009. Gener posted zero and $25 million, respectively, in the form of a letter of credit to support these swaps.

7. INVESTMENTS IN AND ADVANCES TO AFFILIATES

The following table summarizes the relevant effective equity ownership interest and carrying values for the Company’s investments accounted for under the equity method as of December 31, 2010 and 2009.

		December 31,
Affiliate	Country	2010		2009		2010			2009
		Carrying Value				Ownership Interest %
		(in millions)
AES Solar Energy Ltd.	United States	$	256	$	224		50	%		50	%
AES Solar Power Ltd.	United States		8		—		50	%		—	%
Barry(1)	United Kingdom		—		—		100	%		100	%
Cartagena	Spain		N/A		—		N/A			71	%
CEMIG(2)	Brazil		22		—		72	%		10	%
Chigen affiliates	China		146		182		25	%		27	%
China Wind	China		69		52		49	%		49	%
Elsta	Netherlands		202		204		50	%		50	%
Guacolda	Chile		149		131		35	%		35	%
IC Ictas Energy Group	Turkey		151		104		51	%		51	%
InnoVent(1)	France		31		30		40	%		40	%
JHRH	China		39		—		35	%		—	%
OPGC	India		224		208		49	%		49	%
Trinidad Generation Unlimited(1)	Trinidad		20		16		10	%		10	%
Other affiliates			3		6		—	%		—	%
Total investments in and advances to affiliates		$	1,320	$	1,157

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⁽¹⁾  Represent VIEs in which we hold a variable interest, but are not the primary beneficiary.

⁽²⁾  The Company sold its interest in CEMIG during the year ended December 31, 2010; and retains its equity ownership in Cayman Energy Traders (“CET”). See additional discussion of the sale below.

AES Solar Energy Ltd.—In March 2008, the Company formed AES Solar Energy Ltd. (“AES Solar”), a joint venture with Riverstone Holdings LLC (“Riverstone”). AES Solar develops land-based solar photovoltaic panels that capture sunlight to convert into electricity that feed directly into power grids. AES Solar is accounted for under the equity method of accounting based on the Company’s 50% ownership and significant influence, but not control over the joint venture. Under the terms of the agreement, the Company and Riverstone may each provide up to $500 million of capital over the next five years. As of December 31, 2010, AES had invested approximately $312 million in the joint venture.

AES Solar Power Ltd.—In March 2010, the Company formed AES Solar Power Ltd. (“AES Solar Power”), a joint venture with Riverstone. AES Solar Power develops solar photovoltaic projects in the United States. AES Solar Power is accounted for under the equity method of accounting based on the Company’s 50% ownership and significant influence, but not control over the joint venture. Under the terms of the agreement, the Company and Riverstone may each provide up to $100 million of capital over the next five years. As of December 31, 2010, AES had invested approximately $11 million in the joint venture.

AES Barry Ltd.—The Company holds a 100% ownership interest in AES Barry Ltd. (“Barry”), a dormant entity in the United Kingdom that disposed of its generation and other operating assets. As a result of a debt agreement, no material financial or operating decisions can be made without the banks’ consent, and the Company does not control Barry. As of December 31, 2010 and 2009, other long-term liabilities included $53 million and $54 million, respectively, related to this debt agreement.

Cartagena Energia—The Company owns 71% of Cartagena Energia (“Cartagena”), a 1,199 MW power plant in Cartagena, Spain completed in November 2007. The Company’s initial investment in Cartagena was approximately $29 million. As a result of the accounting guidance issued in 2009 regarding VIEs, the Company consolidated Cartagena effective January 1, 2010. Cartagena is no longer accounted for under the equity method of accounting. For further discussion, see Note 1—General and Summary of Significant Accounting Policies.

CEMIG—During the second quarter of 2010, the Company, through its Brazilian subsidiary, Southern Electric Brasil Participações Ltda. (“SEB”), transferred its shares of Companhia Energética de Minas Gerais (“CEMIG”), an integrated utility in Minas Gerais, Brazil, to Andrade Gutierrez Concessões S.A. and an affiliated company (jointly referred to as, “AG”). AG also assumed SEB’s debt with Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”) in the amount of approximately $1.4 billion (the “BNDES Loan”) including all unpaid interest and penalties. In exchange, SEB received $25 million and obtained a full release from any claims of BNDES and originating from the BNDES Loan. See Note 12—Contingencies, for additional information regarding these claims and proceedings.

Prior to the transfer of shares, the Company, through SEB, a VIE, had a 14.8% voting interest in CEMIG. The Company holds its interest in SEB through its equity ownership in Cayman Energy Traders (“CET”), a holding company whose sole activity is its investment in SEB. Although our interest in CEMIG was below 20%, AES had significant influence over the operational and financial policies of CEMIG through representation on the board of directors of CEMIG. In 2002, the Company determined there was an other-than-temporary impairment of its investment in CEMIG and wrote it down to fair market value, $155 million. Additionally, AES established a valuation allowance against a deferred tax asset related to its investment in CEMIG. The total amount of these charges, net of tax, was $587 million. As a result, the Company’s investment in CEMIG was a $484 million net liability at December 31, 2009 and was included in “Other long-term liabilities” on the Consolidated Balance Sheet. The Company discontinued the application of the equity method in accordance with its accounting policy regarding equity method investments.

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The consummation of the share purchase and sale agreement along with AG’s assumption of the BNDES Loan in June 2010 resulted in the reversal of the Company’s net long-term liability along with the associated cumulative translation adjustment, resulting in the recognition of a $115 million pre-tax gain reflected in “Net equity in earnings of affiliates” on the Consolidated Statement of Operations for the year ended December 31, 2010. Additionally, $70 million of net tax expense resulting from the CEMIG sale transaction was recorded as “income tax expense,” rather than equity earnings, since the expense is attributable to a consolidated corporate level partner in the CEMIG investment.

The Company retains its ownership in CET.

China Wind—In May 2007, the Company entered into a joint venture with Guohua Energy Investment Co. Ltd. (“Guohua”) for a 49% interest in Guohua AES (Huanghua) Wind Power Co., Ltd. (“AES Huanghua”) that is primarily engaged to develop, construct, own and operate wind projects in Huanghua. Huanghua I went live in the third quarter of 2009 and Huanghua II went live in April 2010. In the second and third quarters of 2008, the Company acquired a 49% interest in Guohua AES (“Hulunbeier”) Wind Power Co., Ltd. and entered into joint venture agreements with Guohua for 49% interest in Guohua AES (“Xinba’erhu”) Wind Power Co., Ltd. (“Dong Qi”) which went live in June 2010 and Guohua AES (“Chenba’erhu”) Wind Power Co., Ltd. (“Chen Qi”) which is expected to go live in 2011. The Company invested approximately $12 million in the aforementioned projects in 2010, bringing the cumulative investment to $62 million.

Jianghe Rural Electrification Development Co., LTD (“JHRH”)— On June 3, 2010, the Company entered into an agreement to acquire a 35% ownership in this joint venture which operates seven hydro plants in China. The agreement entitled the Company to acquire up to a 49% interest. The purchase of an additional 14% ownership is expected to be completed by May 2011.

Trinidad Generation Unlimited—In 2007, the Company began pursuing a development project to construct and operate a 720 MW combined cycle power plant in Trinidad through its wholly owned subsidiary, Trinidad Generation Unlimited (“TGU”). In July 2008, a shareholder agreement was executed establishing the Company’s ownership interest in TGU at 60% with the remaining 40% interest held by the Government of Trinidad and Tobago. Although the Company’s ownership in TGU was reduced to 10% in 2009, the Company continues to account for its investment in Trinidad as an equity method investment because AES continues to exercise significant influence through the supermajority vote requirement for any significant future project development activities.

Summarized Financial Information

The following tables summarize financial information of the Company’s 50%-or-less owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method.

	50%-or-less Owned Affiliates								Majority-Owned Unconsolidated Subsidiaries
Years ended December 31,	2010			2009			2008		2010		2009			2008
	(in millions)								(in millions)
Revenue	$	1,341		$	1,229		$	1,180		$20		$158		$	170
Gross margin		207			240			274		18		71			61
Net income (loss)		100			110			83		7		(5	)		(4	)
December 31,	2010			2009					2010		2009
	(in millions)								(in millions)
Current assets	$	948		$	882				$	114	$	142
Noncurrent assets		4,131			3,543					646		1,140
Current liabilities		687			528					144		153
Noncurrent liabilities		1,597			1,406					242		1,055
Noncontrolling interests		(206	)		(191	)				125		(24	)
Stockholders’ equity		3,001			2,682					249		98

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At December 31, 2010, retained earnings included $168 million related to the undistributed earnings of the Company’s 50%-or-less owned affiliates. Distributions received from these affiliates were $49 million, $35 million and $50 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Refer to Item 1 of this Form 8-K for additional information on these affiliates.

8. GOODWILL AND OTHER INTANGIBLE ASSETS

The following table summarizes the changes in the carrying amount of goodwill, by segment for the years ended December 31, 2010, 2009 and 2008. There was no goodwill associated with our North America—Utilities segment during the years ended December 31, 2010, 2009 and 2008.

	Latin America - Generation			Latin America - Utilities			North America - Generation			Europe - Generation			Asia - Generation			Corporate and Other			Total
Balance as of December 31, 2008
Goodwill	$	926		$	140		$	121		$	127		$	78		$	101		$	1,493
Accumulated impairment losses		(24	)		(7	)		(20	)		(19	)		—			(2	)		(72	)
Net balance		902			133			101			108			78			99			1,421
Impairment losses		—			—			—			(118	)		—			(4	)		(122	)
Goodwill associated with the sale of a business		—			—			—			—			(2	)		—			(2	)
Foreign currency translation and other		—			—			(10	)		10			2			—			2
Balance as of December 31, 2009
Goodwill		926			140			111			137			78			101			1,493
Accumulated impairment losses		(24	)		(7	)		(20	)		(137	)		—			(6	)		(194	)
Net balance		902			133			91			—			78			95			1,299
Impairment losses		—			—			(18	)		—			—			(3	)		(21	)
Foreign currency translation and other		—			—			(10	)		—			3			—			(7	)
Balance as of December 31, 2010
Goodwill		926			140			101			137			81			101			1,486
Accumulated impairment losses		(24	)		(7	)		(38	)		(137	)		—			(9	)		(215	)
Net balance	$	902		$	133		$	63		$	—		$	81		$	92		$	1,271

During the third quarter of 2010, Deepwater, our petcoke-fired merchant generation facility in Texas, reported in the North America Generation segment, incurred a goodwill impairment of $18 million. The Company determined that there was an impairment indicator for Deepwater’s goodwill. This determination was based primarily on the fact that Deepwater did not operate for more than 30 days in the third quarter of 2010, incurred current operating and cash flow losses and, at that time, was forecasting operating and cash flow losses for the remainder of 2010 through 2014. This resulted from a decrease in future power price expectations and an increase in petcoke prices affecting the market. The Company performed the two-step goodwill impairment test of Deepwater’s goodwill as of August 31, 2010 and recognized the entire $18 million carrying amount of goodwill as goodwill impairment.

In 2009, Kilroot, our subsidiary in the United Kingdom, reported in the Europe Generation segment, incurred a goodwill impairment loss of $118 million. Kilroot is a generation plant fired primarily by coal. Factors contributing to the impairment included: reduced profit expectations based on latest estimates of future

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commodity prices and reduced expectations on the recovery of cash flows on the existing plant following the Company’s decision to forgo capital expenditures to meet emission allowance requirements taking effect in 2024. Additionally, one of our subsidiaries located in the Ukraine and reported within “Corporate and Other” incurred a goodwill impairment loss of $4 million. For the year ended December 31, 2008, the Company had no goodwill impairment.

The following tables summarize the balances comprising other intangible assets in the accompanying Consolidated Balance Sheets as of December 31, 2010 and 2009:

	December 31, 2010							December 31, 2009
	Gross Balance		Accumulated Amortization			Net Balance		Gross Balance		Accumulated Amortization			Net Balance
	(in millions)							(in millions)
Subject to Amortization
Project development rights(1)	$	141	$	—		$	141	$	—	$	—		$	—
Sales concessions		162		(88	)		74		167		(84	)		83
Contractual payment rights(2)		65		(4	)		61		—		—			—
Land use rights		50		(2	)		48		48		(1	)		47
Management rights		66		(30	)		36		64		(27	)		37
Emission allowances(3)		26		—			26		11		—			11
Other(4)		94		(33	)		61		118		(28	)		90
Subtotal		604		(157	)		447		408		(140	)		268
Indefinite-Lived Intangible Assets
Land use rights		51		—			51		50		—			50
Emission allowances(5)		8		—			8		15		—			15
Other		5		—			5		—		—			—
Subtotal		64		—			64		65		—			65
Total	$	668	$	(157	)	$	511	$	473	$	(140	)	$	333

⁽¹⁾  Represent development rights, including but not limited to, land control, various permits and right to acquire equity interests in development projects resulting from asset acquisitions by our Wind group.

⁽²⁾  Represent legal rights to receive system reliability payments from the regulator.

⁽³⁾  Acquired or purchased emission allowances are expensed when utilized and included in net income for the year.

⁽⁴⁾  Consists of various intangible assets including PPAs and transmission rights, none of which is individually significant.

⁽⁵⁾  Represent perpetual emission allowances without an expiration date.

The following table summarizes, by category, intangible assets acquired during the years ended December 31, 2010 and 2009:

	December 31, 2010
	Amount		Subject to Amortization/ Indefinite-Lived		Weighted Average Amortization Period		Amortization Method
	(in millions)				(in years)
Project development rights	$	141		Subject to amortization		Various		Straight line
Contractual payment rights		65		Subject to amortization		10		Straight line
Emission allowances		14		Subject to amortization		Various		As utilized
Land use rights		7		Indefinite-lived		N/A		N/A
Total	$	227

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	December 31, 2009
	Amount		Subject to Amortization/ Indefinite-Lived		Weighted Average Amortization Period		Amortization Method
	(in millions)				(in years)
Emission allowances	$	4		Subject to amortization		Various		As utilized
Land use rights		4		Indefinite-lived		N/A		N/A
Other		1		Subject to amortization		35		—
Total	$	9

In 2009, the Company reclassified $42 million from other assets into intangible assets at a subsidiary in Latin America.

The following table summarizes the estimated amortization expense, broken down by intangible asset category, for 2011 through 2015:

	Estimated amortization expense
	2011		2012		2013		2014		2015
	(in millions)
Contractual payment rights	$	9	$	9	$	9	$	9	$	9
Sales concessions		6		6		6		6		6
All other		7		6		4		3		3
Total	$	22	$	21	$	19	$	18	$	18

Intangible asset amortization expense was $14 million, $17 million and $11 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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9. REGULATORY ASSETS & LIABILITIES

The Company has recorded regulatory assets and liabilities that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:

	December 31,
	2010		2009		Recovery Period
	(in millions)
REGULATORY ASSETS
Current regulatory assets:
Brazil tariff recoveries:(1)
Energy purchases	$	62	$	144		Over tariff reset period
Transmission costs, regulatory fees and other		82		120		Over tariff reset period
El Salvador tariff recoveries(2)		67		125		Over tariff reset period
Other(3)		1		6		Various
Total current regulatory assets		212		395
Noncurrent regulatory assets:
Defined benefit pension obligations at IPL(4)(5)		235		217		Various
Income taxes recoverable from customers(4)(6)		66		70		Various
Brazil tariff recoveries:(1)
Energy purchases		18		22		Over tariff reset period
Transmission costs, regulatory fees and other		32		30		Over tariff reset period
Other(3)		119		111		Various
Total noncurrent regulatory assets		470		450
TOTAL REGULATORY ASSETS	$	682	$	845
REGULATORY LIABILITIES
Current regulatory liabilities:
Efficiency program costs(7)	$	58	$	133		Over tariff reset period
Brazil tariff recoveries:(1)
Energy purchases		118		61		Over tariff reset period
Transmission costs, regulatory fees and other		71		67		Over tariff reset period
Other(8)		39		35		Various
Total current regulatory liabilities		286		296
Noncurrent regulatory liabilities:
Asset retirement obligations(9)		509		482		Over life of assets
Brazil special obligations(10)		435		402		To be determined
Brazil tariff recoveries:(1)
Energy purchases		69		42		Over tariff reset period
Transmission costs, regulatory fees and other		57		35		Over tariff reset period
Efficiency program costs(7)		54		4		Over tariff reset period
Other(8)		13		17		Various
Total noncurrent regulatory liabilities		1,137		982
TOTAL REGULATORY LIABILITIES	$	1,423	$	1,278

⁽¹⁾  Recoverable per National Electric Energy Agency (“ANEEL”) regulations through the Annual Tariff Adjustment (“IRT”). These costs are generally non-controllable costs and primarily consist of purchased electricity, energy transmission costs and sector costs that are considered volatile. These costs are recovered in 24 installments through the annual IRT process and are amortized over the tariff reset period.

⁽²⁾  Deferred fuel costs incurred by our El Salvador subsidiaries associated with purchase of energy from the El Salvador spot market and the power generation plants. In El Salvador, the deferred fuel adjustment

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represents the variance between the actual fuel costs and the fuel costs recovered in the tariffs. The variance is recovered semi-annually at the tariff reset period.

⁽³⁾  Includes assets with and without a rate of return. All current regulatory assets earned a rate of return as of December 31, 2010 and 2009. Other noncurrent regulatory assets that did not earn a rate of return were $95 million and $90 million, as of December 31, 2010 and 2009, respectively. Those without a rate of return that are recoverable primarily consist of transmission service costs and other administrative costs from IPL’s participation in the Midwest ISO market. Recovery of costs is probable, but the timing is not yet determined.

⁽⁴⁾  Past expenditures on which the Company does not earn a rate of return.

⁽⁵⁾  The regulatory accounting standards allow the defined pension and postretirement benefit obligation to be recorded as a regulatory asset equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Pension expense is recognized based on the plan’s actuarially determined pension liability. Recovery of costs is probable, but not yet determined. Pension contributions made by our Brazilian subsidiaries are not included in regulatory assets as those contributions are not covered by the established tariff in Brazil.

⁽⁶⁾  Probable of recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This amount is expected to be recovered, without interest, over the period as book-tax temporary differences reverse and become current taxes.

⁽⁷⁾  Payments received for costs expected to be incurred to improve the efficiency of our plants in Brazil that are refunded as part of the IRT.

⁽⁸⁾  Other Current and Noncurrent Regulatory Liabilities consist of:

• Deferred fuel costs, which are expected to be refunded to customers as a credit against future fuel adjustment charges. In the United States, deferred fuel costs at IPL represent variances between estimated and actual fuel and purchased power costs. IPL is required to refund overestimated fuel and purchased power costs in future rates.

• Penalties and fees from regulators at our Brazilian subsidiaries.

• Financial transmission rights used to hedge exposure in the Midwest ISO market that are credited per specific rate orders.

• The cost incurred by electricity generators due to variance in energy prices during rationing periods (Free Energy). Our Brazilian subsidiaries are authorized to recover or refund this cost associated with monthly energy price variances between the wholesale energy market prices owed to the power generation plants producing Free Energy and the capped price reimbursed by the local distribution companies which are passed through to the final customers through energy tariffs.

⁽⁹⁾  Obligations for removal costs which do not have an associated legal retirement obligation as defined by the accounting standards on asset retirement obligations.

⁽¹⁰⁾  Obligations established by ANEEL in Brazil associated with electric utility concessions and represent amounts received from customers or donations not subject to return. These donations are allocated to support energy network expansion and to improve utility operations to meet customers’ needs. The term of the obligation is established by ANEEL. Settlement shall occur when the concession ends.

The current regulatory assets and liabilities are recorded in “Other current assets” and “Accrued and other liabilities,” respectively, on the accompanying Consolidated Balance Sheets. The noncurrent regulatory assets and liabilities are recorded in “Other assets” and “Other long-term liabilities,” respectively, in the accompanying Consolidated Balance Sheets.

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The following table summarizes regulatory assets by region as of December 31, 2010 and 2009:

	December 31,
	2010		2009
	(in millions)
Latin America	$	265	$	445
North America		417		400
Total regulatory assets	$	682	$	845

The following table summarizes regulatory liabilities by region as of December 31, 2010 and 2009:

	December 31,
	2010		2009
	(in millions)
Latin America	$	897	$	772
North America		526		506
Total regulatory liabilities	$	1,423	$	1,278

10. DEBT

The Company has two types of debt reported on its Consolidated Balance Sheets: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for the construction and acquisition of electric power plants, wind projects, distribution companies and other project-related investments at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. Absent guarantees, intercompany loans or other credit support, the default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries, though the Company’s equity investments and/or subordinated loans to projects (if any) are at risk. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisitions, including serving as funding for equity investments or loans to the affiliates. The Parent Company’s debt is, among other things, recourse to the Parent Company and is structurally subordinated to the affiliates’ debt.

The following table summarizes the carrying amount and estimated fair values of the Company’s recourse and non-recourse debt as of December 31, 2010 and 2009:

	December 31,
	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Non-recourse debt	$	14,939	$	15,269	$	13,828	$	14,175
Recourse debt		4,612		4,868		5,515		5,603
Total debt	$	19,551	$	20,137	$	19,343	$	19,778

Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon the type of loan. The fair value of fixed rate loans is estimated using quoted market prices, if available or a discounted cash flow analysis. In the discounted cash flow analysis, the discount rate is based on the credit rating of the individual debt instruments if available, or the credit rating of the subsidiary. If the subsidiary’s credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry specific factors. For subsidiaries located outside of the U.S., in the

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event that the country rating is lower than the credit rating previously determined, the country rating is used for the purposes of the discounted cash flow analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date.

The estimated fair value was determined using available market information as of December 31, 2010 and 2009. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2010.

NON-RECOURSE DEBT

The following table summarizes the carrying amount and terms of non-recourse debt as of December 31, 2010 and 2009:

	Interest Rate(1)					December 31,
NON-RECOURSE DEBT				Maturity		2010			2009
						(in millions)
VARIABLE RATE:(2)
Bank loans		2.39	%		2011 – 2027	$	3,836		$	3,109
Notes and bonds		12.14	%		2011 – 2020		2,982			1,922
Debt to (or guaranteed by) multilateral, export credit agencies or development banks(3)		2.95	%		2011 – 2027		1,848			1,679
Other		4.13	%		2011 – 2038		365			922
FIXED RATE:
Bank loans		8.44	%		2011 – 2023		424			446
Notes and bonds		7.28	%		2011 – 2037		4,830			5,265
Debt to (or guaranteed by) multilateral, export credit agencies or development banks(3)		6.41	%		2011 – 2027		467			406
Other		6.31	%		2011 – 2039		187			79
SUBTOTAL						$	14,939	(4)	$	13,828	(4)
Less: Current maturities							(2,567	)		(1,707	)
TOTAL						$	12,372		$	12,121

⁽¹⁾  Weighted average interest rate at December 31, 2010.

⁽²⁾  The Company has interest rate swaps and interest rate option agreements in an aggregate notional principal amount of approximately $4.3 billion on non-recourse debt outstanding at December 31, 2010. The swap agreements economically change the variable interest rates on the portion of the debt covered by the notional amounts to fixed rates ranging from approximately 0.71% to 6.98%. The option agreements fix interest rates within a range from 4.03% to 7.00%. The agreements expire at various dates from 2016 through 2027.

⁽³⁾  Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.

⁽⁴⁾  Non-recourse debt of $182 million and $902 million as of December 31, 2010 and 2009, respectively, was excluded from non-recourse debt and included in current and long-term liabilities of held for sale and discontinued businesses in the accompanying Consolidated Balance Sheets.

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Non-recourse debt as of December 31, 2010 is scheduled to reach maturity as set forth in the table below:

December 31,	Annual Maturities
	(in millions)
2011	$	2,567
2012		646
2013		941
2014		1,826
2015		1,124
Thereafter		7,835
Total non-recourse debt	$	14,939

As of December 31, 2010, AES subsidiaries with facilities under construction had a total of approximately $432 million of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $664 million in a number of available but unused committed revolving credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used in one or more of the following ways: solely for borrowings; solely for letters of credit; or a combination of these uses. The weighted average interest rate on borrowings from these facilities was 3.24% at December 31, 2010.

Non-Recourse Debt Covenants, Restrictions and Defaults

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

As of December 31, 2010 and 2009, approximately $693 million and $548 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these amounts were included within “Restricted cash” and “Debt service reserves and other deposits” in the accompanying Consolidated Balance Sheets.

Various lender and governmental provisions restrict the ability of certain of the Company’s subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $4.6 billion at December 31, 2010.

The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of December 31, 2010 and is included in the current portion of non-recourse debt unless otherwise indicated:

	Primary Nature of  Default		December 31, 2010
Subsidiary			Default		Net Assets
			(in millions)
Maritza		Covenant	$	986	$	262
Sonel		Covenant		390		357
Kelanitissa		Covenant		28		31
Aixi		Payment		4		(8	)
Total			$	1,408

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of December 31, 2010 in order for such defaults to trigger

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an event of default or permit acceleration under such indebtedness. The bankruptcy or acceleration of material amounts of debt at such entities would cause a cross default under the recourse senior secured credit facility. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position or results of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon a bankruptcy or acceleration of its non-recourse debt trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.

RECOURSE DEBT

The following table summarizes the carrying amount and terms of recourse debt of the Company as of December 31, 2010 and 2009:

				December 31,
RECOURSE DEBT	Interest Rate	Maturity		2010			2009
				(in millions)
Senior Unsecured Note	9.375%		2010	$	—		$	214
Senior Secured Term Loan	LIBOR + 1.75%		2011		200			200
Senior Unsecured Note	8.875%		2011		129			129
Senior Unsecured Note	8.375%		2011		134			139
Second Priority Senior Secured Note	8.75%		2013		—			690
Senior Unsecured Note	7.75%		2014		500			500
Senior Unsecured Note	7.75%		2015		500			500
Senior Unsecured Note	9.75%		2016		535			535
Senior Unsecured Note	8.00%		2017		1,500			1,500
Senior Unsecured Note	8.00%		2020		625			625
Term Convertible Trust Securities	6.75%		2029		517			517
Unamortized discounts					(28	)		(34	)
SUBTOTAL				$	4,612		$	5,515
Less: Current maturities					(463	)		(214	)
Total				$	4,149		$	5,301

Recourse debt as of December 31, 2010 is scheduled to reach maturity as set forth in the table below:

December 31,	Annual Maturities
	(in millions)
2011	$	463
2012		—
2013		—
2014		497
2015		500
Thereafter		3,152
Total recourse debt	$	4,612

Recourse Debt Transactions

During 2010, the Company redeemed $690 million aggregate principal of its 8.75% Second Priority Senior Secured Notes due 2013 (“the 2013 Notes”). The 2013 Notes were redeemed at a redemption price equal to 101.458% of the principal amount redeemed. The Company recognized a pre-tax loss on the redemption of the 2013 Notes of $15 million for the year ended December 31, 2010, which is included in “Other expense” in the accompanying Consolidated Statement of Operations.

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On July 29, 2010, the Company entered into a second amendment (“Amendment No. 2”) to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008, among the Company, various subsidiary guarantors and various lending institutions (the “Existing Credit Agreement”) that amends and restates the Existing Credit Agreement (as so amended and restated by Amendment No. 2, the “Fifth Amended and Restated Credit Agreement”). The Fifth Amended and Restated Credit Agreement adjusted the terms and conditions of the Existing Credit Agreement, including the following changes:

• the aggregate commitment for the revolving credit loan facility was increased to $800 million;

• the final maturity date of the revolving credit loan facility was extended to January 29, 2015;

• changes to the facility fee applicable to the revolving credit loan facility;

• the interest rate margin applicable to the revolving credit loan facility is now based on the credit rating assigned to the loans under the credit agreement, with pricing currently at LIBOR + 3.00%;

• there is an undrawn fee of 0.625% per annum;

• the Company may incur a combination of additional term loan and revolver commitments so long as total term loan and revolver commitments (including those currently outstanding) do not exceed $1.4 billion; and

• the negative pledge (i.e., a cap on first lien debt) of $3.0 billion.

Recourse Debt Covenants and Guarantees

Certain of the Company’s obligations under the senior secured credit facility are guaranteed by its direct subsidiaries through which the Company owns its interests in the AES Shady Point, AES Hawaii, AES Warrior Run and AES Eastern Energy businesses. The Company’s obligations under the senior secured credit facility are, subject to certain exceptions, secured by:

(i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company; and

(ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.

The senior secured credit facility is subject to mandatory prepayment under certain circumstances, including the sale of a guarantor subsidiary. In such a situation, the net cash proceeds from the sale of a Guarantor or any of its subsidiaries must be applied pro rata to repay the term loan using 60% of net cash proceeds, reduced to 50% when and if the parent’s recourse debt to cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption.

The senior secured credit facility contains customary covenants and restrictions on the Company’s ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.

The senior secured credit facility also contains financial covenants requiring the Company to maintain certain financial ratios including a cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company’s adjusted operating cash flow to the Company’s interest charges related to recourse debt of 1.3× must be maintained at all times and a recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company’s total recourse debt to the Company’s adjusted operating cash flow must not exceed a maximum at any time of calculation, or 7.5× at December 31, 2010.

The terms of the Company’s senior unsecured notes and senior secured credit facility contain certain covenants including, without limitation, limitation on the Company’s ability to incur liens or enter into sale and leaseback transactions.

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TERM CONVERTIBLE TRUST SECURITIES

Between 1999 and 2000, AES Trust III, a wholly owned special purpose business trust, issued approximately 10.35 million of $3.375 Term Convertible Preferred Securities (“TECONS”) (liquidation value $50) for total proceeds of $517 million and concurrently purchased $517 million of 6.75% Junior Subordinated Convertible Debentures due 2029 (the “6.75% Debentures” of the Company). The TECONS are consolidated and classified as long-term recourse debt on the Company’s Consolidated Balance Sheet.

AES, at its option, can redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by AES Trust III, currently for $50 per TECON. The TECONS must be redeemed upon maturity of the 6.75% Debentures. The TECONS are convertible into the common stock of AES at each holder’s option prior to October 15, 2029 at the rate of 1.4216, representing a conversion price of $35.17 per share. The maximum number of shares of common stock AES would be required to issue should all holders decide to convert their securities would be 14.7 million shares.

Dividends on the TECONS are payable quarterly at an annual rate of 6.75%. The Trust is permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the TECONS would accumulate quarterly and accrue interest, and the Company may not declare or pay dividends on its common stock. AES has not exercised the option to defer any dividends at this time and all dividends due under the Trust have been paid.

AES Trust III is a VIE under the relevant consolidation accounting guidance. AES’ obligations under the 6.75% Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by AES of the TECON Trusts’ obligations. Accordingly, AES consolidates AES Trust III. As of December 31, 2010 and 2009, the sole assets of AES Trust III are the 6.75% Debentures.

11. COMMITMENTS

The following disclosures exclude any businesses classified as discontinued operations or held-for-sale.

OPERATING LEASES—As of December 31, 2010, the Company was obligated under long-term non-cancelable operating leases, primarily for certain transmission lines, office rental and site leases. Rental expense for lease commitments under these operating leases for the years ended December 31, 2010, 2009 and 2008 was $58 million, $62 million and $73 million, respectively.

The table below sets forth the future minimum lease commitments under these operating leases as of December 31, 2010 for 2011 through 2015 and thereafter:

December 31,	Future Commitments for Operating Leases
	(in millions)
2011	$	56
2012		55
2013		56
2014		54
2015		50
Thereafter		647
Total	$	918

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CAPITAL LEASES—Several AES subsidiaries lease operating and office equipment and vehicles that are considered capital lease transactions. These capital leases are recognized in Property, Plant and Equipment within “Electric generation and distribution assets” and primarily relate to transmission lines at our subsidiaries in Brazil. The gross value of the leased assets as of December 31, 2010 and 2009 was $98 million and $106 million, respectively.

The following table summarizes the future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2010 for 2011 through 2015 and thereafter:

December 31,	Future Minimum Lease Payments
	(in millions)
2011	$	17
2012		14
2013		12
2014		11
2015		10
Thereafter		142
Total	$	206
Less: Imputed interest		127
Present value of total minimum lease payments	$	79

CONTRACTS—Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties that primarily include energy auction agreements at our Brazil subsidiaries with extended terms from 2011 through 2042 and in some cases are subject to variable quantities or prices. Purchases in the years ended December 31, 2010, 2009 and 2008 were approximately $2.4 billion, $2.1 billion and $1.5 billion, respectively.

The table below sets forth the future minimum commitments under these electricity purchase contracts at December 31, 2010 for 2011 through 2015 and thereafter:

December 31,	Future Commitments for Electricity Purchase Contracts
	(in millions)
2011	$	3,055
2012		3,273
2013		2,845
2014		2,569
2015		2,642
Thereafter		37,776
Total	$	52,160

Operating subsidiaries of the Company have entered into various long-term contracts for the purchase of fuel subject to termination only in certain limited circumstances and in some cases are subject to variable quantities or prices. Purchases in the years ended December 31, 2010, 2009 and 2008 were $1.8 billion, $1.3 billion and $1.1 billion, respectively.

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The table below sets forth the future minimum commitments under these fuel contracts as of December 31, 2010 for 2011 through 2015 and thereafter:

December 31,	Future Commitments for Fuel Contracts
	(in millions)
2011	$	1,530
2012		1,144
2013		733
2014		552
2015		454
Thereafter		4,391
Total	$	8,804

The Company’s subsidiaries have entered into other various long-term contracts. These contracts are mainly for construction projects, service and maintenance, transmission of electricity and other operation services. Payments under these contracts for the years ended December 31, 2010, 2009 and 2008 were $1.7 billion, $2.8 billion and $1.9 billion, respectively.

The table below sets forth the future minimum commitments under these other purchase contracts as of December 31, 2010 for 2011 through 2015 and thereafter:

December 31,	Future Commitments for Other Purchase Contracts
	(in millions)
2011	$	1,628
2012		1,357
2013		1,246
2014		1,540
2015		1,212
Thereafter		14,057
Total	$	21,040

12. CONTINGENCIES

ENVIRONMENTAL LIABILITIES

The Company will record liabilities when an environmental assessment indicates that remedial actions are probable and that costs can be reasonably estimated. As of December 31, 2010, the Company has recognized liabilities of $21 million for estimated environmental remediation costs and potential fines and penalties. These are reported on the Consolidated Balance Sheet within “accrued and other liabilities” and “other long-term liabilities.” Due to the uncertainties associated with environmental assessment and remediation activities, actual future costs of compliance or remediation could be higher or lower than the amount currently accrued. Certain expenditures may also be capitalized in accordance with the Company’s property, plant and equipment policies and are excluded from environmental liabilities in accordance with accounting guidelines. Any capital expenditures incurred of this nature would be incremental to amounts reserved.

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ENVIRONMENTAL REGULATION

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air emissions, such as SO₂, NO_X, particulate matter and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our United States or international subsidiaries, and our consolidated results of operations. For further information about environmental risks, see Item 1A.—Risk Factors of the 2010 Form 10-K, “Our businesses are subject to stringent environmental laws and regulations,” “Our businesses are subject to enforcement initiatives from environmental regulatory agencies,” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.”

Legislation and Regulation of GHG Emissions

Currently in the United States there is no Federal legislation establishing mandatory GHG emissions reduction programs (including CO₂) affecting the electric power generation facilities of the Company’s subsidiaries. There are numerous state programs regulating GHG emissions from electric power generation facilities and there is a possibility that federal GHG legislation will be enacted within the next several years. Further, the EPA has adopted regulations pertaining to GHG emissions and has announced its intention to propose new regulations for electric generating units under Section 111 of the United States Clean Air Act (“CAA”).

Potential United States Federal GHG Legislation. Federal legislation passed the United States House of Representatives in 2009 that, if adopted, would impose a nationwide cap-and-trade program to reduce GHG emissions. In the United States Senate, several different draft bills pertaining to GHG legislation have been considered at various times since then, including comprehensive GHG legislation similar to the legislation that passed the United States House of Representatives and more limited legislation focusing only on the utility and electric generation industry. It is uncertain whether any such legislation or any new legislation pertaining to GHG emissions will be voted on or passed by the Senate. If any legislation is passed by the Senate, it is uncertain whether such legislation will be reconciled with the House of Representatives’ legislation and ultimately enacted into law. However, if any such legislation is enacted, the impact could be material to the Company.

EPA GHG Regulation. The EPA promulgated regulations governing GHG emissions from automobiles under the CAA. The effect of the EPA’s regulation of GHG emissions from mobile sources is that certain provisions of the CAA will also apply to GHG emissions from existing stationary sources, including many United States power plants. Beginning on January 2, 2011, construction of new stationary sources and modifications to existing stationary sources that result in increased GHG emissions, became subject to permitting requirements under the prevention of significant deterioration (“PSD”) program of the CAA. The PSD program, as currently applicable to GHG emissions, requires sources that emit above a certain threshold of GHGs to obtain PSD permits prior to commencement of new construction or modifications to existing facilities. In addition, major sources of GHG emissions may be required to amend, or obtain new, Title V-air permits under the CAA to reflect any new applicable GHG emissions requirements for new construction or for modifications to existing facilities.

The EPA promulgated a final rule on June 3, 2010, (the “Tailoring Rule”) that sets thresholds for GHG emissions that would trigger PSD permitting requirements. The Tailoring Rule, which became effective in January of 2011, provides that sources already subject to PSD permitting requirements need to install Best

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Available Control Technology (“BACT”) for greenhouse gases if a proposed modification would result in the increase of more than 75,000 tons per year of GHG emissions. Also, under the Tailoring Rule, commencing in July of 2011, any new sources of GHG emissions that would emit over 100,000 tons per year of GHG emissions, in addition to any modification that would result in GHG emissions exceeding 75,000 tons per year would require PSD review and be subject to related permitting requirements. The EPA anticipates that it will adjust downward the permitting thresholds of 100,000 tons and 75,000 tons for new sources and modifications, respectively, in future rulemaking actions. The Tailoring Rule substantially reduces the number of sources subject to PSD requirements for GHG emissions and the number of sources required to obtain Title V air permits, although new thermal power plants may still be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the 100,000 ton threshold noted above. The 75,000 ton threshold for increased GHG emissions from modifications to existing sources may reduce the likelihood that future modifications to plants owned by some of our United States subsidiaries would trigger PSD requirements, although some projects that would expand capacity or electric output are likely to exceed this threshold, and in any such cases the capital expenditures necessary to comply with the PSD requirements could be significant.

In December 2010, the EPA entered into a settlement agreement with several states and environmental groups to resolve a petition for review challenging EPA’s new source performance standards (“NSPS”) rulemaking for electric utility steam generating units (“EUSGUs”) based on the NSPS’ failure to address GHG emissions. Under the settlement agreement, the EPA has committed to propose GHG emissions standards for EUSGUs by July 26, 2011 and to finalize GHG emissions standards for EUSGUs by May 26, 2012. The NSPS will establish GHG emission standards for newly constructed and reconstructed EUSGUs. The NSPS also will establish guidelines regarding the best system for achieving further GHG emissions reductions from EUSGUs and, based on such guidelines, individual states will be required to submit a plan to the EPA to establish GHG emission standards for existing EUSGUs within their state. It is impossible to estimate the impact and compliance cost associated with any future NSPS applicable to EUSGUs until such regulations are finalized. However, the compliance costs could have a material and adverse impact on our consolidated financial condition or results of operations.

Regional Greenhouse Gas Initiative. The primary regulation of GHG emissions affecting the United States plants of the Company’s subsidiaries has been through the Regional Greenhouse Gas Initiative (“RGGI”). Under RGGI, ten Northeastern States have coordinated to establish rules that require reductions in CO₂ emissions from power plant operations within those states through a cap-and-trade program. States participating in RGGI in which our subsidiaries have generating facilities include Connecticut, Maryland, New York and New Jersey. Under RGGI, power plants must acquire one carbon allowance through auction or in the emission trading markets for each ton of CO₂ emitted.

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 CO₂ 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 CO₂ 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 in 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 Kyoto Protocol is not extended or replaced by another agreement. The Company’s subsidiaries operate eight 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. At this time, the Company cannot determine fully whether achieving and maintaining compliance with the NAPs, to which its subsidiaries are subject, will have a material impact on its consolidated operations or results. 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. However, one such contract counterparty,

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GDF-Suez, is currently disputing these provisions with AES Energia Cartagena S.R.L. The matter has been submitted to arbitration and the parties are currently awaiting a decision. See Item 3.—Legal Proceedings in the 2010 Form 10-K for more detail regarding this dispute. In connection with this dispute or any similar dispute that might arise with other contract counterparties, there can be no assurance that the Company and/or the relevant subsidiary would prevail, or that the failure to prevail in any such dispute will not have a material adverse effect on the Company and its financial condition or consolidated results of operations.

On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires the industrialized countries that have ratified it to significantly reduce their GHG emissions, including CO₂. The vast majority of developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements, including many of the countries in which the Company’s subsidiaries operate. Of the 28 countries in which the Company’s subsidiaries currently operate all but one—the United States (including Puerto Rico)—have ratified the Kyoto Protocol.

In addition to the risks and uncertainties related to GHG regulations or potential legislation, the Company faces certain risks and uncertainties related to regulations or legislation concerning other types of air emissions. In the United States the CAA and various state laws and regulations regulate emissions of air pollutants, including SO₂, NO_X, particulate matter (“PM”), mercury and other hazardous air pollutants (“HAPs”). The applicable rules and steps taken by the Company to comply with the rules are discussed in further detail below.

The EPA promulgated the “Clean Air Interstate Rule” (“CAIR”) on March 10, 2005, which required allowance surrender for SO₂ and NO_X, emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR was subsequently challenged in federal court on July 11, 2008 and the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA.

In response to the D.C. Circuit’s opinion, on July 6, 2010, the EPA issued a new proposed rule (the “Transport Rule”) to replace CAIR. The final Transport Rule is scheduled to be issued by July 2011. The Clean Air Transport Rule would require significant reductions in SO₂ and NO_X emissions in 31 states and the District of Columbia starting in 2012, including several states where subsidiaries of the Company conduct business.

The Transport Rule contemplates three possible options for reducing SO₂ and NO_X emissions in the designated states. The EPA’s preferred option contemplates a set limit or budget on SO₂ and NO_X emissions for each of the states, with limited interstate trading of emissions allowances and unlimited intrastate trading of SO₂ and NO_X emissions allowances. Affected power plants would receive emissions allowances based on the applicable state emissions budgets. The EPA’s second option under the Transport Rule would establish emission budgets for each state but only allow intrastate trading of emissions allowances. The final option would set emission rate limitations for each power plant but would allow for some intrastate averaging of emission rates. Under any of the proposed options, additional air emission control technology may be required by some of our subsidiaries, and the cost of implementing any such technology could affect the financial condition or results of operations of these subsidiaries or the Parent Company. The EPA has received public comments on the Transport Rule, and such public comments will be considered by the EPA prior to promulgating a final rule.

As a result of prior EPA determinations and a D.C. Circuit Court ruling, the EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and nickel species from coal and oil-fired power plants. The EPA has entered into a consent decree under which it is obligated to propose the rule by March 2011 and to finalize the rule by November 2011. In connection with such rule, the CAA requires the EPA to establish maximum achievable control technology (“MACT”) standards for each pollutant regulated under the rule. MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. While it is impossible to project what emission rate levels the EPA may propose as MACT, the rule may require all coal-fired power plants to install acid gas scrubbers (wet or dry flue gas desulfurization technology) and/or some other

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type of mercury control technology, such as sorbent injection. Most of the Company’s United States coal-fired plants have acid gas scrubbers or comparable control technologies, but it is possible that EPA regulations will require improvements to such control technologies at some of our plants. Under the CAA, compliance is required within three years of the effective date of the rule; however, the compliance period for a unit, or group of units, may be extended by state permitting authorities (for one additional year) or through a determination by the President (for up to two additional years). At this time, the Company cannot predict whether new regulations for hazardous air pollutants will be promulgated or, if promulgated, the extent of such regulations, but the cost of compliance with any such regulations could be material.

In July 1999, the EPA published the “Regional Haze Rule” to reduce haze and protect visibility in designated federal areas. On June 15, 2005, the 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. States were required to submit their regional haze state implementation plans (“SIPs”) to the EPA by December 2007, but only 13 states met this deadline. The EPA has yet to approve any state’s Regional Haze state implementation plan. The statute requires compliance within five years after the EPA approves the relevant SIP, although individual states may impose more stringent compliance schedules.

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 NO_X, SO₂, 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 SO₂ reductions. Kilroot installed a new flue gas desulphurization system in the second quarter of 2009 in order to satisfy SO₂ reduction requirements. 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.

On January 18, 2011, the President of Chile approved a new air emissions regulation submitted to him by the national environmental regulatory agency (“CONAMA”). The new regulation establishes limits on emissions of NO_X, SO₂, metals and particulate matter for both existing and new thermal power plants, with more stringent limitations on new facilities. The regulation will become effective upon approval of the General Comptroller of Chile. The regulation will require AES Gener, our Chilean subsidiary, to install emissions reduction equipment at its existing thermal plants from late 2011 through 2015. The exact costs of compliance with such regulation have not yet been determined and the Company believes some of the compliance costs are contractually passed through to counterparties. However, the compliance costs could be material.

Water Discharges

The Company also faces certain risks and uncertainties related to environmental laws and regulations pertaining to water discharge. The Company’s facilities are subject to a variety of rules governing water discharges. In particular, the Company is subject to the United States Clean Water Act Section 316(b) rule regarding existing power plant cooling water intake structures issued by the EPA in 2005 (69 Fed. Reg. 41579, July 9, 2004), and the subsequent Circuit Court of Appeals decision and Supreme Court decision regarding this rule. The rule as originally issued could affect 12 of the Company’s United States power plants and the rule’s requirements would be implemented via each plant’s National Pollutant Discharge Elimination System (“NPDES”) water quality permit renewal process. 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

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facilities to utilize the best technology available for cooling water intake structures. To comply, a steam electric generating facility must first prepare a Comprehensive Demonstration Study to assess the 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. On January 25, 2007, the United States Court of Appeals for the Second Circuit decision (Docket Nos. 04-6692 to 04-6699) vacated and remanded major parts of the 2004 rule back to the EPA. In November 2007, three industry petitioners sought review of the Second Circuit’s decision by the United States Supreme Court, and this review was granted by the United States Supreme Court in April 2008. In its April 2009 decision, the United States Supreme Court granted the EPA authority to use a cost-benefit analysis when setting technology-based requirements under Section 316(b) of the Clean Water Act, and expressed no view on the remaining bases for the Second Circuit’s remand. New draft rule 316(b) regulations are expected to be proposed by the EPA by March 14, 2011, and finalized by July 27, 2010. Until such regulations are final, the EPA has instructed state regulatory agencies to use their best professional judgment in determining how to evaluate what constitutes best technology available for minimizing adverse environmental impacts from cooling water intake structures. Certain states in which the Company operates power generation facilities, such as New York, have been delegated authority and are moving forward with best technology available determinations in the absence of any final rule from the EPA. On September 27, 2010, the California Office of Administrative Law approved a policy adopted by the California Water Resources Control Board with respect to power plant cooling water intake structures. This policy became effective on October 1, 2010 and establishes technology-based standards to implement Section 316(b) of the United States Clean Water Act. At this time, it is contemplated that the Company’s Redondo Beach, Huntington Beach and Alamitos power plants in California will need to have in place “best technology available” by December 31, 2020, or repower the facilities. At present, the Company cannot predict the final requirements under Section 316(b) or whether compliance with the anticipated new 316(b) rule will have a material impact on our operations or results, but the Company expects that capital investments and/or modifications resulting from such requirements could be significant.

Waste Management

The Company also faces certain risks and uncertainties related to environmental laws and regulations pertaining to waste management. In the course of operations, the Company’s facilities generate solid and liquid waste materials requiring eventual disposal or processing. With the exception of coal combustion byproducts (“CCB”), the wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCB, 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 CCB, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl contaminated liquids and solids. The Company endeavors to ensure that all of its solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. On December 22, 2009, a dike at a coal ash containment area at the Tennessee Valley Authority’s plant in Kingston, Tennessee failed, and over 1 billion gallons of ash was released into adjacent waterways and properties. Following such incident, there has been heightened focus on the regulation of CCBs. On June 21, 2010, the EPA published in the Federal Register a proposed rule to regulate CCB under the Resource Conservation and Recovery Act (“RCRA”). The proposed rule provides two possible options for CCB regulation, both options contemplate heightened structural integrity requirements for surface impoundments of CCB.

The first option contemplates regulation of CCB as a hazardous waste subject to regulation under Subtitle C of the RCRA. Under this option, existing surface impoundments containing CCB would be required to be retrofitted with composite liners and these impoundments would likely be phased out over several years. State and/or federal permit programs would be developed for storage, transport and disposal of CCB. States could bring enforcement actions for non-compliance with permitting requirements, and the EPA would have oversight responsibilities as well as the authority to bring lawsuits for non-compliance.

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The second option contemplates regulation of CCB under Subtitle D of the RCRA. Under this option, the EPA would create national criteria applicable to CCB landfills and surface impoundments. Existing impoundments would also be required to be retrofitted with composite liners and would likely be phased out over several years. This option would not contain federal or state permitting requirements. The primary enforcement mechanism under regulation pursuant to Subtitle D would be private lawsuits.

The public comment period for this proposed regulation has expired, and the EPA is required to consider the public comments prior to promulgating a final rule. Requirements under a final rule are expected to become effective by January 2012, with a compliance schedule of five years. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are finalized, there can be no assurance that the Company’s businesses, financial condition or results of operations would not be materially and adversely affected by such regulations.

GUARANTEES, LETTERS OF CREDIT

In connection with certain project financing, acquisition, power purchase and other agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations primarily relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 16 years. In addition to the contingent obligations of the Parent Company identified in the table below, the Company’s subsidiaries had letters of credit outstanding to support various contingent obligations.

The following table summarizes the Parent Company’s contingent contractual obligations as of December 31, 2010. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of businesses of $101 million.

Contingent contractual obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	415		24		<$1 - $62
Letters of credit under the senior secured credit facility		85		30		<$1 - $26
Total	$	500		54

The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, sponsor support and liquidated damages under power purchase agreements and other agreements for projects in development, under construction and operating. While the Company does not expect to be required to fund any material amounts under these contingent contractual obligations during 2011 or beyond that are not recognized on the Consolidated Balance Sheet, many of the events which would give rise to such an obligation are beyond the Parent Company’s control. There can be no assurance that the Parent Company would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder.

During 2010, the Company paid letter of credit fees ranging from 3.19% to 3.75% per annum on the outstanding amounts of letters of credit.

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LITIGATION

The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims for approximately $448 million and $480 million as of December 31, 2010 and 2009, respectively. These are reported on the Consolidated Balance Sheet within “accrued and other liabilities” and “other long-term liabilities.” A significant portion of these reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that this reserve will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s financial statements. However, even where no reserve has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company, and could require the Company to pay damages or make expenditures in amounts that could be material.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$1.10 billion ($659 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil were dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás may restart the accounting proceedings at the Fifth District Court at any time, which would proceed according to the AC’s April 2010 decision. In the Fifth District Court proceedings, the expert’s conclusions will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected, and in turn the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the

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Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. The parties are disputing the proper venue for the CTEEP lawsuit. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In August 2000, the FERC announced an investigation into the organized California wholesale power markets to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. After hearings at FERC, AES Placerita was found subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001. As FERC investigations and hearings progressed, numerous appeals on related issues were filed with the U.S. Court of Appeals for the Ninth Circuit. Over the years, the Ninth Circuit issued several opinions that had the potential to expand the scope of the FERC proceedings and increase refund exposure for AES Placerita and other sellers of electricity. Following remand of one of the Ninth Circuit appeals in March 2009, FERC started a new hearing process involving AES Placerita and other sellers. In May 2009, AES Placerita entered into a settlement, approved by FERC in July 2009, concerning the claims before FERC against AES Placerita relating to the California energy crisis of 2000-2001, including the California refund proceeding. Pursuant to the settlement, AES Placerita paid $6 million and assigned a receivable of $168,119 due to it from the California Power Exchange in return for a release of all claims against it at FERC by the settling parties and other consideration. More than 98% of the buyers in the market elected to join the settlement. A small amount of AES Placerita’s settlement payment was placed in escrow for buyers that did not join the settlement (“non-settling parties”). It is unclear whether the escrowed funds will be enough to satisfy any additional sums that might be determined to be owed to non-settling parties at the conclusion of the FERC proceedings concerning the California energy crisis. However, any such additional sums are expected to be immaterial to the Company’s consolidated financial statements. In November 2009, one non-settling party, the Sacramento Municipal Utility District (“SMUD”), filed an appeal of the FERC’s approval of the settlement which is pending in the Ninth Circuit. SMUD’s appeal has been stayed pending further order of the court. The settlement agreement is still effective and will continue to remain effective unless it is vacated by the Ninth Circuit. SMUD has reached a settlement in principal with buyers of electricity that, if approved by FERC, will leave only immaterial claims of non-settling parties against AES Placerita.

In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd. (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa

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Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. In September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd. (“OPGC”), an equity method investment, and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPA’s terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA’s terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified AES Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgás and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers, and requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FSCP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

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AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney’s office has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Public Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($4 million). The injunction was rejected and the case is in the evidentiary stage awaiting the judge’s determination concerning the production of expert evidence. The above-referenced proposal was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response, Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. It is estimated that remediation could cost approximately R$14.7 million ($9 million). Discussions between Sul and CEEE are ongoing.

In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”) filed lawsuits against Itabo, an affiliate of the Company, in the First and Fifth Chambers of the Civil and Commercial Court of First Instance for the National District. CDEEE alleges in both lawsuits that Itabo spent more than was necessary

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to rehabilitate two generation units of an Itabo power plant and, in the Fifth Chamber lawsuit, that those funds were paid to affiliates and subsidiaries of AES Gener and Coastal Itabo, Ltd. (“Coastal”), a former shareholder of Itabo, without the required approval of Itabo’s board of administration. In the First Chamber lawsuit, CDEEE seeks an accounting of Itabo’s transactions relating to the rehabilitation. In November 2004, the First Chamber dismissed the case for lack of legal basis. On appeal, in October 2005 the Court of Appeals of Santo Domingo ruled in Itabo’s favor, reasoning that it lacked jurisdiction over the dispute because the parties’ contracts mandated arbitration. The Supreme Court of Justice is considering CDEEE’s appeal of the Court of Appeals’ decision. In the Fifth Chamber lawsuit, which also names Itabo’s former president as a defendant, CDEEE seeks $15 million in damages and the seizure of Itabo’s assets. In October 2005, the Fifth Chamber held that it lacked jurisdiction to adjudicate the dispute given the arbitration provisions in the parties’ contracts. The First Chamber of the Court of Appeal ratified that decision in September 2006. In a related proceeding, in May 2005, Itabo filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel CDEEE to arbitrate its claims. The petition was denied in July 2005. Itabo’s appeal of that decision to the U.S. Court of Appeals for the Second Circuit has been stayed since September 2006. Further, in September 2006, in an International Chamber of Commerce arbitration, an arbitral tribunal determined that it lacked jurisdiction to decide arbitration claims concerning these disputes. Itabo believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In April 2006, a putative class action was filed in the U.S. District Court for the Southern District of Mississippi (“District Court”) on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs subsequently appealed to the U.S. Court of Appeals for the Fifth Circuit, which, in October 2009, affirmed the District Court’s dismissal of the plaintiffs’ unjust enrichment, fraudulent misrepresentation, and civil conspiracy claims. However, the Fifth Circuit reversed the District Court’s dismissal of the plaintiffs’ public and private nuisance, trespass, and negligence claims, and remanded those claims to the District Court for further proceedings. In February 2010, the Fifth Circuit granted the petitions for en banc rehearing filed by the Company and other defendants, and thereby vacated its October 2009 decision. In May 2010, the Fifth Circuit dismissed the appeal on the ground that it had lost its quorum for en banc review. In August 2010, the plaintiffs filed a petition for a writ of mandamus in the U.S. Supreme Court, requesting the Supreme Court to direct the Fifth Circuit to reinstate the appeal and return it to the panel that issued the October 2009 decision. In January 2011, the Supreme Court denied the petition, ending the case.

In July 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan (the “Competition Committee”) ordered Nurenergoservice, an AES subsidiary, to pay approximately KZT 18 billion ($120 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee’s order was affirmed by the economic court in April 2008 (“April 2008 Decision”). The economic court also issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. Nurenergoservice’s subsequent appeals to the court of appeals were rejected. In February 2009, the Antimonopoly Agency (the Competition Committee’s successor) seized approximately KZT 783 million ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. However, on appeal to the Kazakhstan Supreme Court, in October 2009, the Supreme Court annulled the decisions of the lower courts because of procedural irregularities and remanded the case to the economic court for reconsideration. On remand, in January 2010, the economic court reaffirmed its April 2008 Decision. Nurenergoservice’s appeals in the court of appeals (first panel) and the court of appeals (second panel) were unsuccessful. Nurenergoservice intends to file a further appeal to the Kazakhstan Supreme Court. In

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separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately KZT 1.8 billion ($12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court was rejected in February 2009. Given the adverse court decisions against Nurenergoservice, the Antimonopoly Agency may attempt to seize Nurenergoservice’s remaining assets, which are immaterial to the Company’s consolidated financial statements. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious defenses to the claims asserted against it; however, there can be no assurances that it will prevail in these proceedings.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”), in January through February 2009. The investigation of Shulbinsk HPP is ongoing, but the investigation of UK HPP has been completed. The Antimonopoly Agency determined that UK HPP abused its market position and charged monopolistically high prices for power in January through February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($3 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of UK HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

In April 2009, the Antimonopoly Agency initiated an investigation of Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales in 2008 through February 2009. The Antimonopoly Agency subsequently concluded that UKT abused its market position and charged monopolistically high prices for power and should pay an administrative fine of approximately KZT 136 million ($1 million). The Antimonopoly Agency later sought an order from the administrative court requiring UKT to pay the fine. The administrative court proceedings have been suspended due to a related criminal investigation of UKT employees. If the investigation is terminated and the Antimonopoly Agency prevails in the administrative proceedings, UKT may be ordered to pay the administrative fine and disgorge the profits from the sales at issue, estimated by the Antimonopoly Agency to be approximately 514 million KZT ($3 million). UKT believes it has meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In December 2007, an arbitral tribunal terminated ESSA’s gas supply contracts with members of the Sierra Chata Consortium in light of the restrictions that had been placed on the export of gas by the Argentine Republic. ESSA thereafter terminated its gas transportation contract with Transportadora de Gas del Norte S.A. (“TGN”), and initiated arbitration seeking relief from the obligation to pay the firm tariff under ESSA’s gas transportation contracts with Gasoducto GasAndes (Argentina) S.A. (“GasAndes Argentina”) and Gasoducto GasAndes S.A. (“GasAndes Chile”) or in the alternative, termination of such contracts. TGN (which later filed a lawsuit against ESSA in Argentina), GasAndes Argentina, and GasAndes Chile disputed that the restrictions on the export of gas justified the adjustment or termination of the respective gas transportation contracts and sought due tariff payments. On December 29, 2010, ESSA reached settlement agreements with GasAndes Argentina, GasAndes Chile, and TGN terminating the respective gas transportation contracts and resolving all pending legal disputes and potential future claims. ESSA recognized approximately $72 million as other expense for the three months ended December 31, 2010 related to the settlement agreements. Upon termination of the TGN gas transportation contract, ESSA is no longer required to pay certain charges imposed by the Argentine Republic relating to gas supply infrastructure.

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions have contributed to alleged global warming which, in turn, allegedly has led to the erosion of the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from

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$95 million to $400 million, and other unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit. The parties have briefed the appeal and are awaiting a date for oral argument. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In July, 1993 the Public Attorney’s office filed a claim against Eletropaulo, the Sao Paulo State Government, SABESP (a state-owned company), CETESB (a state-owned company) and DAEE (the municipal Water and Electric Energy Department) alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from the Pinheiros River into the Billings Reservoir. The events in question occurred while Eletropaulo was a state-owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately R$670 million ($401 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. In 2009, the Public Attorney’s Office has filed appeals to both Superior Court of Justice (“SCJ”) and the Supreme Court (“SC”) and such appeals were answered by Eletropaulo in the fourth quarter of 2009. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of Sao Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1 million ($599 thousand) as of December 31, 2010, or pay an indemnification amount of approximately R$10.2 million ($6 million). Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.

In February 2009, a CAA Section 114 information request from the EPA regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. Cayuga and Somerset responded to the EPA’s information request in June 2009, and they are awaiting a response from the EPA regarding their submittal. At this time, it is not possible to predict what impact, if any, this request may have on the Company, its results of operations or its financial position.

On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation (“NYSDEC”) that the facility had exceeded the permitted volume limit of coal ash that can be disposed of in the on-site landfill. Cayuga has met with NYSDEC and submitted a Landfill Liner Demonstration Report to them. Such report found that the landfill has adequate engineering integrity to support the additional coal ash and there is no inherent environmental threat. NYSDEC has indicated they accept the finding of the report. A permit modification was approved by the NYSDEC on May 14, 2010 and such permit modification allows for closure of this approximately 10-acre portion of the landfill. The construction in accordance with the approved permit modification was completed in November 2010 and the certification report for this construction project is currently being drafted to submit to the NYSDEC in the second quarter of 2011. While at this time it is not possible to predict what impact, if any, this matter may have on the Company, its results of operations or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.

In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Esado do Rio Grande do Sul and

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Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. The procedural schedules for the arbitrations have been established but the hearing dates have not been scheduled to date. AESU believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously; however, there can be no assurances that it will be successful in its efforts.

In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals (“VCA”) that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant stopped as a consequence of the Supreme Court’s decision. In December 2009, Chilean authorities approved new land use regulations that entitled EEC to apply for a new environmental permit. EEC applied for a new environmental permit in January 2010 and permit approval was granted by the Environmental Authority in February 2010. In March 2010, the Mayor of Puchuncaví and another third party challenged the new environmental permit before the VCA. The parties later entered into a settlement agreement pursuant to which the challenge to the new environmental permit was withdrawn in July 2010. In addition, the construction permit that is required to resume construction of the Plant was issued by the Municipality in August 2010. In September 2010, neighbors of Puchuncaví challenged the construction permit filing claims in the VCA. In November 2010, the VCA rejected the claims. The challenging parties subsequently filed appeals with the Supreme Court. In January 2011, the Supreme Court confirmed the decision of the VCA, finally rejecting the constitutional action. EEC has resumed construction of the Plant.

In June 2009, the Inter-American Commission on Human Rights of the Organization of American States (“IACHR”) requested that the Republic of Panama suspend the construction of AES Changuinola S.A.’s hydroelectric project (“Project”) until the bodies of the Inter-American human rights system can issue a final decision on a petition (286/08) claiming that the construction violates the human rights of alleged indigenous communities. In July 2009, Panama responded by informing the IACHR that it would not suspend construction of the Project and requesting that the IACHR revoke its request. In June 2010, the Inter-American Court of Human Rights vacated the IACHR’s request. With respect to the merits of the underlying petition, the IACHR heard arguments by the communities and Panama in November 2009, but has not issued a decision to date. The Company cannot predict Panama’s response to any determination on the merits of the petition by the bodies of the Inter-American human rights system.

In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that the proceeds of the sale of electricity from AES Cartagena’s plant should be reduced by roughly the value of the CO₂ allowances that were granted to AES Cartagena for free for the years 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately €20 million ($27 million) for 2007-2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for €523,548 (approximately $694,000) for the allowances granted for free for 2007 and €19,907,248 (approximately $26 million) for 2008. In July 2010, AES Cartagena received an invoice for approximately €5.4 million ($7 million) for the allowances granted for free for the first half of 2009. AES Cartagena does not expect to be charged for CO₂ allowances issued free of charge for subsequent periods. AES Cartagena has paid the amounts invoiced and has filed challenges to the CNE’s demands in the Spanish judicial system. There can be no assurances that the challenges will be successful. AES Cartagena has demanded indemnification from its fuel supply and electricity toller, GDF-Suez, in relation to the CNE invoices under the long-term energy agreement (the “Energy Agreement”) with GDF-Suez. However, GDF-Suez has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena

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initiated arbitration against GDF-Suez, seeking to recover the payments made to CNE. In the arbitration, AES Cartagena also seeks a determination that GDF-Suez is responsible for procuring and bearing the cost of CO₂ allowances that are required to offset the CO₂ emissions of AES Cartagena’s power plant, which is also in dispute between the parties. To date, AES Cartagena has paid approximately €20 million ($27 million) for the CO₂ allowances that have been required to offset 2008 and 2009 CO₂ emissions. AES Cartagena expects that allowances will need to be purchased to offset emissions for subsequent years. The evidentiary hearing in the arbitration took place from May 31-June 4, 2010, and closing arguments were heard on September 1, 2010. In February 2011, the arbitral tribunal requested further briefing from the parties on certain issues in the arbitration. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected and, in turn, there could be a material adverse effect on the Company and its results of operations. AES Cartagena believes it has meritorious claims and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 2009, the Public Defender’s Office of the State of Rio Grande do Sul (“PDO”) filed a class action against AES Sul in the 16th District Court of Porto Alegre, Rio Grande do Sul (“District Court”), claiming that AES Sul has been illegally passing PIS and COFINS taxes (taxes based on AES Sul’s income) to consumers. According to ANEEL’s Order No. 93/05, the federal laws of Brazil, and the Brazilian Constitution, energy companies such as AES Sul are entitled to highlight PIS and COFINS taxes in power bills to final consumers, as the cost of those taxes is included in the energy tariffs that are applicable to final consumers. Before AES Sul had been served with the action, the District Court dismissed the lawsuit in October 2009 on the ground that AES Sul had been properly highlighting PIS and COFINS taxes in consumer bills in accordance with Brazilian law. In April 2010, the PDO appealed to the Appellate Court of the State of Rio Grande do Sul (“AC”). In November 2010, the AC affirmed the dismissal. The PDO is expected to appeal. If the dismissal is ever reversed and AES Sul does not prevail in the lawsuit and is ordered to cease recovering PIS and COFINS taxes pursuant to its energy tariff, its potential prospective losses could be approximately R$9.6 million ($6 million) per month, as estimated by AES Sul. In addition, if AES Sul is ordered to reimburse consumers, its potential retrospective liability could be approximately R$1.2 billion ($718 million), as estimated by AES Sul. AES Sul believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings if it is served with the action; however, there can be no assurances that it would be successful in its efforts. Furthermore, if AES Sul does not prevail in the litigation it will seek to adjust its energy tariff to compensate it for its losses, but there can be no assurances that it would be successful in obtaining an adjusted energy tariff.

In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from EPA pursuant to CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to EPA’s Prevention of Significant Deterioration and nonattainment New Source Review (“NSR”) requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff and is currently in discussions with the EPA regarding possible resolutions to this NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties and to install additional pollution control technology on coal-fired electric generating units. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery through customer rates of any operating or capital expenditures related to pollution control technology systems to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.

In November 2009, April 2010 and December 2010, substantially similar personal injury lawsuits were filed by a total of 26 residents and estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic in October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs do not quantify their alleged damages, but generally allege that they are entitled to compensatory and punitive damages.

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The AES defendants have moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. (The AES Defendants have until mid-February to respond to the December 2010 lawsuit.) In September 2010, the Superior Court heard arguments on the motions. The Superior Court dismissed the plaintiffs’ fraud allegations without prejudice to replead, and the plaintiffs filed amended complaints in November 2010. The AES defendants have filed a renewed motion to dismiss the amended issues. The remaining claims (other than fraud) addressed in the AES defendants’ original motion to dismiss are still pending. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns an unfinished 670MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond is approximately €155 million ($205 million). However, the Contractor obtained a temporary injunction from a French court preventing the issuing bank from honoring the bond demands. As the performance bond is governed by English law, Maritza obtained a judgment from an English court that the bond should be paid, and then presented this judgment to the French court which issued the temporary injunction. However, on February 10, 2011, the French court issued a decision enjoining the issuing bank from honoring the demands on the performance bond pending the determination of the arbitration between Maritza and the Contractor, described below. Maritza is attempting to lift that injunction or otherwise obtain payment on its demands. In addition, in December 2010, the Contractor issued a notice of dispute alleging that the lignite that has been supplied by Maritza for commissioning of the power plant is out of specification, allegedly entitling the Contractor to an extension of time to complete the power plant, an increase to the contract price of approximately €62 million ($82 million), and other relief. The Contractor thereafter advised Maritza that it had stopped commissioning of the power plant’s two units because of the characteristics of the lignite supplied, and, in January 2011, initiated arbitration on its lignite claim. Maritza disputes that the lignite is out of specification and intends to defend the arbitration and assert counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC contract. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

13. BENEFIT PLANS

DEFINED CONTRIBUTION PLAN—The Company sponsors one defined contribution plan, qualified under section 401 of the Internal Revenue Code. All U.S. employees of the Company are eligible to participate in the plan except for those employees who are not covered by their collective bargaining agreement. The plan provides matching contributions in AES common stock, other contributions at the discretion of the Compensation Committee of the Board of Directors in AES common stock and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company’s matching contributions. Participants vest in other company contributions ratably over a five-year period ending on the fifth anniversary of their hire date. Company contributions to the plans were approximately $22 million, $22 million, and $21 million for the years ended December 31, 2010, 2009, and 2008, respectively.

DEFINED BENEFIT PLANS—Certain of the Company’s subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings. Of the 28 defined benefit plans, two are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.

AES adopted the measurement date provisions of the pension accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans, for the fiscal year ended December 31, 2008 and, accordingly, recognized a cumulative adjustment of $1 million to retained earnings as of December 31, 2008.

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The following table reconciles the Company’s funded status, both domestic and foreign, as of December 31, 2010 and 2009:

	December 31,
	2010						2009
	U.S.			Foreign			U.S.			Foreign
	(in millions)
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Benefit obligation at beginning of year	$	549		$	5,138		$	528		$	3,498
Service cost		7			17			6			13
Interest cost		32			511			32			459
Employee contributions		—			5			—			19
Plan amendments		11			—			—			—
Plan settlements		—			(2	)		—			—
Benefits paid		(30	)		(411	)		(29	)		(366	)
Business combinations		—			14			—			—
Actuarial loss		39			474			12			304
Effect of foreign currency exchange rate change		—			249			—			1,211
Benefit obligation as of December 31	$	608		$	5,995		$	549		$	5,138
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year	$	368		$	4,045		$	306		$	2,752
Actual return on plan assets		46			742			71			489
Employer contributions		29			157			20			188
Employee contributions		—			5			—			19
Plan settlements		—			(2	)		—			—
Benefits paid		(30	)		(411	)		(29	)		(366	)
Effect of foreign currency exchange rate change		—			198			—			963
Fair value of plan assets as of December 31	$	413		$	4,734		$	368		$	4,045
RECONCILIATION OF FUNDED STATUS
Funded status as of December 31	$	(195	)	$	(1,261	)	$	(181	)	$	(1,093	)

The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the funded status of the plans, both domestic and foreign, as of December 31, 2010 and 2009:

	December 31,
	2010						2009
	U.S.			Foreign			U.S.			Foreign
	(in millions)
AMOUNTS RECOGNIZED ON THE CONSOLIDATED BALANCE SHEETS
Noncurrent assets	$	—		$	34		$	—		$	32
Accrued benefit liability—current		—			(5	)		—			(4	)
Accrued benefit liability—long-term		(195	)		(1,290	)		(181	)		(1,121	)
Net amount recognized at end of year	$	(195	)	$	(1,261	)	$	(181	)	$	(1,093	)

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The following table summarizes the Company’s accumulated benefit obligation, both domestic and foreign, as of December 31, 2010 and 2009:

	December 31,
	2010				2009
	U.S.		Foreign		U.S.		Foreign
	(in millions)
Accumulated Benefit Obligation	$	592	$	5,936	$	535	$	5,098
Information for pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation	$	608	$	5,703	$	549	$	4,887
Accumulated benefit obligation		592		5,657		535		4,855
Fair value of plan assets		413		4,410		368		3,765
Information for pension plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	608	$	5,710	$	549	$	4,892
Fair value of plan assets		413		4,415		368		3,766

The table below summarizes the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of December 31, 2010 and 2009:

	December 31,
	2010						2009
	U.S.			Foreign			U.S.			Foreign
Benefit Obligation:
Discount rates		5.38	%		9.84	%		5.92	%		10.56	%
Rates of compensation increase		N/A	(1)		6.00	%		N/A	(1)		6.00	%
Periodic Benefit Cost:
Discount rate		5.92	%		10.56	%		6.26	%		11.78	%
Expected long-term rate of return on plan assets		8.00	%		11.12	%		8.00	%		11.99	%
Rate of compensation increase		N/A	(1)		6.00	%		N/A	(1)		5.97	%

⁽¹⁾  The Company’s two plans in the U.S. use salary bands to determine future benefit costs rather than rates of compensation increases.

The Company establishes its estimated long-term return on plan assets considering various factors, which include the targeted asset allocation percentages, historic returns and expected future returns.

The measurement of pension obligations, costs and liabilities is dependent on a variety of assumptions. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions.

The assumptions used in developing the required estimates include the following key factors:

• discount rates;

• salary growth;

• retirement rates;

• inflation;

• expected return on plan assets; and

• mortality rates.

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The effects of actual results differing from the Company’s assumptions are accumulated and amortized over future periods and, therefore, generally affect the Company’s recognized expense in such future periods.

Sensitivity of the Company’s pension funded status to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric and are specific to the base conditions at year-end 2010. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The December 31, 2010 funded status is affected by the December 31, 2010 assumptions. Pension expense for 2010 is affected by the December 31, 2009 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the table below (in millions):

Increase of 1% in the discount rate	$	(34	)
Decrease of 1% in the discount rate	$	43
Increase of 1% in the long-term rate of return on plan assets	$	(42	)
Decrease of 1% in the long-term rate of return on plan assets	$	42

The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for the years ended December 31, 2010 through 2008:

	December 31,
	2010						2009						2008
Components of Net Periodic Benefit Cost:	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)
Service cost	$	7		$	17		$	6		$	13		$	5		$	11
Interest cost		32			511			32			459			30			453
Expected return on plan assets		(30	)		(427	)		(24	)		(374	)		(31	)		(412	)
Amortization of initial net asset		—			(1	)		—			(2	)		—			(3	)
Amortization of prior service cost		3			—			4			—			3			—
Amortization of net loss		12			38			16			7			1			2
Settlement gain recognized		—			1			—			—			1			—
Total pension cost	$	24		$	139		$	34		$	103		$	9		$	51

The following table summarizes the amounts reflected in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet as of December 31, 2010 that have not yet been recognized as components of net periodic benefit cost:

	December 31, 2010
	Accumulated Other Comprehensive Loss					Amounts expected to be reclassified to earnings in next fiscal year
	U.S.		Foreign			U.S.		Foreign
	(in millions)
Prior service cost	$	—	$	(2	)	$	—	$	—
Unrecognized net actuarial loss		—		(876	)		—		(23	)
Total	$	—	$	(878	)	$	—	$	(23	)

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The following table summarizes the Company’s target allocation for 2010 and pension plan asset allocation, both domestic and foreign, as of December 31, 2010 and 2009:

					Percentage of Plan Assets as of December 31,
	Target Allocations				2010						2009
Asset Category	U.S.		Foreign		U.S.			Foreign			U.S.			Foreign
Equity securities		50%		15% - 30%		53.51	%		22.71	%		57.06	%		22.22	%
Debt securities		40%		59% - 85%		25.91	%		73.36	%		34.24	%		73.34	%
Real estate		0%		0% - 4%		—	%		2.09	%		—	%		2.07	%
Other		10%		0% - 6%		20.58	%		1.84	%		8.70	%		2.37	%
Total pension assets						100.00	%		100.00	%		100.00	%		100.00	%

The U.S. plans seek to achieve the following long-term investment objectives:

• Maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;

• Long-term rate of return in excess of the annualized inflation rate;

• Long-term rate of return, net of relevant fees, that meet or exceed the assumed actuarial rate; and

• Long-term competitive rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates.

The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage risk through portfolio diversification and takes into account, among other possible factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends. The following table summarizes the Company’s U.S. plan assets by category of investment and level within the fair value hierarchy as of December 31, 2010 and 2009:

	December 31, 2010								December 31, 2009
U.S. Plans	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)
Equity securities:
Common stock	$	146	$	36	$	—	$	182	$	176	$	31	$	—	$	207
Mutual funds		39		—		—		39		3		—		—		3
Debt securities:
Government debt securities		32		—		—		32		43		—		—		43
Corporate debt securities		62		—		—		62		66		—		—		66
Mutual funds(1)		2		—		—		2		2		—		—		2
Other debt securities		11		—		—		11		15		—		—		15
Other:
Cash and cash equivalents		69		—		—		69		16		—		—		16
Other investments		—		16		—		16		—		16		—		16
Total plan assets	$	361	$	52	$	—	$	413	$	321	$	47	$	—	$	368

⁽¹⁾  Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.

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The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk. The assumed asset allocation has less exposure to equities in order to closely match market conditions and near term forecasts. The following table summarizes the Company’s foreign plan assets by category of investment and level within the fair value hierarchy as of December 31, 2010 and 2009:

	December 31, 2010								December 31, 2009
Foreign Plans	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)
Equity securities:
Common stock	$	30	$	—	$	—	$	30	$	21	$	—	$	—	$	21
Mutual funds		524		—		—		524		472		—		—		472
Private equity(1)		—		—		521		521		—		—		406		406
Debt securities:
Certificates of deposit		—		4		—		4		—		7		—		7
Unsecured debentures		—		19		—		19		—		14		—		14
Government debt securities		—		234		—		234		—		206		—		206
Mutual funds(2)		95		3,110		—		3,205		88		2,646		—		2,734
Other debt securities		—		11		—		11		—		5		—		5
Real estate:
Real estate(1)		—		—		99		99		—		—		84		84
Other:
Cash and cash equivalents		—		4		—		4		20		2		—		22
Participant loans(3)		—		—		83		83		—		—		74		74
Total plan assets	$	649	$	3,382	$	703	$	4,734	$	601	$	2,880	$	564	$	4,045

⁽¹⁾  Plan assets of our Brazilian subsidiaries are invested in private equities and commercial real estate through the plan administrator in Brazil. The fair value of these assets is determined using the income approach through annual appraisals based on a discounted cash flow analysis.

⁽²⁾  Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.

⁽³⁾  Loans to participants are stated at cost, which approximates fair value.

The following table presents a reconciliation of all plan assets measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009:

	Year Ended December 31,
	2010		2009
	(in millions)
Balance at January 1	$	564	$	380
Actual return on plan assets:
Returns relating to assets still held at reporting date		104		46
Purchases, sales, issuances and settlements		3		1
Change due to exchange rate changes		32		137
Balance at December 31	$	703	$	564

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The following table summarizes the scheduled cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign:

	U.S.		Foreign
	(in millions)
Expected employer contribution in 2011	$	36	$	165
Expected benefit payments for fiscal year ending:
2011		31		432
2012		32		447
2013		33		464
2014		35		481
2015		36		498
2016 - 2020		201		2,751

14. EQUITY

STOCK PURCHASE AGREEMENT

On March 12, 2010, the Company and Terrific Investment Corporation (“Investor”), a wholly owned subsidiary of China Investment Corporation, entered into a stockholder agreement (the “Stockholder Agreement”) in connection with the agreement discussed in the following paragraph. Under the Stockholder Agreement, as long as Investor holds more than 5% of the outstanding shares of common stock of the Company, Investor will have the right to designate one nominee, who must be reasonably acceptable to the Board, for election to the Board of Directors of the Company. Investor has not designated its nominee for election to the Board of Directors of the Company. In addition, until such time as Investor holds 5% or less of the outstanding shares of common stock, Investor has agreed to vote its shares in accordance with the recommendation of the Company on any matters submitted to a vote of the stockholders of the Company relating to the election of directors and compensation matters. Otherwise, Investor may vote its shares at its discretion. Further, under the Stockholder Agreement, Investor will be subject to a standstill restriction which generally prohibits Investor from purchasing additional securities of the Company beyond the level acquired by it under the stock purchase agreement entered into between Investor and the Company on November 6, 2009. In addition, Investor has agreed to a lock-up restriction such that Investor would not sell its shares for a period of 12 months following the closing, subject to certain exceptions. The standstill and lock-up restrictions also terminate at such time as Investor holds 5% or less of the outstanding shares of common stock. Investor will have certain registration rights and preemptive rights under the Stockholder Agreement with respect to its shares of common stock of the Company.

On March 15, 2010, the Company completed the sale of 125,468,788 shares of common stock to Investor. The shares were sold for $12.60 per share, for an aggregate purchase price of $1.58 billion. Investor’s ownership in the Company’s common stock is now approximately 15% of the Company’s total outstanding shares of common stock on a fully diluted basis.

STOCK REPURCHASE PROGRAM

In July 2010, the Company’s Board of Directors approved a stock repurchase program under which the Company may repurchase up to $500 million of AES common stock. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. The original authorization was set to expire on December 31, 2010, however; in December 2010, the Board authorized an extension of the stock repurchase program. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time. During the year ended December 31, 2010, shares of common stock repurchased under this plan totaled

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8,382,825 at a total cost of $99 million plus a nominal amount of commissions (average of $11.86 per share including commissions). There was $401 million remaining under the stock repurchase program available for future repurchases at December 31, 2010.

On August 7, 2008, the Company’s Board of Directors approved a share repurchase plan for up to $400 million of AES common stock. The Board authorization permitted the Company to repurchase shares over a six month period ended February 7, 2009. Shares of common stock repurchased under this plan through December 31, 2008 totaled 10,691,267 at a total cost of $143 million plus commissions of $0.3 million (average of $13.41 per share including commissions). The Board authorization of the stock repurchase program expired on February 7, 2009.

The shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 17,287,073 and 9,534,580 shares were held in treasury stock at December 31, 2010 and 2009, respectively. The Company has not retired any shares held in treasury during the years ended December 31, 2010, 2009 or 2008.

COMPREHENSIVE INCOME

The components of comprehensive income for the years ended December 31, 2010, 2009 and 2008 were as follows:

	December 31,
	2010			2009			2008
	(in millions)
Net income	$	1,059		$	1,755		$	2,032
Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $3, $(4) and $0, respectively		(5	)		6			—
Foreign currency translation adjustments, net of income tax (expense) benefit of $(11), $(78) and $53, respectively		468			742			(1,052	)
Derivative activity:
Reclassification to earnings, net of income tax (expense) of $(30), $(41) and $(19), respectively		91			(141	)		90
Change in derivative fair value, net of income tax (expense) benefit of $56, $34 and $(29), respectively		(242	)		214			(158	)
Total change in fair value of derivatives		(151	)		73			(68	)
Change in unfunded pension obligation, net of income tax benefit of $45, $69 and $77, respectively		(88	)		(139	)		(149	)
Other comprehensive income (loss)		224			682			(1,269	)
Comprehensive income		1,283			2,437			763
Less: Comprehensive income attributable to noncontrolling interests(1)		(1,038	)		(1,485	)		(169	)
Comprehensive income attributable to The AES Corporation	$	245		$	952		$	594

⁽¹⁾  Reflects the (income) loss attributed to noncontrolling interests in the form of common securities and dividends on preferred stock.

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The following table summarizes the balances comprising accumulated other comprehensive loss, net of tax, as of December 31, 2010 and 2009:

	December 31,
	2010			2009
	(in millions)
Foreign currency translation adjustment	$	1,824		$	2,312
Unrealized derivative losses		344			224
Unfunded pension obligation		216			194
Unrealized loss on securities available for sale		(1	)		(6	)
Total	$	2,383		$	2,724

The following table summarizes the net income attributable to The AES Corporation and transfers (to) from noncontrolling interests for the years ended December 31, 2010 and 2009:

	December 31,
	2010			2009
	(in millions)
Net income attributable to The AES Corporation	$	9		$	658
Transfers (to) from the noncontrolling interests:
Decrease in The AES Corporation’s paid-in capital for purchase of subsidiary shares		(25	)		—
Net transfers (to) from noncontrolling interest		(25	)		—
Change from net income attributable to The AES Corporation and transfers (to) from noncontrolling interests	$	(16	)	$	658

15. SEGMENT AND GEOGRAPHIC INFORMATION

The management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally. During 2010, the Company modified its internal reporting structure to move the management of the Company’s generation business in Jordan, Amman East, from Asia to Europe. Accordingly, Amman East is now reported within the Europe—Generation segment. All prior periods have been retrospectively restated to reflect this change and conform to current period presentation. The Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and the Company concluded it has six reportable segments which include:

• Latin America—Generation;

• Latin America—Utilities;

• North America—Generation;

• North America—Utilities;

• Europe—Generation;

• Asia—Generation.

Corporate and Other—The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation and Climate Solutions operating segments are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that

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would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting; therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue or gross margin. “Corporate and Other” also includes costs related to corporate overhead costs which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

The Company uses Adjusted Gross Margin, a non-GAAP measure, to evaluate the performance of its segments. Adjusted Gross Margin is defined by the Company as: Gross Margin plus depreciation and amortization less general and administrative expenses.

Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain management fees and self insurance activities which are reflected within segment Adjusted Gross Margin. All intra-segment activity has been eliminated with respect to revenue and Adjusted Gross Margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued or classified as held for sale as of December 31, 2010 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

The tables below present the breakdown of business segment balance sheet and income statement data as of and for the years ended December 31, 2010 through 2008:

	Total Revenue						Intersegment									External Revenue
	2010		2009		2008		2010			2009			2008			2010		2009		2008
	(in millions)
Revenue
Latin America—Generation	$	4,281	$	3,651	$	4,468	$	(1,017	)	$	(864	)	$	(991	)	$	3,264	$	2,787	$	3,477
Latin America—Utilities		7,222		6,092		5,907		—			—			—			7,222		6,092		5,907
North America—Generation		1,551		1,483		1,644		—			—			—			1,551		1,483		1,644
North America—Utilities		1,145		1,068		1,079		—			—			—			1,145		1,068		1,079
Europe—Generation		1,318		762		1,044		(2	)		2			—			1,316		764		1,044
Asia—Generation		618		375		345		—			—			—			618		375		345
Corp/Other and eliminations		46		9		21		1,019			862			991			1,065		871		1,012
Total Revenue	$	16,181	$	13,440	$	14,508	$	—		$	—		$	—		$	16,181	$	13,440	$	14,508

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	Total Adjusted Gross Margin							Intersegment									External Adjusted Gross Margin
	2010		2009		2008			2010			2009			2008			2010			2009			2008
	(in millions)
Adjusted Gross Margin
Latin America—Generation	$	1,698	$	1,528	$	1,557		$	(1,010	)	$	(852	)	$	(978	)	$	688		$	676		$	579
Latin America—Utilities		1,320		1,130		1,102			1,018			865			991			2,338			1,995			2,093
North America—Generation		555		558		640			2			(3	)		17			557			555			657
North America—Utilities		407		401		419			2			2			2			409			403			421
Europe—Generation		395		273		305			3			4			2			398			277			307
Asia—Generation		255		111		(11	)		2			4			4			257			115			(7	)
Corp/Other and eliminations		62		2		(65	)		(17	)		(20	)		(38	)		45			(18	)		(103	)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization																		(1,096	)		(936	)		(899	)
Interest expense																		(1,506	)		(1,462	)		(1,746	)
Interest income																		410			346			515
Other expense																		(238	)		(106	)		(161	)
Other income																		104			460			372
Gain on sale of investments																		—			131			909
Loss on sale of subsidiary stock																		—			—			(31	)
Goodwill impairment																		(21	)		(122	)		—
Asset impairment expense																		(391	)		(20	)		(175	)
Foreign currency transaction gains (losses) on net monetary position																		(33	)		34			(183	)
Other non-operating expense																		(7	)		(12	)		(15	)
Income from continuing operations before taxes and equity in earnings of affiliates																	$	1,914		$	2,316		$	2,533

	Total Assets						Depreciation and Amortization						Capital Expenditures
	2010		2009		2008		2010		2009		2008		2010		2009		2008
	(in millions)
Latin America—Generation	$	10,373	$	9,802	$	8,217	$	215	$	183	$	168	$	641	$	951	$	886
Latin America—Utilities		10,081		9,233		7,124		254		220		221		649		413		437
North America—Generation		4,681		5,081		5,196		168		167		162		71		64		64
North America—Utilities		3,139		3,035		3,092		161		157		152		177		116		117
Europe—Generation		4,178		3,154		2,836		114		53		45		233		212		531
Asia—Generation		1,762		1,594		1,588		33		32		23		10		22		32
Discontinued businesses		258		2,371		2,684		49		88		92		16		38		86
Corp/Other and eliminations		6,039		5,265		4,069		184		149		138		536		722		744
Total	$	40,511	$	39,535	$	34,806	$	1,178	$	1,049	$	1,001	$	2,333	$	2,538	$	2,897

	Investment in and Advances to Affiliates						Equity in Earnings (Loss)
	2010		2009		2008		2010			2009			2008
	(in millions)
Latin America—Generation	$	150	$	129	$	81	$	48		$	30		$	9
Latin America—Utilities		—		—		—		—			—			—
North America—Generation		—		3		2		(2	)		(2	)		(2	)
North America—Utilities		—		—		1		—			—			—
Europe—Generation		353		308		232		19			50			28
Asia—Generation		409		390		371		3			28			12
Discontinued businesses		—		—		—		—			—			—
Corp/Other and eliminations		408		327		214		115			(14	)		(14	)
Total	$	1,320	$	1,157	$	901	$	183		$	92		$	33

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The table below presents information, by country, about the Company’s consolidated operations for each of the years ended December 31, 2010 through 2008 and as of December 31, 2010 and 2009, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.

	Revenue						Property, Plant & Equipment, net
	2010		2009		2008		2010		2009
	(in millions)
United States(1)	$	2,193	$	2,089	$	2,155	$	6,165	$	6,323
Non-U.S.:
Brazil		6,473		5,394		5,501		6,413		5,799
Chile		1,355		1,239		1,349		2,560		2,321
Argentina		887		684		949		459		448
El Salvador		648		619		484		261		254
Dominican Republic		535		429		601		625		634
Philippines(2)		501		250		148		784		765
Cameroon		422		370		379		823		742
Spain(3)		411		—		—		667		—
Mexico		409		329		463		786		802
Colombia		393		347		291		387		390
United Kingdom		385		241		342		527		433
Ukraine		356		286		403		86		80
Hungary(4)		252		259		367		73		182
Puerto Rico		253		267		251		596		609
Panama		194		168		210		921		834
Kazakhstan		138		123		234		63		48
Jordan		120		104		47		224		231
Sri Lanka		100		109		184		69		74
Bulgaria(5)		44		—		—		1,825		1,835
Qatar(6)		—		—		—		—		—
Pakistan(7)		—		—		—		—		—
Oman(8)		—		—		—		—		—
Other Non-U.S.		112		133		150		298		285
Total Non-U.S.		13,988		11,351		12,353		18,447		16,766
Total	$	16,181	$	13,440	$	14,508	$	24,612	$	23,089

⁽¹⁾  Excludes revenue of $422 million, $456 million and $590 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $2 million and $693 million as of December 31, 2010, and 2009, respectively, related to Eastern Energy, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

⁽²⁾  Masinloc was acquired in April 2008; 2008 revenue represents results for a partial year.

⁽³⁾  Cartagena was consolidated effective January 1, 2010 upon implementation of the variable interest entity accounting guidance.

⁽⁴⁾  Excludes revenue of $44 million, $58 million and $99 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $7 million and $14 million as of December 31, 2010, and 2009, respectively, related to Borsod and Tiszapalkonya, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

⁽⁵⁾  Maritza East and our wind project in Bulgaria were under development and therefore not operational as of December 31, 2009. Our wind project in Bulgaria started operations in 2010.

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⁽⁶⁾  Excludes revenue of $129 million, $163 million and $161 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $501 million as of December 31, 2009 related to Ras Laffan, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

⁽⁷⁾  Excludes revenue of $299 million, $470 million and $607 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $36 million as of December 31, 2009 related to Lal Pir and Pak Gen, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

⁽⁸⁾  Excludes revenue of $62 million, $101 million and $105 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $311 million as of December 31, 2009, related to Barka, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

16. SHARE-BASED COMPENSATION

STOCK OPTIONS—AES grants options to purchase shares of common stock under stock option plans. Under the terms of the plans, the Company may issue options to purchase shares of the Company’s common stock at a price equal to 100% of the market price at the date the option is granted. Stock options are generally granted based upon a percentage of an employee’s base salary. Stock options issued under these plans in 2010, 2009 and 2008 have a three-year vesting schedule and vest in one-third increments over the three-year period. The stock options have a contractual term of ten years. At December 31, 2010, approximately 20 million shares were remaining for award under the plans. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.

The weighted average fair value of each option grant has been estimated, as of the grant date, using the Black-Scholes option-pricing model with the following weighted average assumptions:

	December 31,
	2010			2009			2008
Expected volatility		38	%		66	%		37	%
Expected annual dividend yield		—	%		—	%		—	%
Expected option term (years)		6			6			6
Risk-free interest rate		2.86	%		2.01	%		3.04	%

The Company exclusively relies on implied volatility as the expected volatility to determine the fair value using the Black-Scholes option-pricing model. The implied volatility may be exclusively relied upon due to the following factors:

• The Company utilizes a valuation model that is based on a constant volatility assumption to value its employee share options;

• The implied volatility is derived from options to purchase AES common stock that are actively traded;

• The market prices of both the traded options and the underlying shares are measured at a similar point in time and on a date reasonably close to the grant date of the employee share options;

• The traded options have exercise prices that are both near-the-money and close to the exercise price of the employee share options; and

• The remaining maturities of the traded options on which the estimate is based are at least one year.

Pursuant to share-based compensation accounting guidance, the Company used a simplified method to determine the expected term based on the average of the original contractual term and the pro rata vesting period.

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This simplified method was used for stock options granted during 2010, 2009 and 2008. This is appropriate given a lack of relevant stock option exercise data. This simplified method may be used as the Company’s stock options have the following characteristics:

• The stock options are granted at-the-money;

• Exercisability is conditional only on performing service through the vesting date;

• If an employee terminates service prior to vesting, the employee forfeits the stock options;

• If an employee terminates service after vesting, the employee has a limited time to exercise the stock option; and

• The stock option is nonhedgeable and not transferable.

The Company does not discount the grant date fair values to estimate post-vesting restrictions. Post-vesting restrictions include black-out periods when the employee is not able to exercise stock options based on their potential knowledge of information prior to the release of that information to the public.

Using the above assumptions, the weighted average fair value of each stock option granted was $5.08, $4.08 and $7.65, for the years ended December 31, 2010, 2009, and 2008, respectively.

The following table summarizes the components of stock-based compensation related to employee stock options recognized in the Company’s financial statements:

	December 31,
	2010			2009			2008
	(in millions)
Pre-tax compensation expense	$	9		$	10		$	12
Tax benefit		(2	)		(3	)		(3	)
Stock options expense, net of tax	$	7		$	7		$	9
Total intrinsic value of options exercised	$	2		$	3		$	9
Total fair value of options vested		11			13			13
Cash received from the exercise of stock options		2			6			17
Windfall tax benefits realized from the exercised stock options		—			—			1

There was no cash used to settle stock options or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, $5 million of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted average period of 1.5 years. There were no modifications to stock option awards during the year ended December 31, 2010.

A summary of the option activity for the year ended December 31, 2010 follows (number of options in thousands, dollars in millions except per option amounts):

	Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value
Outstanding at December 31, 2009		22,372		$	17.59
Exercised		(338	)		6.09
Forfeited and expired		(2,380	)		30.89
Granted		828			12.17
Outstanding at December 31, 2010		20,482		$	16.04		3.1	$	25
Vested and expected to vest at December 31, 2010		20,150		$	16.10		2.6	$	24
Eligible for exercise at December 31, 2010		18,079		$	16.68		2.4	$	20

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The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on the last trading day of the fourth quarter of 2010 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2010. The amount of the aggregate intrinsic value will change based on the fair market value of the Company’s stock.

The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2010, AES has estimated a forfeiture rate of 18.6% and 12.09% for stock options granted in 2010 to non-officer employees and officer employees of AES, respectively. Those estimates will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rates, the Company expects to expense $3.7 million on a straight-line basis over a three year period (approximately $1.2 million per year) related to stock options granted during the year ended December 31, 2010.

RESTRICTED STOCK

Restricted Stock Units Without Market Conditions—The Company issues restricted stock units (“RSUs”) without market conditions under its long-term compensation plan. The RSUs are generally granted based upon a percentage of the participant’s base salary. The units have a three-year vesting schedule and vest in one-third increments over the three-year period. The units are then required to be held for an additional two years before they can be converted into shares, and thus become transferable. In all circumstances, restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.

For the years ended December 31, 2010, 2009, and 2008, RSUs issued without a market condition had a grant date fair value equal to the closing price of the Company’s stock on the grant date. The Company does not discount the grant date fair values to reflect any post-vesting restrictions. RSUs without a market condition granted to non-executive employees during the years ended December 31, 2010, 2009, and 2008 had grant date fair values per RSU of $12.18, $6.71 and $18.87, respectively. The total grant date fair value of RSUs granted in 2010 without a market condition was $13 million.

The following table summarizes the components of the Company’s stock-based compensation related to its employee RSUs issued without market conditions recognized in the Company’s consolidated financial statements:

	December 31,
	2010			2009			2008
	(in millions)
RSU expense before income tax	$	11		$	11		$	10
Tax benefit		(2	)		(3	)		(2	)
RSU expense, net of tax	$	9		$	8		$	8
Total value of RSUs converted(1)	$	5		$	7		$	—
Total fair value of RSUs vested	$	12		$	12		$	10

⁽¹⁾  Amount represents fair market value on the date of conversion.

There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, $11 million of total unrecognized compensation cost related to RSUs without a market condition is expected to be recognized over a weighted average period of approximately 1.8 years. There were no modifications to RSU awards during the year ended December 31, 2010.

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A summary of the activity of RSUs without a market condition for the year ended December 31, 2010 follows (number of RSUs in thousands):

	RSUs			Weighted Average Grant Date Fair Values		Weighted Average Remaining Vesting Term
Nonvested at December 31, 2009		2,471		$	10.73
Vested		(929	)		12.56
Forfeited and expired		(455	)		12.20
Granted		1,080			12.18
Nonvested at December 31, 2010		2,167		$	10.20		1.5
Vested at December 31, 2010		2,226		$	16.48
Vested and expected to vest at December 31, 2010		3,999		$	13.67

The table below summarizes the RSUs without a market condition that vested and were converted during the years ended December 31, 2010, 2009 and 2008 (number of RSUs in thousands):

	December 31,
	2010		2009		2008
RSUs vested during the year		929		619		597
RSUs converted during the year(1)		386		772		59

⁽¹⁾  Net of shares withheld for taxes of 127,000 and 238,000 in the years ended December 31, 2010 and 2009, respectively. No shares were withheld for taxes during the year ended December 31, 2008.

Restricted Stock Units With Market Conditions—Restricted stock units issued to officers of the Company have a three-year vesting schedule and include a market condition to vest. Vesting will occur if the applicable continued employment conditions are satisfied and the Total Stockholder Return (“TSR”) on AES common stock exceeds the TSR of the Standard and Poor’s 500 (“S&P 500”) over the three-year measurement period beginning on January 1st in the year of grant and ending after three years on December 31st. In certain situations where the TSR of both AES common stock and the S&P 500 exhibit a gain over the measurement period, the grant may vest without the TSR of AES common stock exceeding the TSR of the S&P 500, if the Compensation Committee exercises its discretion to permit such vesting. The units are then required to be held for an additional two years subsequent to vesting before they can be converted into shares, and thus become transferable. In all circumstances, restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.

The effect of the market condition on restricted stock units issued to officers of the Company is reflected in the award’s fair value on the grant date for the year ended December 31, 2010. A discount of 5.0% was applied to the closing price of the Company’s stock on the date of grant to estimate the fair value to reflect the market condition for RSUs with market conditions granted during the year ended December 31, 2010. RSUs that included a market condition granted during the year ended December 31, 2010, 2009 and 2008 had a grant date fair value per RSU of $11.57, $6.68 and $16.23, respectively. The total grant date fair value of RSUs with a market condition granted in 2010 was $4 million. If no discount was applied to reflect the market condition for RSUs issued to officers, the total grant date fair value of RSUs with a market condition granted during the year ended December 31, 2010 would have increased by an immaterial amount.

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The following table summarizes the components of the Company’s stock-based compensation related to its RSUs granted with market conditions recognized in the Company’s consolidated financial statements:

	December 31,
	2010			2009			2008
	(in millions)
RSU expense before income tax	$	4		$	4		$	4
Tax benefit		(1	)		(1	)		(1	)
RSU expense, net of tax	$	3		$	3		$	3
Total value of RSUs converted(1)	$	3		$	4		$	—
Total fair value of RSUs vested(2)	$	—		$	—		$	5

⁽¹⁾  Amount represents fair market value on the date of conversion.

⁽²⁾  RSUs granted in 2007 with a market condition did not vest in 2010 because the TSR on AES common stock did not exceed the TSR of the S&P 500 over the three year vesting period.

There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, $5 million of total unrecognized compensation cost related to RSUs with a market condition is expected to be recognized over a weighted average period of approximately 1.7 years. There were no modifications to RSU awards during the year ended December 31, 2010.

A summary of the activity of RSUs with a market condition for the year ended December 31, 2010 follows (number of RSUs in thousands):

	RSUs			Weighted Average Grant Date Fair Values		Weighted Average Remaining Vesting Term
Nonvested at December 31, 2009		1,136		$	10.80
Vested		—			—
Forfeited and expired		(223	)		17.78
Granted		370			11.57
Nonvested at December 31, 2010		1,283		$	9.80		1.3
Vested at December 31, 2010		—		$	—
Vested and expected to vest at December 31, 2010		1,125		$	9.76

The table below summarizes the RSUs with a market condition that vested and were converted during the years ended 2010, 2009 and 2008 (number of RSUs in thousands):

	December 31,
	2010		2009		2008
RSUs vested during the year		—		—		352
RSUs converted during the year(1)		245		410		—

⁽¹⁾  Net of shares withheld for taxes of 102,000 and 153,000 during the years ended December 31, 2010 and 2009, respectively. There were no shares withheld for taxes during the year ended December 31, 2008.

17. SUBSIDIARY STOCK

The Company’s subsidiary had $60 million of cumulative preferred stock outstanding at December 31, 2010 and 2009. This represented five series of preferred stock of IPL, the Company’s integrated utility in Indiana. The total annual dividend requirements were approximately $3 million at December 31, 2010 and 2009. Certain series

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of the preferred stock were redeemable solely at the option of the issuer at prices between $100 and $118 per share. Holders of the preferred stock are entitled to elect a majority of IPL’s board of directors if IPL has not paid dividends to its preferred stockholders for four consecutive quarters. Based on the preferred stockholders’ ability to elect a majority of IPL’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity and presented in the mezzanine level of the Consolidated Balance Sheets in accordance with the relevant accounting guidance for noncontrolling interests and redeemable securities.

In February 2009, in connection with a preemptive rights period associated with a share issuance (capital increase) at AES Gener, Inversiones Cachagua Limitada (“Cachagua”), a wholly owned subsidiary of the Company, paid $175 million to AES Gener to maintain its current ownership percentage of approximately 70.6%.

On November 6, 2008, Cachagua sold a 9.6% ownership interest in AES Gener in a private transaction for $174.9 million. The sale reduced the Company’s ownership percentage of AES Gener from 80.2% to 70.6%. The Company recognized a pre-tax loss of $30.8 million, net of $3.6 million of related fees, from this transaction in the fourth quarter of 2008.

18. OTHER INCOME AND EXPENSE

The components of other income are summarized as follows:

	Years Ended December 31,
	2010		2009		2008
	(in millions)
Gain on extinguishment of tax and other liabilities	$	65	$	168	$	199
Tax credit settlement		—		129		—
Performance incentive fee		—		80		—
Insurance proceeds		—		—		40
Gain on sale of assets		12		14		34
Other		27		69		99
Total other income	$	104	$	460	$	372

Other income generally includes gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies, and other income from miscellaneous transactions.

Other income of $104 million for the year ended December 31, 2010 included the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and noncontrolling interest was $9 million. Other income also included a gain on sale of assets at Eletropaulo.

Other income of $460 million for the year ended December 31, 2009 included $165 million from the reduction in interest and penalties associated with federal tax debts at Eletropaulo and Sul as a result of the Programa de Recuperacao Fiscal (“REFIS”) program and a $129 million gain related to a favorable court decision enabling Eletropaulo to receive reimbursement of excess non-income taxes paid from 1989 to 1992 in the form of tax credits to be applied against future tax liabilities. The net impact to the Company after income taxes and noncontrolling interests for these items was $44 million. In addition, the Company recognized income of $80 million from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. The management agreement was related to the sale of these businesses in Kazakhstan in May 2008; see further discussion of this transaction in Note 22—Acquisitions and Dispositions.

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Other income of $372 million for the year ended December 31, 2008 included gains on the extinguishment of a gross receipts tax liability and a legal contingency at Eletropaulo of $117 million and $75 million, respectively, $32 million of cash proceeds related to a favorable legal settlement at Southland in California, $29 million of insurance recoveries for damaged turbines at Uruguaiana, $23 million of gains associated with a sale of land at Eletropaulo and sales of turbines at Itabo, and compensation of $18 million for the impairment associated with the settlement agreement to shut down Hefei.

The components of other expense are summarized as follows:

	Years Ended December 31,
	2010		2009		2008
	(in millions)
Loss on sale and disposal of assets	$	84	$	36	$	34
Gener gas settlement		72		—		—
Loss on extinguishment of debt		37		—		70
AES Wind transaction costs		22		—		—
Other		23		70		57
Total other expense	$	238	$	106	$	161

Other expense generally includes losses on asset sales, losses on extinguishment of debt, legal contingencies and losses from other miscellaneous transactions.

Other expense of $238 million for the year ended December 31, 2010 included $72 million for a settlement agreement of gas transportation contracts at Gener. There were also previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business. These costs were written off upon the expiration of the letter of intent on June 30, 2010. In addition, there were losses on disposal of assets at Eletropaulo, Panama, and Gener, an $18 million loss on debt extinguishment at Andres and Itabo, and a $15 million loss at the Parent Company from the retirement of senior notes.

Other expense of $106 million for the year ended December 31, 2009 included a $13 million loss recognized when three of our businesses in the Dominican Republic received $110 million par value bonds issued by the Dominican Republic government to settle existing accounts receivable for the same amount from the government-owned distribution companies. The loss represented an adjustment to reflect the fair value of the bonds on the date received. Other expenses also included losses on the disposal of assets at Eletropaulo and Andres and contingencies at Alicura in Argentina and our businesses in Kazakhstan.

Other expense of $161 million for the year ended December 31, 2008 included $69 million of losses on the retirement of debt at the Parent Company in June 2008 and at IPALCO associated with a $375 million refinancing in April 2008, and losses on the disposal of assets primarily at Eletropaulo in Brazil.

19. IMPAIRMENT EXPENSE

Asset Impairment

Asset impairment expense for the year ended December 31, 2010 consisted of:

	2010
	(in millions)
Southland (Huntington Beach)	$	200
Tisza II		85
Deepwater		79
Other		27
Total	$	391

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Southland—In May 2010, the California State Water Board approved a policy to reduce the number of marine animals killed by seawater cooling systems in coastal power plants in California. At that time since the policy required the approval of California’s Office of Administrative Law, it was unclear whether the policy would be approved and the exact form the regulations would take. In October 2010, the Office of Administrative Law in California approved the policy that will require the Company to change the process through which it uses ocean water to cool the generation turbines at its Alamitos, Huntington Beach and Redondo Beach (collectively “Southland”) gas-fired generation facilities in California. The policy requires compliance with the new regulations by December 31, 2020. The change in the water cooling process will result in significant future capital expenditures to ensure compliance with the new regulations and the Company determined that an indicator of impairment existed at September 30, 2010. The Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment. The asset group was determined to be at the individual plant level and based on the undiscounted cash flow analysis, the Company determined that the Huntington Beach asset group was not recoverable. The fair value of the Huntington Beach asset group was then determined using a discounted cash flow analysis. To assist management in determining the fair value of the asset group, an independent valuation firm was engaged. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. The carrying value of the Huntington Beach plant of $288 million exceeded the fair value of $88 million resulting in the recognition of asset impairment expense of $200 million for the year ended December 31, 2010. The undiscounted cash flows of the Alamitos and Redondo Beach generation facilities exceeded their respective carrying values and resulted in no impairment. Huntington Beach is reported in the North America Generation reportable segment.

Tisza II—During the third quarter of 2010, the Company entered into annual negotiations with the offtaker of its Tisza II generation plant in Hungary. As a result of these preliminary negotiations, as well as the further deterioration of the economic environment in Hungary, the Company determined that an indicator of impairment existed at September 30, 2010. Thus, the Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment and determined that based on the undiscounted cash flow analysis, the carrying amount of the Tisza II asset group was not recoverable. The fair value of the asset group was then determined using a discounted cash flow analysis. The carrying value of the Tisza II asset group of $160 million exceeded the fair value of $75 million resulting in the recognition of asset impairment expense of $85 million during the year ended December 31, 2010. Tisza II is reported in the Europe Generation reportable segment.

Deepwater—In March 2010, Deepwater, our 160 MW pet coke-fired merchant power plant located in Texas, experienced deteriorating market conditions due to increasing pet coke prices and diminishing power prices. As a result, Deepwater incurred an operating loss for the period and forecasted short term losses. These conditions gradually worsened in the second quarter of 2010 and management determined it could not operate the plant at certain times during the year without generating negative operating margin.

As the contraction of energy margin continued in the second quarter of 2010, management determined the collective events to be an indicator of impairment and performed an impairment evaluation of Deepwater’s goodwill and recoverability test for the long-lived asset group. Based on the results of these tests in the second quarter of 2010, management concluded no impairment was necessary. In the third quarter of 2010, these downward trends continued and management, after determining that there was an indicator of impairment, performed another impairment evaluation of Deepwater’s goodwill and recoverability test of the long-lived asset group. The results in the third quarter indicated no impairment was necessary for the asset group, but the goodwill associated with the reporting unit was deemed to be impaired and the $18 million goodwill balance was written off during the quarter ended September 30, 2010.

In the fourth quarter of 2010, further adverse trends in energy and pet coke pricing curves were observed in management’s review of external market analyses. The most significant impact on the forecasted energy prices reviewed by management in November 2010 related to the general external market consensus that Federal CO₂ cap and trade legislation was less likely, resulting in a drop in long-term energy price projections. At that time,

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Deepwater’s revised forecasts indicated that Deepwater would have operating losses which would extend beyond 2020 and negative cash flows through 2019. Management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was no longer recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. In determining the fair value of the asset group, all three valuation approaches described by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered most appropriate. On that basis, the carrying value of the asset group was determined to be impaired and $79 million of impairment expense was recognized in the fourth quarter of 2010. Deepwater is reported in the North America Generation reportable segment.

Asset impairment expense for the year ended December 31, 2009 consisted of:

	2009
	(in millions)
Piabanha	$	11
Other		9
Total	$	20

During the fourth quarter of 2009, the Company recognized a pre-tax long-lived asset impairment charge of $11 million related to the Company’s Piabanha hydro project in Brazil. The Company determined that the carrying value exceeded the future discounted cash flows and abandoned the project. Piabanha is reported in the Company’s Latin America Generation segment.

Asset impairment expense for the year ended December 31, 2008 consisted of:

	2008
	(in millions)
LNG projects in North America	$	67
Uruguaiana		36
South African peakers		31
Hefei		18
Other		23
Total	$	175

In the fourth quarter of 2008 and in response to the financial market crisis, the Company reviewed and prioritized projects in the development pipeline. From this review, the Company determined that the carrying value exceeded the future discounted cash flows for certain projects. In accordance with the accounting standards for the impairment or disposal of long-lived assets, the Company recorded a total pre-tax impairment charge of $75 million ($34 million, net of noncontrolling interests and income taxes) related to two liquefied natural gas projects in North America and a non-power development project at one of our facilities in North America. These projects were reported in the North America Generation segment.

Following an initial impairment charge in the fourth quarter of 2007 at Uruguaiana, there were impairment charges of $36 million recognized during the first three quarters of 2008. The impairment was triggered by a combination of gas curtailments and increases in the spot market price of energy in 2007 that continued in 2008. The additional impairment charges in 2008 were primarily due to fixed asset purchase agreements in place. Uruguaiana is a thermoelectric generation plant located in Brazil and reported in the Latin America Generation segment.

The Company recognized impairment charges totaling $31 million related to a project in South Africa the Company withdrew from during the first quarter of 2008. These represented project development costs and an

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impairment of turbine deposits related to the project. All costs capitalized and incurred on the project have been written off as no future benefit is expected from these assets. This project was reported in “Corporate and Other.”

The Anhui Development and Reform commission issued notice to our Hefei plant in China, in March 2007 as a result of the 2007 State Council’s decision to shut down smaller, inefficient and potentially polluting generation units nationwide. A settlement agreement was signed March 30, 2008 to end the contractual PPA arrangement. In accordance with the accounting standards for goodwill and other intangible assets, management concluded that the assets were impaired in March 2008, since the long-lived asset group would be sold or otherwise disposed of significantly before the end of its previously estimated life. As a result, impairment charges of $18 million were recognized associated with the settlement agreement to shut down the Hefei plant, which is reported in the Asia Generation segment.

Other Impairments

In addition to the asset impairment expense discussed above, other-than-temporary impairments of cost method investments of $1 million, $12 million and $15 million were recorded in the years ended December 31, 2010, 2009 and 2008, respectively. The impairment charges in 2009 and 2008 primarily related to the Company’s investment in a company developing a commercial facility for a “blue gas” (coal to gas) technology project. The Company accounted for the investment in convertible preferred shares under the cost method of accounting. During the fourth quarter of 2008, the market value of the shares materially declined due to downward trends in the capital markets and management concluded that the decline was other-than-temporary and recorded an impairment charge of $10 million. In 2009, this investment was determined to be further impaired and an additional $10 million other-than-temporary impairment charge, representing the remaining value of the shares, was recognized.

20. INCOME TAXES

INCOME TAX PROVISION

The following table summarizes the expense for income taxes on continuing operations, for the years ended December 31, 2010, 2009 and 2008:

	December 31,
	2010			2009			2008
	(in millions)
Federal:
Current	$	(8	)	$	3		$	12
Deferred		(118	)		(160	)		72
State:
Current		1			—			(1	)
Deferred		(19	)		(10	)		(10	)
Foreign:
Current		699			552			611
Deferred		41			195			35
Total	$	596		$	580		$	719

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EFFECTIVE AND STATUTORY RATE RECONCILIATION

The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to the Company’s effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2010, 2009 and 2008:

	December 31,
	2010			2009			2008
Statutory Federal tax rate		35	%		35	%		35	%
State taxes, net of Federal tax benefit		(2	)		(1	)		—
Taxes on foreign earnings		(6	)		(5	)		(4	)
Valuation allowance		3			—			3
Gain (loss) on sale of businesses		4			(3	)		(13	)
Chilean withholding tax reversals		(3	)		—			—
Taxes on cash repatriation		—			—			6
Other—net		—			(1	)		1
Effective tax rate		31	%		25	%		28	%

The current income taxes receivable and payable are included in Other Current Assets and Accrued and Other Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent income taxes receivable and payable are included in Other Assets and Other Long-Term Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The following table summarizes the income taxes receivable and payable as of December 31, 2010 and 2009:

	December 31,
	2010		2009
	(in millions)
Income taxes receivable—current	$	520	$	434
Income taxes receivable—noncurrent		21		22
Total income taxes receivable	$	541	$	456
Income taxes payable—current	$	701	$	508
Income taxes payable—noncurrent		8		11
Total income taxes payable	$	709	$	519

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

As of December 31, 2010, the Company had federal net operating loss carryforwards for tax purposes of approximately $1.7 billion expiring in years 2023 to 2029. Approximately $68 million of the net operating loss carryforward related to stock option deductions will be recognized in additional paid-in capital when realized. The Company also had federal general business tax credit carryforwards of approximately $18 million expiring primarily from 2020 to 2030, and federal alternative minimum tax credits of approximately $5 million that carryforward without expiration. The Company had state net operating loss carryforwards as of December 31, 2010 of approximately $3.5 billion expiring in years 2016 to 2031. As of December 31, 2010, the Company had foreign net operating loss carryforwards of approximately $4.6 billion that expire at various times beginning in 2011 and some of which carryforward without expiration, and tax credits available in foreign jurisdictions of approximately $37 million, $3 million of which expire in 2011 to 2013, $15 million of which expire in 2014 to 2021 and $19 million of which carryforward without expiration.

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Valuation allowances decreased $336 million during 2010 to $1.3 billion at December 31, 2010. This net decrease was primarily the result of the removal of valuation allowances against deferred tax assets at foreign subsidiaries.

Valuation allowances increased $261 million during 2009 to $1.7 billion at December 31, 2009. This net increase was primarily the result of an increase in foreign net operating loss carryforwards that required full offsetting valuation allowances.

The Company believes that it is more likely than not that the net deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income. The Company continues to monitor the utilization of its deferred tax asset for its U.S. consolidated net operating loss carryforward. Although management believes it is more likely than not that this deferred tax asset will be realized through generation of sufficient taxable income prior to expiration of the loss carryforwards, such realization is not assured.

The following table summarizes the deferred tax assets and liabilities, as of December 31, 2010 and 2009:

	December 31,
	2010			2009
	(in millions)
Differences between book and tax basis of property	$	1,246		$	1,694
Cumulative translation adjustment		94			(200	)
Other taxable temporary differences		392			310
Total deferred tax liability		1,732			1,804
Operating loss carryforwards		(1,655	)		(1,697	)
Capital loss carryforwards		(93	)		(107	)
Bad debt and other book provisions		(543	)		(561	)
Retirement costs		(315	)		(283	)
Tax credit carryforwards		(60	)		(68	)
Other deductible temporary differences		(413	)		(426	)
Total gross deferred tax asset		(3,079	)		(3,142	)
Less: valuation allowance		1,334			1,670
Total net deferred tax asset		(1,745	)		(1,472	)
Net deferred tax (asset)/liability	$	(13	)	$	332

The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings in accordance with the relevant accounting guidance for income taxes. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.

Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The Company’s income tax benefits related to the tax status of these operations are estimated to be $60 million, $35 million and $23 million for the years ended December 31, 2010, 2009 and 2008, respectively. The per share effect of these benefits after noncontrolling interests was $0.07, $0.04 and $0.03 for the year ended December 31, 2010, 2009 and 2008, respectively.

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The following table summarizes the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and noncontrolling interests, for the years ended December 31, 2010, 2009 and 2008:

	December 31,
	2010			2009			2008
	(in millions)
U.S.	$	(517	)	$	(1,015	)	$	(460	)
Non-U.S.		2,431			3,331			2,993
Total	$	1,914		$	2,316		$	2,533

UNCERTAIN TAX POSITIONS

Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid in one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

As of December 31, 2010 and 2009, the total amount of gross accrued income tax related interest included in the Consolidated Balance Sheets was $12 million and $21 million, respectively. The total amount of gross accrued income tax related penalties included in the Consolidated Balance Sheets as of December 31, 2010 and 2009 was $4 million and $5 million, respectively.

The total expense (benefit) for interest related to unrecognized tax benefits for the years ended December 31, 2010, 2009 and 2008 amounted to $(10) million, $4 million and $2 million, respectively. For the years ended December 31, 2010, 2009 and 2008, the total expense (benefit) for penalties related to unrecognized tax benefits amounted to $(1) million, $0 million and $(2) million, respectively.

We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:

Jurisdiction	Tax Years Subject to Examination
Argentina		2004-2010
Brazil		2005-2010
Cameroon		2007-2010
Chile		1998-2010
Colombia		2008-2010
El Salvador		2007-2010
United Kingdom		1999-2010
United States (Federal)		1994-2010

As of December 31, 2010, 2009 and 2008, the total amount of unrecognized tax benefits was $437 million, $511 million and $555 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2010, 2009 and 2008 is $412 million, $484 million and $527 million, respectively, of which $51 million, $55 million and $131 million, respectively, would be in the form of tax attributes that would warrant a full valuation allowance.

The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2010 is estimated to be between $4 million and $8 million.

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The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2010, 2009 and 2008:

	2010			2009			2008
	(in millions)
Balance at January 1	$	511		$	555		$	590
Additions for current year tax positions		14			72			6
Additions for tax positions of prior years		51			7			80
Reductions for tax positions of prior years		(46	)		(9	)		(26	)
Effects of foreign currency translation		(3	)		6			(74	)
Settlements		(67	)		(104	)		(18	)
Lapse of statute of limitations		(23	)		(16	)		(3	)
Balance at December 31	$	437		$	511		$	555

The amount of settlements of uncertain tax positions in 2009 was primarily the result of a non-cash audit settlement for $105 million at a Brazilian subsidiary which resulted in no tax expense or benefit.

The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe we have appropriately accrued for our uncertain tax benefits. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of current or future examinations may exceed our provision for current unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2010. Our effective tax rate and net income in any given future period could therefore be materially impacted.

21. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

On May 6, 2011, the Company filed its Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 which reflected Eastern Energy, Borsod and Tiszapalkonya as discontinued operations. As a result of the reclassification of these entities to discontinued operations in the consolidated financial statements for each of the three years in the period ended December 31, 2010, the Company has made changes to Notes 2, 3, 4, 6, 8, 10, 11, 12, 13, 15, 18, 19, 20, 21, 23, 24 and 26 to conform these notes to the revised financial statement presentation.

The following table summarizes the income (loss) on disposal and impairment for the following discontinued operations for the years ended December 31, 2010, 2009 and 2008:

	December 31,
Subsidiary	2010			2009			2008
	(in millions)
Barka	$	80		$	—		$	—
Lal Pir		(6	)		(74	)		—
Pak Gen		(16	)		(76	)		—
Ras Laffan		6			—			—
Jiaozuo		—			—			7
Central Valley		—			—			(1	)
Gain (loss) on disposal and impairment, after taxes	$	64		$	(150	)	$	6

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Ras Laffan—On October 20, 2010, the Company completed the sale of its 55% equity interest in Ras Laffan and the associated operations company in Qatar for aggregate proceeds of approximately $234 million. The Ras Laffan facility, which was previously reported in the Asia Generation segment, is comprised of a 756 MW combined cycle gas plant and a water desalination facility. The Company recognized a gain on disposal of $6 million, net of tax, during the year ended December 31, 2010.

Barka—On August 19, 2010, the Company completed the sale of its 35% ownership interest in Barka, a 456 MW combined cycle gas facility and water desalination plant and its wholly owned interest in two Barka related service companies. Barka is located in Oman and was previously reported in the Asia Generation segment. Total consideration received in the transaction was approximately $170 million, of which $124 million was AES’ portion. The Company recognized a gain on disposal of $63 million during the year ended December 31, 2010, net of noncontrolling interest and $38 million of tax expense associated with the sale.

Lal Pir and Pak Gen—On June 11, 2010, the Company completed the sale of its 55% ownership in Lal Pir and Pak Gen, two oil-fired facilities in Pakistan with respective generation capacities of 362 MW and 365 MW. These businesses were previously reported in the Asia Generation segment. Total consideration received in the transaction was approximately $117 million, of which $65 million was AES’ portion. The Company recognized a loss on disposal of $150 million during the year ended December 31, 2009 and impairment losses totaling $22 million ($14 million, net of tax and noncontrolling interests) during the year ended December 31, 2010 to reflect the change in the carrying value of net assets of Lal Pir and Pak Gen subsequent to meeting the held for sale criteria as of December 31, 2009.

Jiaozuo— In December 2008, the Company completed the sale of its 70% ownership interest in Jiaozuo AES Wanfang Power Co., Ltd. (“Jiaozuo”), which was reported in the Asia Generation segment, for approximately $73 million net of any withholding taxes. The Company recognized a gain on the sale of approximately $7 million. Goodwill of $4 million was written off in connection with the gain on sale.

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

	December 31,
	2010			2009			2008
	(in millions)
Revenue	$	958		$	1,251		$	1,662
Income (loss) from operations of discontinued businesses, before taxes	$	(793	)	$	99		$	238
Income tax expense (benefit)		287			(22	)		(59	)
Income (loss) from operations of discontinued businesses	$	(506	)	$	77		$	179
Gain (loss) on disposal of discontinued businesses, after taxes	$	64		$	(150	)	$	6

Eastern Energy—In March 2011, AES Eastern Energy (“AEE”) met the held for sale criteria and was reclassified from continuing operations to held for sale. AEE operates four coal-fired power plants: Cayuga, Greenidge, Somerset and Westover, representing generation capacity of 1,169 MW in the western New York power market. During 2010, the power prices in the New York power market trended downward, similar to North America natural gas prices. The New York Independent System Operator (“NYISO”) continues to move forward with the potential addition of a new capacity zone, which is expected to put further downward pressure on the capacity prices paid to the AEE facilities. In November 2010, legislation was proposed in the state of New Jersey for the addition of state subsidized capacity additions serving to lower PJM (“Pennsylvania, New Jersey and Maryland”) Interconnection, L.L.C. capacity price expectations. Similar changes to capacity pricing may be made in the future in New York. Continued pressure on energy prices, driven by falling natural gas prices and state actions, indicate that capacity prices are unlikely to reach levels significantly in excess of those achieved historically. Accordingly, management’s view of long-term capacity markets in western New York was revised

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downward. In December 2010, management revised its cash flow forecasts based on these developments and forecasted continuing negative operating cash flow and losses through 2034. The forecasted energy prices are such that a hedge strategy significantly beyond those in place at December 31, 2010 would not be economical. Additionally, on November 15, 2010, Standard & Poor’s downgraded the bond rating of AEE from BB to B+. Collectively, in the fourth quarter of 2010, these events were considered an impairment indicator for the AES New York asset group, of which AEE is the most significant component and necessitated a recoverability test of the asset group.

The long-lived asset group subject to the impairment evaluation was determined to include all of the generating plants of AEE. This determination was based on the assessment of the plants’ inability to generate independent cash flow. When the recoverability test of the asset group was performed, management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was not recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. While there were numerous assumptions that impact the fair value, potential state actions that impact capacity pricing and forward energy prices were the most significant.

In determining the fair value of the asset group, the three valuation approaches prescribed by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered the most appropriate and resulted in a zero fair value. Any salvage value of the asset group is expected to be offset by environmental and other remediation costs. The carrying value of the AEE plants of $827 million exceeded the fair value of $0 million resulting in the recognition of asset impairment expense of $827 million, which is included in Income from operations of discontinued businesses for the year ended December 31, 2010. AEE was previously reported in the North America Generation segment.

Borsod and Tiszapalkonya—In March 2011, Borsod and Tiszapalkonya met the held for sale criteria and were reclassified from continuing operations to held for sale. Borsod and Tiszapalkonya are two coal and biomass-fired generation plants in Hungary with generating capacity of 161 MW. They were previously reported in the Europe Generation segment.

As further discussed in Note 22—Acquisitions and Dispositions, in February 2008, the Company entered into an agreement to sell two of its wholly owned subsidiaries in Kazakhstan, AES Ekibastuz LLP (“Ekibastuz”) and Maikuben West LLP (“Maikuben”). These businesses are included in the Europe Generation segment. The sale was completed on May 30, 2008. As a result of AES’ continuing involvement in the management and operations of the businesses after the sale was completed, their results of operations continued to be reflected as part of income from continuing operations for all periods presented. Revenue recognized subsequent to the sale represented the management fees earned for the Company’s continued management of the operations of the businesses.

22. ACQUISITIONS AND DISPOSITIONS

Acquisitions

The Company completed its acquisition of the Ballylumford Power Station in the third quarter of 2010 and in accordance with the accounting guidance for business combinations, has recorded the preliminary amounts for the purchase price allocation. The purchase price allocation is preliminary and adjustments will continue to be made during the measurement period. Subsequent adjustments, if any, will be retrospectively adjusted in future filings with the SEC.

In April 2008, the Company completed the purchase of a 92% interest in a 660 gross MW coal-fired thermal power generation facility in Masinloc, Philippines (“Masinloc”) from the Power Sector Assets & Liabilities

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Management Corporation, a state enterprise, for $930 million in cash. Project financing of $665 million was obtained from International Finance Corporation (“IFC”), the Asian Development Bank and a consortium of commercial banks. IFC is also an 8% minority shareholder in Masinloc. AES immediately embarked upon a comprehensive rehabilitation program to improve the output, reliability and general condition of the plant. Including transaction costs and completion of the planned upgrade program to improve environmental and operational performance, the total project cost was approximately $1.1 billion. Beginning on the acquisition date in April 2008, the results of operations of Masinloc are reflected in the Consolidated Financial Statements. The Company finalized the purchase price allocation of this acquisition in the fourth quarter of 2008.

Dispositions

On May 30, 2008, the Company completed the sale of two of its wholly owned subsidiaries in Kazakhstan, Ekibastuz, a coal-fired generation plant, and Maikuben, a coal mine. Total consideration received in the transaction was approximately $1.1 billion plus additional potential earn-out provisions, a three-year management and operation agreement and a capital expenditures program bonus. Due to the fact that AES was to have significant continuing involvement in the management and operations of the businesses through its three-year management and operation agreement, the results of operations from Ekibastuz and Maikuben were included in income from continuing operations through the date of the disposition. Income earned as a result of the three-year management and operation agreement has been recognized as management fee income for all periods subsequent to the disposition.

On March 23, 2009, the Company and Kazakhmys PLC (“Kazakhmys”), which purchased the subsidiaries, mutually agreed to terminate the original sale agreement and the three-year management and operation agreement. In connection with the termination of these agreements, the Company and Kazakhmys entered into a new agreement (the “2009 Agreement”). Under the 2009 Agreement, Kazakhmys agreed to pay the Company an $80 million performance incentive bonus in April 2009 for management services provided in 2008. This was recognized as “Other Income” during the first quarter of 2009. A $13 million gain was recognized related to a reversal of a tax contingency for a contractual obligation, under which the Company provided indemnification to Kazakhmys, which expired in January 2009. This was recorded as an adjustment to the gain on the sale of Ekibastuz and Maikuben during the first quarter of 2009.

The 2009 agreement also provided for an additional $102 million payment, primarily related to the termination of the management agreement, payable to AES in January 2010. In May 2009, Kazakhmys provided an irrevocable standby letter of credit from a creditworthy institution to AES of $102 million to secure the final payment. The payment of the final component of the management termination agreement was not contingent upon any future events. As a result, the Company recognized an additional gain on the sale of Ekibastuz and Maikuben of approximately $98.5 million in the second quarter of 2009. AES received the final payment of $102 million from Kazakhmys in January 2010.

The parties agreed to terminate both the Stock Purchase Agreement and the Management Agreement, and have further agreed to a mutual release of prior claims. As part of the management termination agreement, AES agreed to transition the management of the businesses to Kazakhmys over a period of 100 days from March 13, 2009. The transition period ended June 21, 2009 and at that time the management of Ekibastuz and Maikuben became the responsibility of Kazakhmys. The Company’s involvement with the businesses remained in place for more than one year from the date of the sale; therefore, the Company has continued to include the businesses as part of continuing operations in the Consolidated Financial Statements for all periods presented, despite the termination of the management agreement.

Excluding income earned under the three-year management and operation agreement (terminated in March 2009), Ekibastuz and Maikuben generated no revenue or net income in 2010 and 2009 and generated revenue and net income of $114 million and $61 million, respectively, for the year ended December 31, 2008.

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23. EARNINGS PER SHARE

Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.

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

	December 31, 2010						December 31, 2009						December 31, 2008
	Income		Shares		$ per Share		Income		Shares		$ per Share		Income		Shares		$ per Share
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	495		769	$	0.64	$	729		667	$	1.09	$	1,088		669	$	1.62
EFFECT OF DILUTIVE SECURITIES
Convertible securities		—		—		—		—		—		—		22		15		(0.01	)
Stock options		—		2		—		—		1		—		—		4		—
Restricted stock units		—		3		—		—		2		—		—		1		—
DILUTED EARNINGS PER SHARE	$	495		774	$	0.64	$	729		670	$	1.09	$	1,110		689	$	1.61

The calculation of diluted earnings per share excluded 16,618,137, 18,035,813 and 11,150,853 options outstanding at December 31, 2010, 2009 and 2008, respectively, that could potentially dilute basic earnings per share in the future. Those options were not included in the computation of diluted earnings per share because the exercise price of those options exceeded the average market price during the related period. In 2010 and 2009, all convertible debentures were omitted from the earnings per share calculation because they were antidilutive. In 2008, all convertible debentures were included in the earnings per share calculation. In arriving at income attributable to AES Corporation common stockholders in computing basic earnings per share, dividends on preferred stock of our subsidiary were deducted.

In addition, on March 15, 2010, the Company issued 125,468,788 shares of common stock to an investor as described in Note 14—Equity.

24. RISKS AND UNCERTAINTIES

AES is a global power producer in 28 countries on five continents. See additional discussion of the Company’s principal markets in Note 15—Segment and Geographic Information. Our principal lines of business are Generation and Utilities. The Generation line of business uses a wide range of technologies, including coal, gas, hydroelectric, and biomass as fuel to generate electricity. Our Utilities business is comprised of businesses that transmit, distribute, and in certain circumstances, generate power. In addition, the Company continues to expand its reach into the renewables area. These efforts include projects primarily in wind and solar.

POLITICAL AND ECONOMIC RISKS—The Company’s market capitalization was negatively impacted largely in the second half of 2008 and in 2009. During this period, credit markets and global markets deteriorated and experienced increased market volatility, which can pose risks to the overall liquidity and/or asset values of our businesses with heightened unpredictability in currencies, counterparty credit risk and the widening of credit spreads in certain markets. If market conditions are protracted or continue to deteriorate, the Company may be at risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities

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and foreign currency spot markets or deterioration in global macroeconomic conditions. With the tightening of the credit markets, there is a risk that future investments may not be able to be financed through accessing capital and debt markets and may be subject to restrictions in the near future.

Currently, the Company has a below-investment grade rating from Standard & Poor’s of BB-. This may limit the ability of the Company to finance new and existing development projects to cash currently available on hand and through reinvestment of earnings. As of December 31, 2010, the Company had $2.6 billion of unrestricted cash and cash equivalents.

During 2010, approximately 86% of our revenue, and 56% of our revenue from discontinued businesses, was generated outside the United States and a significant portion of our international operations is conducted in developing countries. We continue to invest in projects in developing countries because the growth rates and the opportunity to implement operating improvements and achieve higher operating margins may be greater than those typically achievable in more developed countries. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:

• economic, social and political instability in any particular country or region;

• ability to economically hedge energy prices;

• volatility in commodity prices;

• adverse changes in currency exchange rates;

• government restrictions on converting currencies or repatriating funds;

• unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;

• high inflation and monetary fluctuations;

• restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;

• threatened or consummated expropriation or nationalization of our assets by foreign governments;

• unwillingness of governments, government agencies, similar organizations or other counterparties to honor their contracts;

• unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;

• inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;

• adverse changes in government tax policy;

• difficulties in enforcing our contractual rights or enforcing judgments or obtaining a just result in local jurisdictions; and

• potentially adverse tax consequences of operating in multiple jurisdictions.

Any of these factors, individually or in combination with others, could materially and adversely affect our business, results of operations and financial condition. In addition, our Latin American operations experience volatility in revenue and earnings which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability and currency fluctuations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.

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Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain expected or contracted increases in electricity tariff rates or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analysts’ expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our Utilities businesses where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:

• changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;

• changes in the definition or determination of controllable or noncontrollable costs;

• adverse changes in tax law;

• changes in the definition of events which may or may not qualify as changes in economic equilibrium;

• changes in the timing of tariff increases;

• other changes in the regulatory determinations under the relevant concessions; or

• changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.

Any of the above events may result in lower margins for the affected businesses, which can adversely affect our business.

RISKS RELATED TO FOREIGN CURRENCIES—AES operates businesses in many foreign countries and such operations may be impacted by significant fluctuations in foreign currency exchange rates. The Company’s financial position and results of operations have been significantly affected by fluctuations in the value of the Brazilian real, the Argentine peso, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian peso and the Philippine peso relative to the U.S. Dollar.

RISKS RELATED TO POWER SALES CONTRACTS—Several of the Company’s power plants rely on power sales contracts with one or a limited number of entities for the majority of, and in some case all of, the relevant plant’s output over the term of the power sales contract. The remaining term of the power sales contracts related to the Company’s power plants range from less than one to 38 years. No single customer accounted for 10% or more of total revenue in 2010, 2009, or 2008.

The cash flows and results of operations of such plants are dependent on the credit quality of the purchasers and the continued ability of their customers and suppliers to meet their obligations under the relevant power sales contract. If a substantial portion of the Company’s long-term power sales contracts were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company’s cash flow, results of operations and financial condition.

25. RELATED PARTY TRANSACTIONS

Our generation businesses in Panama are partially owned by the Government of Panama (the “Panamanian Government”). The Panamanian Government, in turn, partially owns the distribution companies within Panama. For the years ended December 31, 2010, 2009 and 2008, our Panamanian businesses recognized electricity sales to the Panamanian Government totaling $146 million, $143 million and $203 million, respectively. For the same period, our Panamanian businesses purchased electricity, which excludes transmission charges from the Panamanian Government, totaling $21 million, $25 million and $27 million, respectively. As of December 31,

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2010 and 2009, our Panamanian businesses owed the Panamanian Government $4 million and $7 million, respectively, payable on normal trade terms. For the same period, the Panamanian Government owed our Panamanian businesses $12 million and $25 million, respectively, payable on normal trade terms.

Our generation businesses in the Dominican Republic are partially owned by the Government of the Dominican Republic (the “Dominican Government”). The Dominican Government, in turn, owns the distribution companies within the Dominican Republic. For the years ended December 31, 2010, 2009 and 2008, our Dominican Republic businesses recognized electricity sales to the Dominican Government totaling $179 million, $204 million and $244 million, respectively. For the same period, the Dominican Government owed our Dominican Republic businesses $88 million and $121 million, respectively, payable on normal trade terms.

In December 2010, ESSA , one of our subsidiaries in Latin America, signed termination agreements related to its long term gas transportation contracts that were under dispute in arbitration tribunals. As a result of these settlements, ESSA paid $52 million to two of the gas transportation companies which are related parties and recorded a loss of $43 million. In addition, an aggregate amount of $16 million was payable to these related parties at December 31, 2010. See Note 12—Contingencies, Litigations for details.

26. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly Financial Data

The following tables summarize the unaudited quarterly statements of operations for the Company for 2010 and 2009. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods. Amounts have been restated to reflect discontinued operations in all periods presented.

	Quarter ended 2010
	Mar 31		June 30			Sept 30		Dec 31
	(in millions, except per share data)
Revenue	$	3,920	$	3,923		$	4,020	$	4,318
Gross margin		961		1,002			982		1,043
Income from continuing operations, net of tax(1)		381		429			300		391
Discontinued operations, net of tax		21		—			97		(560	)
Net income (loss)	$	402	$	429		$	397	$	(169	)
Net income (loss) attributable to The AES Corporation	$	187	$	144		$	114	$	(436	)
Basic income (loss) per share:
Income from continuing operations attributable to The AES Corporation, net of tax	$	0.24	$	0.19		$	0.06	$	0.16
Discontinued operations attributable to The AES Corporation, net of tax		0.03		(0.01	)		0.08		(0.71	)
Basic income (loss) per share attributable to The AES Corporation	$	0.27	$	0.18		$	0.14	$	(0.55	)
Diluted income (loss) per share:
Income from continuing operations attributable to The AES Corporation, net of tax	$	0.24	$	0.19		$	0.06	$	0.16
Discontinued operations attributable to The AES Corporation, net of tax		0.03		(0.01	)		0.08		(0.71	)
Diluted income (loss) per share attributable to The AES Corporation	$	0.27	$	0.18		$	0.14	$	(0.55	)

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	Quarter ended 2009
	Mar 31		June 30		Sept 30		Dec 31
	(in millions, except per share data)
Revenue	$	3,083	$	3,163	$	3,529	$	3,665
Gross margin		833		790		961		822
Income from continuing operations, net of tax(2)		481		513		422		412
Discontinued operations, net of tax		21		17		18		(129	)
Net income	$	502	$	530	$	440	$	283
Net income (loss) attributable to The AES Corporation	$	218	$	303	$	185	$	(48	)
Basic income (loss) per share:
Income from continuing operations attributable to The AES Corporation, net of tax	$	0.31	$	0.44	$	0.27	$	0.07
Discontinued operations attributable to The AES Corporation, net of tax		0.02		0.01		0.01		(0.14	)
Basic income (loss) per share attributable to The AES Corporation	$	0.33	$	0.45	$	0.28	$	(0.07	)
Diluted income (loss) per share:
Income from continuing operations attributable to The AES Corporation, net of tax	$	0.31	$	0.44	$	0.27	$	0.07
Discontinued operations attributable to The AES Corporation, net of tax		0.02		0.01		0.01		(0.14	)
Diluted income (loss) per share attributable to The AES Corporation	$	0.33	$	0.45	$	0.28	$	(0.07	)

⁽¹⁾  Includes pretax impairment expense of $315 million and $96 million, for the third and fourth quarters of 2010, respectively. See Note 19—Impairment Expense and Note 8—Goodwill and Other Intangible Assets for additional discussion on these impairment expenses.

⁽²⁾  Includes pretax impairment expense $140 million for the fourth quarter of 2009. See Note 19—Impairment Expense and Note 8—Goodwill and Other Intangible Assets for additional discussion on the impairment expense.

27. SUBSEQUENT EVENTS

Subsequent to December 31, 2010, the Company continued to repurchase stock under the stock repurchase program announced on July 7, 2010. The Company has repurchased 1,026,610 shares at a cost of $13 million in 2011, bringing the cumulative total through February 22, 2011 to 9,409,435 shares at a total cost of $112 million (average price of $11.92 per share including commissions). As of February 22, 2011, $388 million of the $500 million authorized remained available under the stock repurchase program. For additional information, see Note 14—Equity included in Item 8 of this Form 8-K.

On February 1, 2011, AES Thames, LLC (“Thames”), our 208 MW coal-fired plant in Connecticut, filed petitions for bankruptcy protection under Chapter 11 in the U. S. Bankruptcy Court. The bankruptcy is due, in part, to the increased cost of energy production. The bankruptcy protection is not expected to have a material impact on the Company’s financial position or the results of operations.

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Exhibit 12

The AES Corporation and Subsidiaries

Statement Re: Calculation of Ratio of Earnings to Fixed Charges

(in millions, unaudited)

	2010			2009			2008			2007			2006
Actual:
Computation of earnings:
Income from continuing operations before income taxes and equity in earnings of affiliates	$	1,914		$	2,316		$	2,533		$	1,073		$	673
Fixed charges		1,763			1,732			2,017			1,878			1,824
Amortization of capitalized interest		51			35			32			15			15
Distributed income of equity investees		14			68			183			21			19
Less:
Capitalized interest		(193	)		(183	)		(172	)		(84	)		(50	)
Preference security dividend of consolidated subsidiary		(5	)		(4	)		(4	)		(6	)		(5	)
Noncontrolling interests in pretax income of subsidiaries that have not incurred fixed charges(1)		(4	)		(8	)		—			—			—
Earnings	$	3,540		$	3,956		$	4,589		$	2,897		$	2,476
Fixed charges:
Interest expense, debt premium and discount amortization	$	1,565		$	1,545		$	1,841		$	1,788		$	1,769
Capitalized interest		193			183			172			84			50
Preference security dividend of consolidated subsidiary		5			4			4			6			5
Fixed charges	$	1,763		$	1,732		$	2,017		$	1,878		$	1,824
Ratio of earnings to fixed charges		2.01			2.28			2.28			1.54			1.36

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