Form 20-F

As filed with the Securities and Exchange Commission on March 31, 2010

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 20-F

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

For the fiscal year ended December 31, 2009

Commission File Number: 000-53606

AEI

(exact name of registrant as specified in its charter)

Cayman Islands
(jurisdiction of incorporation or organization)

Clifton House, 75 Fort Street, P.O. Box 190GT
George Town, Grand Cayman, Cayman Islands
(address of principal executive offices)

Maureen J. Ryan
Executive Vice President, General Counsel and Chief Compliance Officer
AEI Services LLC, 700 Milam, Suite 700, Houston, Texas 77002 (713) 345-5200 maureen.ryan@aeienergy.com
(name, telephone, e-mail and/or facsimile number and address of company contact person)

Securities registered or to be registered pursuant to Section 12(b) of the Act: None.

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Ordinary shares $0.002 par value
(Title of class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None.

The number of outstanding shares of each of the issuer’s classes of capital or common stock as of December 31, 2009 was:

244,113,499 Ordinary Shares

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No þ

If this report is an annual report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes o No þ

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

Yes þ No o

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12-b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non accelerated filer þ

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S.GAAP þ International Financial Reporting Standards as issued by the International Accounting Standards Board o Other o

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

INTRODUCTION

AEI was incorporated in the Cayman Islands in June 2003. In this annual report, the terms “AEI,” “we,” “us,” “our,” “the Company,” and “our company” means AEI and its subsidiaries, unless otherwise indicated. Our principal executive offices are located at Clifton House, 75 Fort Street, P.O. Box 190GT, George Town, Grand Cayman, Cayman Islands and our telephone number is 345-949-4900. The principal executive offices of our wholly owned affiliate AEI Services LLC, which provides management services to us, are located at 700 Milam, Suite 700, Houston, TX 77002, and its telephone number is 713-345-5200.

BUSINESS OF AEI

We organize our operations into five business segments, namely Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel within five regions, namely Andean, Southern Cone, Central America/Caribbean, China and Europe/Middle East/North Africa. The following business segment statistics are as of December 31, 2009.

	•		Power Distribution: approximately 27,300 GWh sold, 4.9 million electric power customers, and 121,100 miles of power distribution and transmission lines;

	•		Power Generation: approximately 9,600 GWh sold, and 2,278 MW of electric power generation capacity with an additional 300 MW under construction;

	•		Natural Gas Transportation and Services: approximately 3,300 mmcfd average throughput and 4,900 miles of natural gas and gas liquids transportation pipelines;

	•		Natural Gas Distribution: approximately 400 mmcfd average sales, 2.5 million natural gas distribution customers and 21,800 miles of natural gas distribution pipeline networks; and

	•		Retail Fuel: approximately 4.7 mm gal/day average throughput of liquid fuels, 34.9 mmcfd average sales of compressed natural gas, or CNG, and 1,861 owned and affiliated gasoline and CNG service stations. Retail Fuel is a non-core business for us and we are currently exploring strategic alternatives with respect to that business.

For the year ended December 31, 2009, we generated consolidated operating income of $731 million, net income attributable to AEI of $297 million and Adjusted EBITDA of $1,146 million.

To learn more, please visit our web site at www.aeienergy.com and see “Item 4. Information on the Company — B. Business Overview” beginning on page 31.

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NON-GAAP FINANCIAL MEASURES

The body of generally accepted accounting principles is commonly referred to as “GAAP.” For this purpose, a non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or the SEC, as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measure. From time to time we disclose non-GAAP financial measures, primarily Gross Margin, Adjusted EBITDA, Adjusted Net Income and Net Debt in our communications with investors, financial analysts and the public. These non-GAAP measures are a basis upon which we assess our financial performance. The non-GAAP financial measures described herein or in other documents we issue are not a substitute for the GAAP measures of earnings and liquidity.

We define Gross Margin as revenues less cost of sales. A significant portion of our businesses’ revenues are related to either regulated tariffs or to long-term contracts, most of which have pass-through provisions for the cost of energy, fuel and gas. Our revenues and cost of sales may be significantly impacted by the volatility in energy and fuel prices. Because of the pass-through provisions, fluctuations in revenues and cost of sales taken in absolute terms may themselves not be meaningful in the analysis of our financial results. Gross Margin is generally perceived as a measure of our operating performance which eliminates the volatility in energy and fuel prices related to the pass-through provisions.

We define Adjusted EBITDA as net income attributable to AEI excluding the effects of discontinued operations, income taxes, gains and losses on early retirement of debt, interest, depreciation and amortization, foreign currency transaction gains and losses, gains and losses on disposition of assets, other income (expense), net, and impairments and other charges. Adjusted EBITDA is generally perceived as a useful and comparable measure of operating performance. For example, interest and gains and losses on early retirement of debt are dependent on the capital structure and credit rating of a company. However, debt and cash levels, credit ratings and, therefore, the impact of interest and gains and losses on early retirement of debt on earnings vary significantly between companies. Similarly, the tax positions of individual companies can vary because of their differing abilities to take advantage of tax benefits, with the result being that their effective tax rates and tax expense can vary considerably. Companies also differ in the age and method of acquisition of productive assets, and thus the relative costs of those assets, as well as in the depreciation (straight-line, accelerated, units of production) method, which can result in considerable variability in depreciation and amortization expense between companies. Certain other items that may fluctuate over time as a result of external factors over which management has little to no control, such as foreign currency transaction gains and losses, impairments and other charges, can vary not only among companies but within a particular company across time periods, and thus significantly impact the comparability of earnings both externally and from period to period. Finally, the effects of discontinued operations can distort comparability as well as expectations of future financial performance. Thus, for comparison purposes with other companies, management believes, based on discussions with financial analysts and other users of the financial statements, that Adjusted EBITDA can be useful as an objective and comparable measure of operating profitability because it excludes these elements of earnings that may not consistently provide information about the current and ongoing operations of existing assets.

We define Adjusted Net Income as net income attributable to AEI excluding impairments and other charges, foreign currency transaction gains and losses, gains and losses on early retirement of debt, gains and losses on sales of assets, and settlements that are not related to the periods presented. We exclude these items from our internal measurements of performance. These items are generally non-cash and are not included by investors, financial analysts and the public when determining valuation and expectations for future performance of the company. Thus, for comparison purposes with other companies, management believes, based on discussions with financial analysts and other users of the financial statements, that Adjusted Net Income can be useful as an objective and comparable measure of operating profitability because it excludes these elements of earnings that may not consistently provide information about the current and ongoing operations of existing assets.

We define Net Debt as total debt less cash and cash equivalents, current restricted cash and non-current restricted cash. Net Debt, both on a consolidated basis and for our individual operating companies, is perceived as a useful and comparable measure of our liquidity. Debt levels, cash deposits for debt service requirements and other cash management policies vary in significance between companies. Thus, for comparison purposes, management believes that Net Debt can be useful as an objective and comparable measure of our liquidity because it recognizes the cash position of the current operations.

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Management utilizes the non-GAAP measures of Gross Margin, Adjusted EBITDA, Adjusted Net Income and Net Debt as key indicators of the financial performance and liquidity of our reporting segments and the underlying businesses. Gross Margin, Adjusted EBITDA, Adjusted Net Income and Net Debt are calculated for the annual budgeting process and are reported upon in our monthly and quarterly internal reporting processes. Our key valuation multiples are computed using Adjusted EBITDA and Net Debt. In addition, the primary ratio for determining the level of our investment capacity utilizes Adjusted EBITDA and Net Debt as inputs. Adjusted EBITDA, Adjusted Net Income and Net Debt are used in our compensation determinations. Finally, these metrics and others are analyzed and summarized for discussions or presentations to our equity and debt investors, financial analysts and the public. Accordingly, although Gross Margin, Adjusted EBITDA, Adjusted Net Income and Net Debt as calculated by us may not be comparable to calculations of similarly titled measures by other companies, management believes that disclosure of these non-GAAP measures can provide useful information to investors, financial analysts and the public in their evaluation of our operating performance or liquidity.

For additional non-GAAP information and reconciliations to GAAP measures, see “Item 3. Key Information — A. Selected Financial Data,” “Item 5 — Operating and Financial Review and Prospects,” and Annexes I and II.

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PRESENTATION OF INFORMATION

This annual report is based on information provided by us and by other sources that we believe are reliable. This annual report summarizes certain documents and other information and we refer you to them for a more complete understanding of what we discuss in this annual report.

This annual report includes information regarding corporate and country ratings from ratings agencies. Ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from the rating agency.

In this annual report, unless otherwise specified or if the context so requires, references to:

	•		“Argentine pesos” or “AR$” are to the lawful currency of Argentina;

	•		“Brazilian real,” “Brazilian reais” or “R$” are to the lawful currency of Brazil;

	•		“Chilean pesos” or “CLP” are to the lawful currency of Chile;

	•		“Chinese renminbi” or “RMB” are to the lawful currency of China;

	•		“Colombian pesos” or “COP” are to the lawful currency of Colombia;

	•		“Jamaican dollars” are to the lawful currency of Jamaica;

	•		“Pakistani rupees” or “PKR” are to the lawful currency of Pakistan;

	•		“Peruvian nuevos soles” are to the lawful currency of Peru;

	•		“Polish zlotys” or “PLN” are to the lawful currency of Poland;

	•		“New Turkish lira” or “TRY” are to the lawful currency of Turkey; and

	•		“Dollars,” “U.S. dollars,” “$” or “U.S.$” are to the lawful currency of Ecuador, El Salvador, Panama and the United States.

For additional defined terms, see “Glossary of Technical Terms” and “Glossary of Defined Terms,” included elsewhere in this annual report.

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FORWARD-LOOKING STATEMENTS

This annual report includes certain forward-looking statements (particularly in “Item 3. Key Information — D. Risk Factors,” “Item 4. Information on the Company — B. Business Overview” and “Item 5. Operating and Financial Review and Prospects”). These forward-looking statements are based principally on our current expectations and on projections of future events and financial trends that currently affect or might affect our business. In addition to the items discussed in other sections of this annual report, there are many significant factors that could cause our financial condition and results of operations to differ materially from those set out in our forward-looking statements, including factors such as:

	•		Our businesses are in emerging markets. Our results of operations and financial condition are dependent upon economic conditions in those countries in which we operate, and any decline in economic conditions could harm our results of operations or financial condition.

	•		Governments have a high degree of influence in the economies in which we operate. This influence could harm our result of operations or financial condition.

	•		The uncertainty of the legal and regulatory environment in certain countries in which we operate, develop or construct infrastructure assets may make it difficult for us to enforce our rights under agreements relating to our businesses.

	•		Currency exchange rate fluctuations relative to the U.S. dollar in the countries in which we operate our businesses may adversely impact our results of operations or financial condition.

	•		Most of our businesses are subject to significant governmental regulations and our results of operations and financial condition could be adversely affected by changes in the law or regulatory schemes (including proposed climate change legislation).

	•		The tariffs of most of our business segments are regulated and periodically revised by regulators. Reductions in tariffs could result in the inability of our businesses to recover operating costs, including commodity costs and/or investments and maintain current operating margins.

	•		The operation of our businesses involves significant risks that could adversely affect our results of operations or financial condition.

	•		Other risk factors set forth in “Item 3. Key Information — D. Risk Factors.”

The words “believe,” “expect,” “continue,” “understand,” “hope,” “estimate,” “will,” “may,” “might,” “should,” “intend” and other similar expressions are intended to identify forward-looking statements and estimates. Such statements refer only to the date on which they were expressed and we assume no obligation to publicly update or revise any such estimates resulting from new information or any other events. As a result of the inherent risks and uncertainties involved, the forward-looking statements included in this annual report may not be accurate and our future results of operations and performance may differ materially from those set out for a number of different reasons. No forward-looking statement in this annual report is a guarantee of future performance and each estimate involves risks and uncertainties.

Investors are cautioned not to place undue reliance on any forward-looking statements.

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GLOSSARY OF DEFINED TERMS

Certain terms used in this annual report are defined below:


Accroven		Accroven S.R.L., our Venezuelan Natural Gas Transportation and Services business

AEIL		Ashmore Energy International Limited, a Cayman Islands company formed by Ashmore that was merged into PEI

ANEEL		Brazilian National Electric Energy Agency (Agência Nacional de Energia Elétrica)

Amayo		Consorcio Eólico Amayo S.A., one of our Nicaraguan Power Generation businesses

ASEP		Panamanian National Authority of Public Services (Autoridad Nacional de los Servicios Públicos)

Ashmore		Ashmore Investment Management Limited

Ashmore Funds		Investment funds directly or indirectly managed by Ashmore

Bahía Blanca		Parque Eólico Bahía Blanca, an Argentine wind project under development in partnership with Pattern

BBPL		Bolivia-to-Brazil Pipeline which is comprised of GTB and TBG

BLM		Bahía Las Minas Corp., our Panamanian Power Generation business which we sold on March 14, 2007

BMG		Beijing MacroLink Gas Co. Ltd., one of our Chinese Natural Gas Distribution businesses

BNDES		Brazilian Economic Development Bank (Banco Nacional de Desenvolvimento Econômico e Social)

BOTAŞ		Boru Hatlari Ile Petrol Taşima A.Ş., the Turkish government owned natural gas monopoly

CAMMESA		Compañía Administradora del Mercado Mayorista Eléctrico S.A., the Argentine state-run power pool administrator

Cálidda		Gas Natural de Lima y Callao S.A., our Peruvian Natural Gas Distribution business

CBC		Cantonment Board Clifton, a private Pakistani company that buys water from DCL

CDEEE		Dominican Corporation of State Electricity Companies (Corporación Dominicana de Empresas Eléctricias Estatales), a Dominican Republic state-run power company

CEEE		Brazilian Chamber of Electric Energy Commercialization (Câmara de Comercialização de Energia Elétrica)

Centragas		Centragas, one of our Colombian Natural Gas Transportation and Services business

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Centrans		Centrans Energy Services Inc., an energy services company that develops and operates projects in Central America and the Caribbean

Chilquinta		Chilquinta Energía S.A. and associated companies, our Power Distribution business in Chile

CNE		Chilean National Energy Commission (Comisión Nacional de Energía)

Colombian MME		Colombian Ministry of Mines and Energy

Corinto		Empresa Energética Corinto Ltd., one of our Nicaraguan Power Generation businesses

CREG		Colombian Regulatory Commission for Energy and Gas (Comisión de Regulación de Energía y Gas)

Cuiabá Integrated Project		Integrated project in Bolivia and Brazil consisting of EPE, GOB, GOM and TBS

Delsur		Distribuidora de Electricidad Del Sur, S.A. de C.V., our El Salvadorian Power Distribution business

DCL		DHA Cogen Limited, our Pakistani Power Generation business

Ecopetrol		Ecopetrol S.A., the Colombian state-controlled petroleum company

EDELAR		Empresa Distribuidora de La Rioja S.A., a subsidiary of EMDERSA

EDEN		Empresa Distribuidora de Energía Norte S.A., one of our Argentine Power Distribution businesses

EDESA		Empresa Distribuidora de Salta S.A., a subsidiary of EMDERSA

EDESAL		Empresa Distribuidora de San Luis S.A., a subsidiary of EMDERSA

EEGSA		Empresa Eléctrica de Guatemala S.A., a Guatemalan power distributor

EGSSA		EMDERSA Generacíon Salta S.A., a subsidiary of EMDERSA

El Arrayán		Parque Eólico El Arrayán, a Chilean wind project under development in partnership with Pattern

Elektra		Elektra Noreste, S.A., our Panamanian Power Distribution business and one of our predecessor companies

Elektro		Elektro Eletricidad e Serviços S.A., our Brazilian Power Distribution business

Emgasud		Emgasud S.A., our Argentine Power Generation, Natural Gas Transportation and Services and Natural Gas Distribution business

EMDERSA		Empresa Distribuidora Electrica Regional S.A., one of our Argentine Power Distribution holding companies

ENARSA		Energía Argentina S.A., an Argentine state-run power company

Enersud		Enersud Energy S.A., a subsidiary of Emgasud

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ENS		Elektrocieplownia Nowa Sarzyna Sp. z.o.o., our Polish Power Generation business

EPE		Empresa Produtora de Energia Ltda., one of our Brazilian Power Generation businesses and part of the Cuiabá Integrated Project

ESED		Empresa de Sistemas Eléctricos Dispersos, a subsidiary of EDESA

Eton Park		Eton Park Capital Management, L.P., a hedge fund that owns a portion of AEI common shares

Fenix		Fenix Power Peru S.A., our Peruvian company in the advanced stages of developing a combined-cycle power plant in Chilca, Peru

Gases de Occidente		Gases de Occidente S.A. E.S.P., one of our Colombian Natural Gas Distribution businesses

Gases del Caribe		Gases del Caribe S.A. E.S.P., one of our Colombian Natural Gas Distribution businesses

GBS		Gases de Boyacá y Santander, GBS S.A., one of our Colombian Natural Gas Distribution businesses and part of Promigas

Gazel		Gas Natural Comprimido S.A., one of our Colombian Retail Fuel businesses which is owned by Proenergía

GOB		GasOriente Boliviano Ltda., one of our Bolivian Natural Gas Transportation and Services businesses and part of the Cuiabá Integrated Project

GOM		GasOcidente do Mato Grosso Ltda, one of our Brazilian Natural Gas Transportation and Services businesses and part of the Cuiabá Integrated Project

GTB		Gas Transboliviano S.A., one of our Bolivian Natural Gas Transportation and Services businesses and part of the Bolivia-to-Brazil Pipeline

Huatong		Huatong (Shanghai) Investment Co., Ltd., our Chinese Natural Gas Distribution business

Jaguar		Jaguar Energy Guatemala LLC, our Guatemalan company in the advanced stages of developing a solid fuel-fired power generation facility in Puerto Quetzal, Guatemala

JPPC		Jamaica Private Power Company Ltd., our Jamaican Power Generation business

JPS		Jamaica Public Services Company Limited, a private/public power company

KESC		Karachi Electric Supply Company, a private Pakistani power company

Luoyang		Luoyang Sunshine Cogeneration Co., Ltd., our Chinese Power Generation business

Luz del Sur		Luz del Sur S.A. A. and associated companies, our Power Distribution business in Peru

MEM		Peruvian Ministry of Energy and Mines

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MENR		Turkish Ministry of Energy and Natural Resources

MetroGas		MetroGas S.A., an Argentine Natural Gas Distribution business

NPC		National Power Corporation of the Philippines

OSINERGMIN		Peruvian Supervisory Organization of Investment in Energy and Mining (Organismo Supervisor de la Inversión en Energía y Mineria)

Pattern		Pattern Energy, our partner in the joint development of potential wind projects in Brazil, Argentina and Chile

PDVSA		Petróleos de Venezuela, S.A., the Venezuelan state-owned oil company

PDVSA Gas		A wholly-owned subsidiary of PDVSA

PEI		Prisma Energy International, Inc., one of our predecessor companies

Poliwatt		Politwatt Limitada, a wholly owned subsidiary of PQP

PQP		Puerto Quetzal Power LLC, our Guatemalan Power Generation business

Proenergía		Proenergía Internacional S.A, the holding company of SIE and our Retail Fuel businesses

Promigas		Promigas S.A. ESP, our Colombian company which holds the interests in our Colombian Natural Gas Transportation and Services and Natural Gas Distribution businesses

Promigas Pipeline		1,297 mile pipeline in Colombia extending along the Atlantic coast from Ballena to Jobo, which is owned by Promigas

PSI		Promigas Servicios Integrados, one of our Colombian Natural Gas Transportation and Services businesses

San Felipe		Generadora San Felipe Limited Partnership, our Dominican Republic Power Generation business

Sempra		Sempra Energy International, a California corporation that operates natural gas-fired power plants, pipelines and storage facilities globally, and our partner in Chilquinta and Luz del Sur

SES		Synthesis Energy Systems, Inc., an energy and technology company in which we invested

Shell		Royal Dutch Shell plc and its affiliates

SIE		Sociedad de Inversiones de Energía S.A., our Colombian holding company owned by Proenergía

SIGET		El Salvador General Superintendency of Electricity and Telecommunications (Superintendencia General de Electricidad y Telecomunicaciones)

SSGC		Sui Southern Gas Company Ltd., a distributor of natural gas in Pakistan

Subic		Subic Power Corp., a Philippine Power Generation business

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Surtigas		Surtigas S.A. E.S.P., one of our Colombian Natural Gas Distribution businesses

TBG		Transportadora Brasileira Gasoduto, one of our Brazilian Natural Gas Transportation and Services businesses and part of the Bolivia-to-Brazil Pipeline

TBS		Transborder Gas Services, one of our Brazilian Natural Gas Transportation and Services businesses and part of the Cuiabá Integrated Project

Terpel		Organización Terpel Inversiones S.A., one of our Colombian Retail Fuel businesses, which is owned by Proenergía

TETAŞ		Türkiye Elektrik Ticaret ve Taahüt A.S., a Turkish state-run power company

TGI		Transportadora de Gas del Interior, entity recently privatized by the Colombian government

TGS		Transportadora de Gas del Sur S.A., an Argentine Natural Gas Transportation and Services business

Tipitapa		Tipitapa Power Company Ltd., one of our Nicaraguan Power Generation businesses

Tongda		Tongda Energy Private Limited, one of our Chinese Natural Gas Distribution businesses

Trakya		Trakya Elektrik Üretim ve Ticaret A.Ş., our Turkish Power Generation business

Transmetano		Transmetano S.A. ESP, one of our Colombian Natural Gas Transportation and Services businesses

Transoccidente		Transoccidente S.A. ESP, one of our Colombian Natural Gas Transportation and Services businesses

Transoriente		Transoriente S.A. ESP, one of our Colombian Natural Gas Transportation and Services businesses

Transredes		Transredes-Transporte de Hidrocarburos S.A., a Bolivian Natural Gas Transportation and Services business

Vengas		Vengas S.A., a Venezuelan Retail Fuel business, in which we sold our interest in November 2007 to PDVSA

YPFB		Yacimientos Petrolíferos Fiscales Bolivianos, the Bolivian state-owned energy company

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Item 3. Key Information

A. Selected Financial Data

The following tables present selected financial data for AEI, the successor entity, and for both of our predecessor companies, Elektra Noreste, S.A., or Elektra, and Prisma Energy International Inc., or PEI.

The summary consolidated financial data for the periods and as of the dates indicated should be read in conjunction with “Item 5. Operating and Financial Review and Prospects” and our audited consolidated financial statements and related notes, located elsewhere in this annual report.

AEI and Elektra

The following table sets forth the financial results for AEI and the historical predecessor Elektra.


	Elektra Noreste,
	S.A. (Predecessor)			AEI (Successor)
	For the 275-			For the 90-Day
	Day Period From			Period From
	January 1,			October 3,			For the Year Ended			For the Year Ended			For the Year Ended			For the Year Ended
	2005 to			2005 to			December 31,			December 31,			December 31,			December 31,
	October 2, 2005			December 31, 2005			2006⁽¹⁾			2007			2008			2009
	Millions of dollars (U.S.) except per share data
Statement of Operations Data:
Revenues	$	200		$	72		$	946		$	3,216		$	9,211		$	8,185
Cost of sales		140			53			566			1,796			7,347			6,238
Operating expenses:
Operations, maintenance, general and administrative expenses		22			7			193			630			894			863
Depreciation and amortization		9			3			59			217			268			272
Taxes other than income		1			—			7			43			43			45
Other charges		—			—			—			50			56			123
(Gain) loss on disposition of assets		1			—			7			(21	)		(93	)		20
Equity income from unconsolidated affiliates		—			—			37			76			117			107

Operating income		27			9			151			577			813			731
Interest income		1			—			71			110			88			74
Interest expense		(6	)		(3	)		(138	)		(306	)		(378	)		(327	)
Foreign currency transactions gain (loss), net		—			—			(5	)		19			(56	)		9
Gain (loss) on early retirement of debt		—			—			—			(33	)		—			10
Other income (expense), net		—			—			7			(22	)		9			70

Income before income taxes		22			6			86			345			476			567
Provisions for income tax		7			2			84			193			194			279

Income from continuing operations		15			4			2			152			282			288
Income from discontinued operations, net of tax		—			—			7			3			—			—
Gain from disposal of discontinued operations, net of tax		—			—			—			41			—			—

Net income (loss)		15			4			9			196			282			288
Less: Net income (loss) — noncontrolling interests		—			2			20			65			124			(9	)

Net income attributable to Elektra Noreste S.A. shareholders	$	15



Net income (loss) attributable to AEI shareholders				$	2		$	(11	)	$	131		$	158		$	297

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	Elektra Noreste,
	S.A. (Predecessor)			AEI (Successor)
	For the 275-			For the 90-Day
	Day Period From			Period From
	January 1,			October 3,			For the Year Ended			For the Year Ended			For the Year Ended			For the Year Ended
	2005 to			2005 to			December 31,			December 31,			December 31,			December 31,
	October 2, 2005			December 31, 2005			2006⁽¹⁾			2007			2008			2009
	Millions of dollars (U.S.) except per share data
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	19		$	12		$	155		$	686		$	508		$	821
Investing activities		(13	)		(6	)		(1,729	)		(1,151	)		(414	)		(559	)
Financing activities		(12	)		(5	)		2,395			88			173			(370	)
Capital expenditures		(13	)		(6	)		(76	)		(249	)		(372	)		(441	)
Other Financial Data:
Adjusted EBITDA⁽²⁾								217			823			1,044			1,146
Basic and diluted earnings per share:
Income (loss) from continuing operations attributable to AEI shareholders								(0.09	)		0.42			0.73			1.27
Net income (loss) attributable to AEI shareholders								(0.05	)		0.63			0.73			1.27
Weighted average shares outstanding								202			209			218			234


	AEI
	As of		As of		As of		As of		As of
	December 31,		December 31,		December 31,		December 31,		December 31,
	2005		2006		2007		2008		2009
Balance Sheet Data:
Property, plant and equipment (net)	$	228	$	2,307	$	3,035	$	3,524	$	4,200
Total assets		568		6,134		7,853		8,953		10,225
Long-term debt		90		2,390		2,515		3,415		3,105
Total debt		100		2,677		3,264		3,962		3,718
Net debt⁽²⁾		91		1,591		2,525		3,094		2,896
Total equity attributable to AEI		327		1,441		1,858		1,830		2,832


(1)		Includes Elektra on a consolidated basis for the entire year and PEI on the equity method basis from June through August and on a consolidated basis from September to December.

(2)		See “Non-GAAP Financial Measures.”

Net debt as indicated in the table above is reconciled below:


	AEI
	As of			As of			As of			As of			As of
	December 31,			December 31,			December 31,			December 31,			December 31,
	2005			2006			2007			2008			2009
Total debt	$	100		$	2,677		$	3,264		$	3,962		$	3,718
Less
Cash and cash equivalents		(6	)		(830	)		(516	)		(736	)		(682	)
Current restricted cash		—			(117	)		(95	)		(83	)		(77	)
Non-current restricted cash		(3	)		(139	)		(128	)		(49	)		(63	)

Net debt	$	91		$	1,591		$	2,525		$	3,094		$	2,896

-14-

The following table sets forth the reconciliation of net income to Adjusted EBITDA for AEI for the year ended December 31, 2009 on a consolidated basis and by segment.


							Natural Gas
	Power			Power			Transportation			Natural Gas
	Distribution			Generation			and Services			Distribution			Retail Fuel			Other			Total
	Millions of dollars (U.S.)
Net income (loss) attributable to AEI	$	276		$	62		$	48		$	43		$	15		$	(147	)	$	297
Depreciation and amortization		134			42			21			23			46			6			272
Net income (loss) —noncontrolling interests	$	14		$	(37	)	$	(78	)	$	42		$	48		$	2		$	(9	)
Provision for income taxes		117			60			31			30			40			1			279
Interest expense		93			57			41			17			52			67			327
Subtract:
Interest income		46			15			5			2			6			—			74
Foreign currency transaction gain (loss), net		—			5			3			2			9			(10	)		9
Gain (loss) on disposition of assets		(22	)		—			4			(2	)		—			—			(20	)
Gain on early retirement of debt		—			—			—			—			—			10			10
Other charges		—			(25	)		(96	)		—			—			(2	)		(123	)
Other income (expense), net		42			24			2			—			(1	)		3			70

Adjusted EBITDA	$	568		$	165		$	145		$	153		$	187		$	(72	)	$	1,146

The following table sets forth the reconciliation of net income to Adjusted EBITDA for AEI for the year ended December 31, 2008 on a consolidated basis and by segment.


							Natural Gas
	Power			Power			Transportation			Natural Gas
	Distribution			Generation			and Services			Distribution			Retail Fuel			Other			Total
	Millions of dollars (U.S.)
Net income (loss) attributable to AEI	$	209		$	(16	)	$	53		$	26		$	17		$	(131	)	$	158
Depreciation and amortization		138			24			21			18			61			6			268
Net income (loss) —noncontrolling interests		12			(49	)		21			30			93			17			124
Provision for income taxes		110			43			25			28			21			(33	)		194
Interest expense		134			45			44			19			53			83			378
Subtract:
Interest income		54			14			6			2			9			3			88
Foreign currency transaction gain (loss), net		(5	)		(25	)		(1	)		(3	)		(28	)		6			(56	)
Gain (loss) on disposition of assets		(19	)		—			—			—			69			43			93
Other charges		—			(44	)		—			—			—			(12	)		(56	)
Other income (expense), net		(11	)		19			10			(1	)		(15	)		7			9

Adjusted EBITDA	$	584		$	83		$	149		$	123		$	210		$	(105	)	$	1,044

-15-

The following table sets forth the reconciliation of net income to Adjusted EBITDA for AEI for the year ended December 31, 2007 on a consolidated basis and by segment.


							Natural Gas
	Power			Power			Transportation			Natural Gas
	Distribution			Generation			and Services			Distribution			Retail Fuel			Other			Total
	Millions of dollars (U.S.)
Net income (loss) attributable to AEI	$	227		$	83		$	53		$	22		$	55		$	(309	)	$	131
Depreciation and amortization		139			42			20			8			3			5			217
Net income (loss) — noncontrolling interests		11			10			15			31			13			(15	)		65
Provision for income taxes		105			(16	)		29			20			12			43			193
Interest expense		90			41			42			14			12			107			306
Subtract:
Income from discontinued operations		—			—			—			—			3			—			3
Gain from disposal of discontinued operations		—			—			—			—			41			—			41
Interest income		58			27			7			2			2			14			110
Foreign currency transaction gain (loss), net		3			19			(3	)		2			—			(2	)		19
Gain (loss) on disposition of assets		(10	)		21			6			3			1			—			21
Other charges		—			(50	)		—			—			—			—			(50	)
Loss on early retirement of debt		—			—			—			—			—			(33	)		(33	)
Other income (expense), net		(2	)		(5	)		6			(2	)		(2	)		(17	)		(22	)

Adjusted EBITDA	$	523		$	148		$	143		$	90		$	50		$	(131	)	$	823

The following table sets forth the reconciliation of net income to Adjusted EBITDA for AEI for the year ended December 31, 2006 on a consolidated basis and by segment.


							Natural Gas
	Power			Power			Transportation		Natural Gas
	Distribution			Generation			and Services		Distribution		Retail Fuel		Other			Total
	Millions of dollars (U.S.)
Net income (loss) attributable to AEI	$	93		$	18		$	15	$	1	$	2	$	(140	)	$	(11	)
Depreciation and amortization		47			9			2		—		1		—			59
Net income —noncontrolling interests		9			8			3		—		—		—			20
Provision for income taxes		40			32			4		—		5		3			84
Interest expense		27			18			5		—		2		86			138
Subtract:
Income from discontinued operations		—			—			—		—		7		—			7
Interest income		20			11			—		—		—		40			71
Foreign currency transaction loss, net		(4	)		(1	)		—		—		—		—			(5	)
Loss on disposition of assets		(7	)		—			—		—		—		—			(7	)
Other income (expense), net		2			5			7		—		—		(7	)		7

Adjusted EBITDA	$	205		$	70		$	22	$	1	$	3	$	(84	)	$	217

-16-

PEI

The following table sets forth the financial results for the historical predecessor, PEI.


	Prisma Energy International Inc. (Predecessor)
	For the Year Ended			For the 249-Day Period
	December 31, 2005			Ended September 6, 2006
	Millions of dollars (U.S.)
Statement of Operations Data:
Revenues	$	1,901		$	1,414
Cost of sales		930			750
Operating expenses
Operations, maintenance, general and administrative		387			233
Depreciation and amortization		101			63
Taxes other than income		31			32
Loss on disposition of assets		14			6
Equity income from unconsolidated affiliates		109			35

Operating income		547			365
Interest income from unconsolidated affiliates		4			2
Interest income		97			80
Interest expense		(104	)		(96	)
Foreign currency transaction gain, net		95			17
Other income (expense), net		71			26

Income before income taxes		710			394
Provision for income taxes		181			209

Net income		529			185
Less: Net income — noncontrolling interests		79			21

Net income attributable to PEI shareholders	$	450		$	164

Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	507		$	448
Investing activities		186			(448	)
Financing activities		(169	)		(580	)
Capital expenditures		(97	)		(72	)


	Prisma Energy International Inc.
	(Predecessor)
	As of December 31, 2005
	Millions of dollars (U.S.)
Balance Sheet Data:
Property, plant and equipment (net)	$	1,629
Total Assets		4,759
Long-term debt		748
Total debt		870
Net debt⁽¹⁾		(375	)
Total equity attributable to PEI		2,471


(1)		See “Non-GAAP Financial Measures.”

Net debt as indicated in the table above is reconciled below:


	Prisma Energy International Inc.
	(Predecessor)
	As of December 31, 2005
	Millions of dollars (U.S.)
Total debt	$	870
Less
Cash and cash equivalents		(1,046	)
Current restricted cash		(150	)
Non-current restricted cash		(49	)

Net debt	$	(375	)

B. Capitalization and Indebtedness

Not applicable.

-17-

C. Reasons for the Offer and Use of Proceeds

Not applicable.

D. Risk Factors

Risks Associated with the Countries in which We Operate

Our businesses are in emerging markets. Our results of operations and financial condition are dependent upon economic conditions in those countries in which we operate, and any decline in economic conditions could harm our results of operations or financial condition.

All of our operations and development are in countries in emerging markets, and we expect to have additional operations in these or other emerging market countries. Many of these countries have a history of political, social and economic instability. Our revenue is derived primarily from the sale, distribution and transportation of electricity, natural gas and liquid fuels, and the demand for that energy is largely driven by the economic conditions of the countries in which we operate. Therefore, our results of operations and financial condition are to a large extent dependent upon the overall level of economic activity and political and social stability in those emerging market countries. Should economic conditions deteriorate in these countries or in emerging markets generally, our results of operations and financial condition may be adversely affected.

Governments have a high degree of influence in the economies in which we operate. This influence could harm our results of operations or financial condition.

Governments in many of the markets in which we operate frequently intervene in the economy and occasionally make significant changes in monetary, credit, industry and other policies and regulations. Government actions to control inflation and other policies and regulations have often involved, among other measures, price controls, currency devaluations, capital controls and limits on imports. We have no control over, and cannot predict, what measures or policies governments may take in the future. The results of operations and financial condition of our businesses may be adversely affected by changes in governmental policy or regulations in the jurisdictions in which they operate that impact factors such as:

	•		consumption of electricity and natural gas;

	•		supply of electricity and natural gas;

	•		energy policy;

	•		subsidies and incentives;

	•		regulated returns and associated tariffs;

	•		labor laws;

	•		economic growth;

	•		currency fluctuations;

	•		inflation;

	•		exchange and capital control policies;

	•		interest rates;

	•		liquidity of domestic capital and lending markets;

	•		fiscal policy;

	•		tax laws, including the effect of tax laws on distributions from our subsidiaries;

-18-

	•		import/export restrictions; and

	•		other political, social and economic developments in or affecting the country where each business is based.

Uncertainty over whether governments will implement changes in policy or regulation affecting these or other factors in the future may contribute to economic uncertainty and heightened volatility in the securities markets.

Due to populist political trends that have become more prevalent in Latin America over recent years, some of the administrations in countries where we operate might seek to promote efforts to increase government involvement in regulating economic activity, including the energy sector, which could result in the introduction of additional political factors in economic decisions. For example, as described later, Bolivia has nationalized natural gas and petroleum assets, and Venezuela has nationalized parts of its key infrastructure, including the hydrocarbon and electricity industries.

The uncertainty of the legal and regulatory environments in certain countries in which we operate, develop or construct infrastructure assets may make it difficult for us to enforce our rights under agreements relating to our businesses.

Newly formed or evolving energy regulatory regimes create an environment of uncertainty with respect to the rules and processes that govern the operation of our businesses. In addition, policy changes resulting from changes in governments or political regimes cannot be predicted and could potentially impact our businesses in a negative way.

Although we may have legal recourse to enforce our rights under agreements to which we are a party and recover damages for breaches of those agreements, those legal proceedings would be costly and may not be successful or resolved in a timely manner, and if successful, may not be enforced. Areas in which we may be affected include:

	•		forced renegotiation or modification of concession, supply and sales agreements;

	•		termination of permits or concessions; and

	•		withdrawal or threatened withdrawal of countries from international arbitration conventions.

Currency exchange rate fluctuations relative to the U.S. dollar in the countries in which we operate our businesses may adversely impact our results of operations or financial condition

We operate exclusively outside the United States and our businesses may be impacted by significant fluctuations in foreign currency exchange rates. Our exposure to currency exchange rate fluctuations results from the translation exposure associated with the preparation of our consolidated financial statements, and from transaction exposure associated with generating revenues and incurring expenses in different currencies and devaluation of local currency revenues impairing the value of the investment in U.S. dollars. While our consolidated financial statements are reported in U.S. dollars, the financial statements of some of our subsidiaries are prepared using the local currency as the functional currency and translated into U.S. dollars by applying an exchange rate. We match external indebtedness in the functional currency of the subsidiary. However, there may be instances where this is not possible or is uneconomical. Fluctuations in exchange rates and currency devaluations also affect our cash flow as cash distributions received from those of our subsidiaries operating in local currencies might be different from forecasted distributions due to the effect of exchange rate movements. Most countries in which we operate have currencies which have fluctuated significantly against the U.S. dollar in the past. Accordingly, changes in exchange rates relative to the U.S. dollar could have a material adverse effect on our results of operations and financial condition.

Future fluctuations in the value of the local currencies relative to the U.S. dollar in the countries in which we operate may occur, and if such fluctuations were significant and were to occur in one or a combination of the countries in which we operate, our results of operations or financial condition could be adversely affected.

-19-

Existing and new exchange rate controls and/or restrictions on transfers to foreign investors of proceeds from their investments and/or measures to control the proceeds that enter into the country would restrict or impair our ability to receive distributions from our subsidiaries or could affect our ability to access the international capital markets and adversely affect our results of operations or financial condition.

The governments of several countries in which we operate, such as Argentina, Brazil and China, have periodically implemented policies imposing restrictions on the remittance to foreign investors of proceeds from their investments and/or restricting the inflow of funds to such countries in order to control inflation, limit currency volatility and improve local economic conditions. Furthermore, restrictions on transfers of funds abroad can also impair the ability of our subsidiaries to access capital markets, prevent them from servicing debt obligations that are denominated in U.S. dollars or other non-local currencies and prevent them from paying dividends to us. If a significant number of our operating subsidiaries are unable to make distributions to us because of restrictions on the transfers of currencies, we may not have sufficient cash to pay dividends to our shareholders or liquidity to meet our operational and financial obligations.

We may be affected by terrorism, border conflict, or civil unrest in the countries in which we operate, which could affect our assets, our ability to operate and our personnel.

A number of the countries in which we operate are subject to internal or border conflicts or civil unrest, which could negatively affect our assets, our ability to operate and the safety of our personnel. In the past, we occasionally experienced attacks on our assets. No material loss has occurred as a result of any of the attacks or incidents. The possibility of an attack on infrastructure that will directly affect the operation of our businesses is an ongoing threat, the timing and impact of which cannot be predicted and which will likely continue for the foreseeable future. A terrorist act against our facilities in any country in which we operate could cause disruptions in our operations, and significant repair costs and delays.

Inflation in some of the countries in which we operate, along with governmental measures to combat inflation, may have a significant negative effect on the economies of those countries and, as a result, on our financial condition or results of operations.

In the past, high levels of inflation have adversely affected the economies and financial markets of some of the countries in which we operate and the ability of their governments to create conditions that stimulate or maintain economic growth.

Moreover, governmental measures to curb inflation and speculation about possible future governmental measures have contributed to the negative economic impact of inflation and have created general economic uncertainty. Our results of operations and financial condition have been affected from time to time to varying degrees by these conditions.

Future governmental economic measures, including interest rate increases, restrictions on tariff adjustments to offset inflation, intervention in foreign exchange markets and actions to adjust or fix currency values, may trigger or exacerbate increases in inflation, and consequently have an adverse impact on us. For example, in an inflationary environment, the value of uncollected accounts receivable, as well as unpaid accounts payable, declines rapidly. If the countries in which we operate experience high levels of inflation in the future and price controls are imposed, we may not be able to adjust the rates we charge our customers to fully offset the impact of inflation on our cost structures, which could adversely affect our results of operations or financial condition.

The Bolivian and Venezuelan governments have nationalized energy industry assets, and our remaining businesses in Bolivia and Venezuela may also be nationalized.

Bolivia has experienced political and economic instability that has resulted in significant changes in its general economic policies and regulations. On May 1, 2006, the Bolivian government nationalized the hydrocarbons industry pursuant to a Supreme Decree. Several subsequent decrees were issued and ultimately the Bolivian government registered 100% of our interest in Transredes-Transporte de Hidrocarburos S.A., or Transredes, a gas distribution company of which we owned 50%, in the name of Yacimientos Petrolíferos Fiscales Bolivianos, or YPFB, the Bolivian state-owned energy company. In October 2008, we reached a settlement with the Bolivian government pursuant to which the Bolivian government paid us $120 million in two installments. As a result, there may be a risk that our other assets in Bolivia, including Gas Transboliviano S.A., or GTB and GasOriente Boliviano Ltda., or GOB, will be subject to nationalization without fair compensation.

-20-

Venezuela has nationalized a significant part of its hydrocarbon and electricity industries and changed its operation agreements to joint ventures with the state-owned oil company Petróleos de Venezuela, S.A., or PDVSA. On November 15, 2007, we sold our interests in Vengas S.A., or Vengas, to PDVSA Gas, S.A., a wholly-owned subsidiary of PDVSA, or PDVSA Gas. On September 11, 2009, we signed a non-binding Letter of Intent with PDVSA Gas pursuant to which we agreed to transfer our interest in Accroven S.R.L., or Accroven, to PDVSA Gas. This Letter of Intent has expired. However, negotiations are continuing and we expect to close this transaction during the first half of 2010.

Lack of transparency, threat of fraud, public sector corruption and other forms of criminal activity involving government officials increases risk for potential liability under anti-bribery legislation, including the U.S. Foreign Corrupt Practices Act.

We are subject to the U.S. Foreign Corrupt Practices Act, or the FCPA, and other anti-bribery laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties by U.S. and other business entities for the purpose of obtaining or retaining business, or otherwise receiving discretionary favorable treatment of any kind and requires the maintenance of internal controls to prevent such payments. In particular, we may be held liable for actions taken by our local partners and agents, even though such parties are not always subject to our control. Any determination that we have violated the FCPA or other anti-bribery laws (whether directly or through acts of others, intentionally or through inadvertence) could result in sanctions that could have a material adverse effect on our results of operations and financial condition.

Risks Relating to the Industries in which We Operate

Most of our businesses are subject to significant governmental regulations and our results of operations and financial condition could be adversely affected by changes in the law or regulatory schemes.

We operate energy businesses in five geographic regions and, therefore, we are subject to significant and diverse government regulation. Our inability to forecast, influence or respond appropriately to changes in law or regulatory schemes could adversely impact our results of operations and financial condition. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions in which we operate, particularly our regulated utilities where tariffs are subject to regulatory review or approval, could adversely affect our results of operations and financial condition. Such changes may include:

	•		changes or terminations of key permits, operating licenses or concessions;

	•		changes in the determination, definition or classification of costs to be included as controllable or noncontrollable pass-through costs;

	•		changes in the methodology of calculating or the timing of tariff revisions and changes in the tariff’s regulated returns;

	•		changes in the definition of events which may or may not qualify as changes in economic equilibrium under the terms of concession agreements;

	•		changes in rules governing energy supply and purchase contracts;

	•		changes in subsidies and/or incentives provided by governments;

	•		changes in rules governing dispatch order;

	•		changes in methodology of calculating firm capacity payment charges and frequency of adjustment of those charges;

	•		changes in market rules for the calculation of energy marginal costs and spot prices;

	•		changes in calculation of transportation/transmission rates; and

	•		other changes in the regulatory determinations under the relevant concessions or licenses.

-21-

Any of these factors, by itself or in combination with others, could materially and adversely affect our results of operations or financial condition.

The tariffs of most of our business segments are regulated and periodically revised by regulators. Reductions in tariffs could result in the inability of our businesses to recover operating costs, including commodity costs, and/or investments and maintain current operating margins.

Most of our businesses are subject to tariff regulation by the regulators in the countries in which they operate. Those tariffs are reviewed on a periodic basis and may be reset or reduced. In most of these businesses, to the extent capital expenditures are incurred above the approved amount for a tariff period, the businesses bear the risk of not having the investment recognized during the next rate case review and consequently may not be able to recover the investment. In addition, to the extent that operating costs rise above the level approved in the tariff, the businesses typically bear the risk. Our future tariffs may not permit us to maintain our current operating margins. In addition, to the extent that tariff adjustments are not granted by regulators in a timely manner, our results of operations or financial condition may be adversely affected.

Some of our markets may face power rationings, which could lead to a reduction in the level and/or growth in electricity consumption and sales.

Some of our Power Distribution companies operate in markets that are highly dependent on hydroelectric generation of electricity, which may significantly affect supply under unfavorable hydrology conditions. Supply may also be affected by other factors limiting investments in new generation capacity and/or the ability of the existing power grid to provide reliable electricity to end users. The volatility of hydroelectric generation and the lack of new generation investment may lead local governments to adopt measures, including rationing, in an attempt to reduce consumption levels. While power rationing may, in most cases, involve government efforts to avoid material impacts on the financial results of electric distribution companies, conservation efforts and efficiencies achieved during rationing may result in changes in consumption patterns following the rationing, leading to a reduction in the level and/or growth in electricity consumption and sales.

Many of our businesses operate under concessions granted by the various countries in which we operate and we are subject to penalties, including termination of the concession agreements, if we do not comply with the terms of the concession agreements.

We conduct many of our activities pursuant to concession agreements with governmental and regulatory bodies. If we do not comply with the provisions in our concession agreements, regulatory authorities may enforce penalties. Depending on the gravity of the non-compliance, these penalties could include the following:

	•		warning notices;

	•		fines for breaches of concessions based on a percentage of revenues for the year immediately before the violation date;

	•		temporary suspension from participating in bidding processes for new concessions;

	•		injunctions prohibiting investments in new facilities and equipment;

	•		restrictions to the operations of existing facilities and equipment;

	•		intervention by the authority granting our concession; and

	•		possible termination or non-renewal of our concession.

One or more of our businesses may be penalized for breaching its concession agreement and a business’s concession may be terminated in the future. If a business’s concession agreement were terminated, that business would not be able to operate and sell to its customers in the area covered by its concession. In addition, the compensation to which a business would be entitled upon termination of its concession may not be sufficient for it to realize the full value of its assets, and the payment of that compensation could be delayed for many years. In addition, governments have the power to terminate our businesses’ concessions prior to the end of the applicable concession term in the case of our bankruptcy or dissolution, by means of expropriation in the public interest or in the event our businesses fail to comply with applicable regulation. In this regard, we may not be able to renew our concessions at the end of the term of the concessions.

-22-

Any of the foregoing penalties, the intervention of regulatory authorities in our concessions, or termination of our concessions could have a material adverse effect on our results of operations or financial condition.

Our results of operations or financial condition may be adversely affected if we are unable to address various operating risks typically faced by companies in the energy business.

We face a number of operating risks applicable to companies in the energy business including:

	•		periodic service disruptions and variations in power quality in our Power Distribution businesses, which may result in significant revenue loss and potential liabilities to third parties;

	•		fluctuations or a decline in aggregate customer demand for energy in line with prevailing economic conditions, which could result in decreased revenues;

	•		equipment or other failures at our facilities causing unplanned outages;

	•		the dependence of our Power Generation facilities on a specified fuel source, including the quality and transportation of fuel, which could impact the operation of those facilities;

	•		breakdown or failure of one of our Power Generation or Natural Gas Transportation and Services facilities may prevent the facility from performing under applicable power sales agreements or gas transportation agreements which, in certain situations, could result in termination of the agreement or incurring liability for liquidated damages;

	•		service disruptions in our Natural Gas Transportation and Services and Natural Gas Distribution businesses, reductions in customer demand or reductions in throughput could result in reduced revenues from these businesses;

	•		failures and faults in the electricity transmission system or in the electricity generation facilities of Power Generation companies due to circumstances beyond our control;

	•		system failure affecting our information technology systems or those of other energy industry participants, which could result in loss of operational capacities or critical data;

	•		environmental costs and liabilities arising from our operations, which may be difficult to quantify and could affect our results of operations;

	•		underground storage tank leaks which could result in a contamination of our gas facilities;

	•		energy losses, whether arising from technical reasons inherent in the normal operation of electricity and liquids distribution systems or arising from non-technical reasons (such as theft, fraud and inaccurate billing), resulting in revenue losses which we are unable to pass-through to customers; and

	•		injuries to third parties or our employees in connection with our businesses, which may result in liabilities, higher insurance costs or denial of insurance coverage.

Any of these factors, by itself or in combination with others, could materially and adversely affect our results of operations or financial condition.

-23-

We are dependent on external parties and other factors for consumables, energy and fuel and our inability to obtain these materials could adversely affect our financial condition or results of operations.

Supplies of consumables, energy and fuel for our plants, distribution systems or pipelines could be affected by a number of possible factors:

	•		existing upstream energy reserves need to be available and new reserves developed in order to efficiently utilize the capacity of our gas and liquids pipelines; any prolonged interruption in our ability to access upstream reserves would affect our financial condition or results of operations;

	•		if upstream reserves are depleted, and no new fields or wells are developed, the amount of natural gas available for consumption will be reduced, and so will the volumes of liquids and associated gas transported by our pipelines, and the availability of fuel for our power plants or for resale by our Natural Gas Distribution and Retail Fuel businesses, which could materially and adversely affect our results of operations or financial condition;

	•		in the event that our local suppliers become unwilling or unable to supply fuel or energy to our businesses, we may not have any remedies under our supply contracts, or such remedies may not be sufficient to offset the potential incremental costs or reduction in revenues;

	•		service disruptions, stoppages or variations in power quality contracted or transmitted by third parties to our Power Distribution businesses could cause us to be unable to distribute power to the end users of electricity. In that case, we would be unable to receive revenues for power distribution, and may be subject to claims for damages from end users, fines from regulators and the possible loss of our concessions; and

	•		should a neighboring government decide, for political reasons or otherwise, to curtail or interrupt the transportation of fuel or energy required by our businesses to operate, an alternate source for that fuel or energy may not be available, or become available, in sufficient time to preclude an interruption of our operations. For example, Empresa Produtora de Energia Ltda., or EPE, our Brazilian Power Generation business, has been unable to obtain a gas supply due to a lack of supply combined with a sharp increase in regional demand and has generally not been operational since August 2007.

Risks Related to Our Businesses

The operation of our businesses involves significant risks that could adversely affect our results of operations or financial condition.

The operation of our businesses involves many risks, including:

	•		the inability to obtain or renew required governmental concessions, permits and approvals;

	•		fuel spillage, seepage or release of hazardous materials;

	•		the unavailability of critical equipment or parts;

	•		the unavailability or interruptions of fuel or energy supply;

	•		work stoppages and labor unrest;

	•		social unrest;

	•		operation and critical equipment failures;

	•		increases in line losses, including technical and commercial losses;

	•		forecasting errors for price and volume projections;

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	•		decreases in energy consumption;

	•		severe weather and seasonal variations;

	•		natural disasters or catastrophic events that affect our physical assets or cause interruptions in our ability to provide our services and products, particularly ones that cause damage in excess of our insurance policy limits;

	•		injuries to people and damages to property resulting from transportation and handling of electricity, natural gas, liquid fuels or hazardous materials;

	•		the possibility of material litigation and regulatory proceedings being brought against us or our businesses;

	•		working capital constraints;

	•		operating cost overruns;

	•		construction and operational delays or unanticipated cost overruns; and

	•		performance of services from subcontractors.

If we experience any of these or other problems, we could experience an adverse effect on our financial condition or results of operations.

A failure to attract and retain skilled people could have a material adverse effect on our operations.

Our operating success depends in part on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity, including people in our international businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements.

Our proposed acquisitions and development projects may not be completed or, if completed, may not perform as expected. Our acquisition and development activities may consume a portion of our management’s focus, increase our leverage, and if not successful, reduce our profitability.

We plan to grow our business through acquisitions and greenfield and brownfield development. Development projects and acquisitions require us to spend significant sums for engineering, permitting, legal, financial advisory and other expenses in preparation for competitive bids we may not win or before we determine whether a development project is feasible, economically attractive or capable of being financed. These activities consume a portion of our management’s focus and could increase our leverage or reduce our profitability.

Future acquisitions or development projects may be large and complex, and we may not be able to complete them. There can be no assurance that we will be able to negotiate the required agreements, overcome any local opposition, obtain the necessary licenses, permits and financing or satisfy ourselves that the target company has not engaged in activities that would violate laws and regulations that are applicable to us, including without limitation, the FCPA.

Although acquired businesses may have significant operating histories at the time we acquire them, we will have no history of owning and operating these businesses and possibly limited or no experience operating in the country or region where these businesses are located. In particular:

	•		acquired businesses may not perform as expected;

	•		we may incur unforeseen obligations or liabilities;

	•		acquired businesses may not generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to operate them;

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	•		the rate of return from acquired businesses may be lower than anticipated in our decision to invest our capital to acquire them; or

	•		we may not be able to expand as planned or to integrate the acquired company’s activities and achieve the economies of scale and any expected efficiency gains that often drive such acquisitions.

In addition, when we acquire a new business, we may be required to implement measures to ensure its compliance with the FCPA if the new business has not been previously subject to anti-bribery legislation.

Competition to acquire energy assets is strong and could adversely affect our ability to grow.

The market for acquisition of energy assets is characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental or operating experience (including both domestic and international experience) and financial resources similar to or greater than us. The high level of competition for energy infrastructure assets has caused higher acquisition prices for existing assets through competitive bidding practices which could cause us to pay more for energy assets or otherwise be precluded from buying assets. The foregoing competitive factors could have a material adverse effect on our ability to grow.

Our businesses are dependent on and we are exposed to credit risks and, in some instances, the impact of credit concentration, arising out of the creditworthiness of customers who, for some of our businesses, are limited in number. Therefore, if one of our businesses’ large customers were to default on their obligations to us, it could adversely affect our financial condition or results of operations.

All of our Power Generation businesses, except Puerto Quetzal Power LLC, or PQP, and Empresa Energética Corinto Ltd., or Corinto, and all of our Natural Gas Transportation and Services businesses, except the Promigas Pipeline, have one or very few customers, and therefore we are exposed to credit risks of those customers in those businesses. A default by any of our key customers in our Power Generation or Natural Gas Transportation and Services businesses could materially and adversely affect our financial condition or results of operations. Our Power Distribution and Natural Gas Distribution businesses are impacted by the creditworthiness of our governmental, wholesale and retail residential customers.

Some of our businesses have experienced and currently are experiencing payment delays from large customers. In particular, Accroven and Generadora San Felipe Limited Partnership, or San Felipe, our Dominican Republic Power Generation business, are currently experiencing significant payment delays from their sole customers. In some regions, the suspension of electricity or gas supply to address unpaid accounts receivable or theft is prohibited by law, and our tariffs may not sufficiently compensate us for this indirect subsidy.

Our insurance policies may not fully cover damage or we may not be able to obtain insurance against certain risks, and our results of operations may be adversely affected if we incur losses that are not fully covered by our insurance policies.

We maintain insurance policies intended to mitigate our losses due to customary risks. These policies cover our assets against loss for physical damage, loss of revenue and also third-party liability. However, we cannot assure that the scope of damages suffered in the event of a natural disaster or catastrophic event would not exceed the policy limits of our insurance coverage. We maintain all-risk physical damage coverage for losses resulting from, but not limited to, fire, explosions, floods, windstorms, strikes, riots and mechanical breakdowns. For our Power Generation companies, we also maintain business interruption insurance. We also have civil liability insurance covering physical damage and bodily injury to third parties. In addition, we carry war, civil disorder and terrorism insurance in those markets in which we operate where we believe the political situation merits it. Our level of insurance may not be sufficient to fully cover all losses that may arise in the course of our business or insurance covering our various risks may not continue to be available in the future. In addition, we may not be able to obtain insurance on comparable terms in the future. Our results of operations or financial condition may be adversely affected if we incur losses that are not fully covered by our insurance policies.

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We are strictly liable for any damages resulting from the inadequate rendering of electricity services by our Power Distribution businesses, and any such liabilities could result in significant additional costs to us and may adversely affect our financial condition or results of operations.

We are strictly liable for direct damages to end users resulting from the inadequate rendering of electricity distribution services, such as abrupt supply interruptions or disturbances arising from the generation, transmission, or distribution systems. The liabilities arising from these interruptions or disturbances that are not covered by our insurance policies or that exceed our insurance policies’ limits may result in significant additional costs to us and may adversely affect our financial condition or results of operations. We may be required to pay regulatory penalties related to the operation of our business which may adversely affect our Power Distribution businesses if the regulator concludes that we did not contract enough generation to adequately cover this risk.

Under Brazilian law, Elektro Eletricidad e Serviços S.A., or Elektro, may be held liable for up to 35.7% of the damages caused to others as a result of interruptions or disturbances arising from the interconnected system, if these interruptions or disturbances are not attributed to an identifiable electric energy agent or the National System Operator (Operador Nacional do Sistema), irrespective of whether or not we are at fault.

We make noncontrolling investments in projects which may limit our ability to control the development, construction, acquisition or operation of such investments and future acquisitions.

Some of our or our subsidiaries’ current investments consist of noncontrolling interests in affiliates (i.e., where we beneficially own 50% or less of the ownership interests). Additionally, a portion of our future investments may also take the form of noncontrolling interests. As a result, our ability to control the development, construction, acquisition or operation of such investments and future acquisitions may be limited. As a result, we may be dependent on our co-venturers to construct and operate such businesses, and the approval of co-venturers also may be required for distributions of funds from projects to us.

Our businesses may incur substantial costs and liabilities and be exposed to commodity price volatility, as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial condition or results of operations.

Some of our Power Generation and Power Distribution businesses buy and sell electricity in the wholesale spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. Additionally, we may be required to pay regulatory penalties for our Power Distribution businesses if regulators conclude that we did not contract for enough electricity. Typically, the open market wholesale prices for electricity are volatile and often reflect the cyclical fluctuating cost of coal, natural gas, oil or conditions of hydro reservoirs. Consequently, any changes in the supply and cost of coal, natural gas and oil or conditions of hydro reservoirs may impact the open market wholesale price of electricity. Volatility in market prices for fuel and electricity may result from many factors which are beyond our control and we may not always engage in hedging transactions. In addition, businesses that engage in hedging transactions remain subject to market risks, including market liquidity and counterparty creditworthiness, and may also have exposure to market prices if counterparties do not produce volumes or otherwise comply with contractual obligations in accordance with the terms of the applicable hedging contracts.

We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of greenhouse gases have the potential to affect our business in many ways, including negatively impacting our ability to finance carbon emitting power generation plants, the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.

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Our equipment, facilities and operations are subject to numerous environmental, health and safety laws and regulations that are expected to become more stringent in the future, which may result in increased liabilities, compliance costs and increased capital expenditures.

We are subject to a broad range of environmental, health and safety laws and regulations which require us to incur ongoing costs and capital expenditures and expose us to substantial liabilities in the event of non-compliance. These laws and regulations require us to, among other things, minimize risks to the natural and social environment while maintaining the quality, safety and efficiency of our facilities.

These laws and regulations also require us to obtain and maintain environmental permits, licenses and approvals for the construction of new facilities or the installation and operation of new equipment required for our businesses. All of these permits, licenses and approvals are subject to periodic renewal and challenge from third-parties. We expect environmental, health and safety rules to become more stringent over time, making our ability to comply with the applicable requirements more difficult. Government environmental agencies could take enforcement actions against us for any failure to comply with applicable laws and regulations. Such enforcement actions could include, among other things, the imposition of fines, revocation of licenses, suspension of operations or imposition of criminal liability for non-compliance. Environmental laws and regulations can also impose strict liability for the environmental remediation of spills and discharges of hazardous materials and wastes and require us to indemnify or reimburse third parties for environmental damages. Compliance with changed or new environmental, health and safety regulations could require us to make significant capital investments in additional pollution controls or process modifications. These expenditures may not be recoverable and may consequently divert funds away from planned investments in a manner that could adversely affect our results of operations or financial condition.

Financial Risks

A downgrade in our credit ratings or that of our subsidiaries or those of the countries in which we operate could adversely affect our ability to access the capital markets which could increase our interest costs or adversely affect our financial condition or results of operations.

From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by our operating cash flows. If our credit ratings, or those of our subsidiaries or those of the countries in which we operate, were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs would increase. In addition, we historically have not paid dividends, but any change to our dividend policy could unfavorably affect our credit ratings.

Our below-investment grade rating indicates that our debt is regarded as having significant speculative characteristics, and that there are major ongoing uncertainties or exposure to financial or economic conditions which could compromise our capacity to meet our financial commitments on our debt. Due to our current below-investment grade rating, we may be unable to obtain the financing we need to pursue our business plan, and any future financing or refinancing received may be on less favorable terms than our current arrangements.

As a result of our below-investment grade rating, counterparties may also be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, for both new and existing commitments, we may be required to provide a form of assurance, such as a letter of credit, to backstop or replace our credit support. We may not be able to provide adequate assurances to such counterparties. In addition, 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 liquidity needs.

We may not be able to raise sufficient capital to fund greenfield development in certain less developed economies which could change or in some cases adversely affect our growth strategy.

Part of our strategy is to grow our business by developing our core businesses in less developed economies. Commercial lending institutions sometimes refuse to provide financing in certain less developed economies, and in these situations we may seek direct or indirect (through credit support or guarantees) financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such financing available, the lending institutions may also require sponsor guarantees for completion risks and governmental guarantees of certain business and sovereign related risks. However, financing from international financial agencies or governmental guarantees required to complete projects may not be available when needed, and if they are not, we may have to abandon these projects or invest more of our own funds which may not be in line with our investment objectives and would leave less funds for other investments and development projects.

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Financial market developments may adversely affect our financial condition, results of operations or access to capital.

Dramatic declines in asset values held by financial institutions over the past two years have resulted in significant write-downs. These write-downs, from mortgage-backed securities to credit default swaps and other derivative securities, in turn have caused many financial institutions to seek additional capital, to merge with larger and stronger institutions and, in some cases, to fail. Reflecting concern about the stability of the financial markets generally and the strength of counterparties, many lenders and investors have ceased to provide funding to even the most creditworthy borrowers or to other financial institutions. The resulting lack of available credit and lack of confidence in the financial markets could materially and adversely affect our financial condition, results of operations or our access to capital. In connection with these events, our ability to borrow from financial institutions on favorable terms or at all could be adversely affected by further disruptions in the capital markets or other events.

Risks Associated with our Structure

We are a holding company and therefore are dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise. Failure to receive such funds could impact our ability to pay our interest and other expenses at the parent company or to pay dividends.

We are a holding company, as are many of our subsidiaries, with no material assets other than the stock of our subsidiaries. All of our revenue-generating operations are conducted through our subsidiaries. Accordingly, almost all of our cash flow is generated by our subsidiaries. Our subsidiaries are separate and distinct legal entities and have no obligation to make any funds available to us, whether by dividends, fees, loans or other payments. Accordingly, our ability to pay dividends, fund our obligations and make expenditures at the parent company level is dependent not only on the ability of our subsidiaries to generate cash, but also on the ability of our subsidiaries to distribute cash to us in the form of dividends, fees, principal, interest, loans or otherwise.

Our subsidiaries may be obligated, pursuant to loan agreements, indentures, project financing arrangements or guarantees, to satisfy certain obligations or other conditions before they may make distributions to us. Under our credit agreements, indentures, guarantees and project finance arrangements, if a debtor subsidiary defaults on its indebtedness, it will only be permitted to pay dividends or make other similar distributions to us to the extent permitted under its relevant financing arrangement. In addition, the payment of dividends or the making of loans, advances or other payments to/from us may be subject to legal or regulatory restrictions. Our subsidiaries may also be prevented from distributing funds to us as a result of restrictions imposed by governments on repatriating funds or converting currencies. Any right we have to receive any assets of any of our subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of our indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of those subsidiaries’ creditors (including trade creditors and holders of debt issued by such subsidiary).

Our businesses are separate and distinct legal entities in different jurisdictions and, unless they have expressly guaranteed any of our indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available therefore, whether by dividends, fees, loans or other payments. Changes in tax policies, or the interpretation of those policies, of or within the jurisdictions in which we operate could materially adversely affect our tax profile, significantly increase our future cash tax payments and adversely affect our financial condition or results of operations.

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We are a Cayman Islands company and may not receive the diplomatic and treaty protections that a U.S. company would receive in some of the countries where we do business, which could adversely affect our ability to enforce our rights under our concessions and contracts.

As a Cayman Islands company, we may not have the benefit of bi-lateral investment treaties, diplomatic assistance, foreign service offices or influence through our jurisdiction’s distribution of foreign aid. One or all of these factors may affect our ability to enforce our rights in the countries where we do business.

If ownership of our ordinary shares continues to be highly concentrated, it may prevent you and other minority shareholders from influencing significant corporate decisions and policies.

A group of investment funds directly or indirectly managed by Ashmore, or collectively the Ashmore Funds, owned, as of December 31, 2009, approximately 55% of our ordinary shares. Buckland Investment Pte Ltd., or Buckland, and funds managed by Eton Park Capital Management, L.P., or Eton Park, owned approximately 22% and 6%, respectively, as of such date and other institutional investors, and members of management, directors and our employees and former employees owned the remaining ordinary shares. Consequently, the Ashmore Funds individually, and the Ashmore Funds, Buckland and Eton Park or any combination of the three collectively, have significant influence over the determination of matters submitted to a vote of our shareholders, including in the election of our directors, the appointment of new management and the adoption of amendments to our Memorandum and Articles of Association. The ability of other shareholders to influence our management and policies may be severely limited, including with respect to mergers, amalgamations, consolidations or acquisitions, our acquisition or disposition of our ordinary shares or other equity securities and the payment of dividends or other distributions on our ordinary shares. Additionally, this concentration of ownership may delay, deter or prevent acts that would be favored by our other shareholders, such as change of control transactions that would result in the payment of a premium to our other shareholders.

Our shareholders may compete with us for investment opportunities which could impair our ability to consummate transactions.

Our shareholders and their affiliates may compete with us for investment opportunities, may invest in entities that directly or indirectly compete with us or companies in which they currently invest may begin competing with us. This could impair our ability to consummate transactions. We have no ability to control, nor will we necessarily be aware of, whether any of our shareholders currently compete with us or will in the future acquire interests in companies that will compete with us. Furthermore, Brent de Jong, a representative of Ashmore, who previously was a director and executive officer of our company, is involved in our business development activities. In situations where we and the Ashmore Funds have competing interests, Mr. de Jong may not be disinterested.

The interests of the group of shareholders that control us may be adverse to your interests.

Pursuant to the Second Amended and Restated Shareholders Agreement and through their ownership of our ordinary shares, the Ashmore Funds are entitled to elect a majority of the members of our board of directors and to effectively control substantially all actions to be taken by our shareholders. The Ashmore Funds’ voting control also prevents other shareholders from exercising significant influence over our business decisions. The Ashmore Funds may have interests that differ from other shareholders and may vote in a way with which such shareholders disagree and that may be adverse to their interests. For a description of the Second Amended and Restated Shareholders Agreement, see “Item 10. Additional Information — C. Material Contracts.”

We have granted to our current institutional shareholders certain rights to have their securities registered in accordance with the U.S. securities law pursuant to the terms of our existing Amended and Restated Registration Rights Agreement. For a description of the Amended and Restated Registration Rights Agreement, see “Item 10. Additional Information — C. Material Controls.”

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Item 4. Information on the Company

A. History and Development of the Company

Our Corporate Information

The legal and commercial name of the company is AEI. We were incorporated as an exempted company with limited liability under the laws of the Cayman Islands in June 2003. Our principal executive offices are located at Clifton House, 75 Fort Street, P.O. Box 190GT, George Town, Grand Cayman, Cayman Islands and our telephone number is 345-949-4900. The principal executive offices of our wholly owned affiliate AEI Services LLC, which provides management services to us, are located at 700 Milam, Suite 700, Houston, TX 77002, and its telephone number is 713-345-5200. Our website is www.aeienergy.com. Information contained on, or accessible through, our website is not incorporated by reference in, and shall not be considered part of, this annual report.

History

AEI was formed by a series of transactions that began with the contribution of Elektra shares to Ashmore Energy International Limited, or AEIL, a Cayman Islands company formed by Ashmore Investment Management Limited, or Ashmore, in March 2006. Subsequently, in 2006, AEIL acquired PEI from Enron Corp. and certain of its subsidiaries in two stages, accounted for as a purchase step acquisition, as follows:

	•		Stage 1 (completed May 25, 2006) — AEIL acquired 24.26% of the voting capital and 49% of the economic interest in PEI.

	•		Stage 2 (completed September 7, 2006) — AEIL acquired the remaining 75.74% of the voting capital and the remaining 51% economic interest of PEI.

On December 29, 2006, AEIL and PEI were amalgamated under Cayman law, with PEI being the surviving entity. On the same date, PEI changed its name to Ashmore Energy International, and thereafter to AEI.

B. Business Overview

We own and operate essential energy infrastructure assets in emerging markets. We are exclusively focused on emerging markets because they have higher rates of GDP growth as well as lower base levels of overall and per capita energy consumption compared to developed markets. We believe that growth in emerging markets will drive increases in overall and per capita energy consumption and therefore require significant additional investments in energy infrastructure assets. Emerging market growth is primarily driven by industrialization and urbanization. Global Insight, a global source of economic information, is predicting annual growth of 6.0% for countries which are not members of the Organization for Economic Cooperation and Development, or OECD, for the period 2010-2019 versus 2.3% for OECD countries over the same period.

	•		Power Distribution: approximately 27,300 GWh sold, 4.9 million electric power customers, and 121,100 miles of power distribution and transmission lines;

	•		Power Generation: approximately 9,600 GWh sold, and 2,278 MW of electric power generation capacity with an additional 300 MW under construction;

	•		Natural Gas Transportation and Services: approximately 3,300 mmcfd average throughput and 4,900 miles of natural gas and gas liquids transportation pipelines;

	•		Natural Gas Distribution: approximately 400 mmcfd average sales, 2.5 million natural gas distribution customers and 21,800 miles of natural gas distribution pipeline networks; and

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•

Retail Fuel: approximately 4.7 mm gal/day average throughput of liquid fuels, 34.9 mmcfd average sales of compressed natural gas, or CNG, and 1,861 owned and affiliated gasoline and CNG service stations. Retail Fuel is a non-core business for us and we are currently exploring strategic alternatives with respect to that business.

Because our businesses are largely regulated and generally contracted to a sole or limited number of customers, significant efforts to market the products we sell in our segments are not required.

For the year ended December 31, 2009, we generated consolidated operating income of $731 million, net income attributable to AEI of $297 million and Adjusted EBITDA of $1,146 million. The following 2009 Adjusted EBITDA charts by regions and by segment are based on our 2009 audited consolidated financial statement, included elsewhere in this annual report.



Note: Excludes Headquarters and Eliminations		Note: Excludes Headquarters and Eliminations

Our Strategy

Our strategy is to own and operate essential energy infrastructure assets in emerging markets diversified across our four core business segments and five regions. We seek to maximize value for our shareholders through increasing the profitability and free cash flow of our existing businesses and the rigorous allocation of capital to grow our company. We invest our capital at risk-adjusted rates of return into organic expansion of existing businesses, acquisitions of new businesses or incremental interests in existing businesses and brownfield and greenfield development of new businesses. We target opportunities that we believe will reinforce and build upon our existing core business segments and result in operational synergies. We prefer investments that provide operational control or the ability to exert significant influence, or strategic noncontrolling interest positions that offer the opportunity to gain control or significant influence over the investment in the future. From January 2007 through December 31, 2009, we have acquired new or additional interests in several businesses and are also currently pursuing additional acquisitions and greenfield development opportunities. We have deployed capital in excess of $1.7 billion, including cash and, in certain cases, our ordinary shares, in connection with these opportunities.

In executing our strategy, we seek to:

	•		apply operational, environmental and health and safety best practices to maximize the operational performance and increase profitability and free cash flow of our existing businesses;

	•		develop and maintain strong relationships with local regulators, governments, employees and communities through active involvement in the regulatory process and the maintenance of open communication channels;

	•		leverage our management teams and their relationships and market knowledge to optimize the management of our businesses and identify and execute growth opportunities;

	•		maintain a predictable and flexible capital structure with moderate levels of debt which allows us to take advantage of growth opportunities and reinvest cash flow to enhance growth; and

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•

integrate new businesses and share and employ best practices, both financial and operational, to maximize performance.

Our Competitive Strengths

We believe that the following competitive strengths distinguish us from our competitors and are critical to the continued successful execution of our strategy.

Exclusive focus in emerging markets

We operate exclusively in emerging markets. We focus on these markets because we believe they have greater growth in energy demand and related infrastructure requirements as compared to more developed markets. We believe that our proven track record as investors exclusively focused in the emerging markets on a long-term basis gives us credibility with a wide range of stakeholders including governments, non-governmental organizations, regulators, customers and employees. This, together with our established and locally branded presence, allows us to more effectively manage and grow our business and mitigate risks.

We are focused on being well positioned in our four core segments of the energy infrastructure industry and within five key emerging market regions

We have an established and locally branded presence in the segments and regions in which we operate that we believe positions us to optimize the management of our businesses and critical risks while at the same time benefit from above-average growth prospects. We also believe that our ability to identify and consider investments in multiple, yet defined, segments and regions continuously presents us with a robust set of investment opportunities irrespective of challenges that may occur in any one segment or region at a particular time.

Predictable and flexible financial profile to support growth

We generate the vast majority of our earnings from our regulated and contracted businesses. Most of these businesses have historically generated predictable cash flow with limited fluctuations due to seasonality and are either U.S. dollar-denominated or benefit from mid- to long-term indexation to the U.S. dollar through foreign exchange and inflation adjustments. Our financial profile is further enhanced by the geographic diversification of our businesses with well over half of our earnings derived from countries with investment grade ratings. The combination of our stable cash flow and moderate debt level provides us with rapid and efficient access to capital when we identify compelling growth opportunities.

Demonstrated capability to grow in a disciplined manner

We have successfully demonstrated our ability to grow our company in a disciplined manner as evidenced, for example, by the increase in our diluted earnings per share from $0.42 in 2007 to $0.73 in 2008 to $1.27 in 2009. We have improved the operational and financial performance of our existing businesses; delivered organic growth from existing businesses, including the ongoing build-out of our natural gas distribution business in China, Colombia and Peru; demonstrated an ability to integrate multiple acquisitions of new businesses; and captured valuable greenfield development opportunities that we are currently in the process of executing.

Operational excellence

We are committed to the reliable, responsible, efficient and safe operations of our businesses with a disciplined focus on high operating, health, safety and environmental standards. We have a recognized record for operational excellence and many of our businesses are leaders in their markets, surpassing both local and U.S. standards and their contractual requirements. We had company-wide power distribution line losses of 8.60%, power plant reliability of 97.70%, natural gas pipeline reliability of 100.00% and natural gas processing reliability of 99.56% in 2009. Additionally, our Lost Time Incident Rate for all our businesses was 0.56 in 2009, well below the U.S. industry average of over 1.1 according to the U.S. Bureau of Labor Statistics. Our commitment to operational excellence is critical to achieving compliance with regulations and contracts and to maintaining credibility and generating trust with our key stakeholders, including governments, regulators, off-takers, employees and local communities. Our focus on operational excellence enhances our financial performance and is essential to the execution and sustainability of our strategy.

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Experienced management team with strong local presence

Our management team, including the executives in each of the regions in which we operate, has extensive experience operating, developing and acquiring businesses in the energy industry, with an average of approximately 18 years of experience. We believe that this overall level of experience contributes to our ability to effectively manage existing businesses, identify and evaluate high quality growth opportunities and integrate new businesses that are acquired or developed. The management teams of our businesses consist primarily of local executives who have significant experience working in the local energy industry and with government regulators. We believe that the market specific experience of our local management provides us with visibility into the local regulatory, political and business environment that gives us a greater ability to manage risk and identify new opportunities.

Our Business Segments

Power Distribution

Our Power Distribution businesses distribute and sell electricity primarily to residential, industrial and commercial customers. Most of the businesses in this segment operate in a designated and exclusive service area defined in a regulated concession agreement. All of the concession agreements and/or associated regulations include tariffs that are periodically reviewed by regulators and are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on their respective regulated asset base.

For the year ended December 31, 2009, the Power Distribution segment accounted for 56% of our operating income and 50% of our Adjusted EBITDA.

The table below provides a summary of our Power Distribution segment businesses’ commercial and operational information as of and for the dates indicated:


								Network				Energy
		Commercial		Ownership			Operating	Length		Customers		Sold		Concession			Regulated			Next Tariff
	Location	Operations		(%)			Control	(miles)		(000s)		(GWh)		Termination			Return ⁽¹⁾			Review
Andean
Luz del Sur	Peru		1994		37.97	%	Joint control		11,565		833		5,488	Indefinite		⁽²⁾		12.00	%	2013 (every 4 years)
Chilquinta	Chile		1981		50.00	%	Joint control		5,169		486		2,281	Indefinite		⁽²⁾		10.00	%	2012 (every 4 years)

Southern Cone
Elektro	Brazil		1998		99.68	%	Yes		66,597		2,123		11,036		2028	⁽³⁾		15.08	%	2011 (every 4 years)
EMDERSA	Argentina		1993		77.10	%	Yes		15,885		509		2,814		2010, 2016, 2018	⁽⁴⁾		10.59, 9.54, 12.00	% % % ⁽⁵⁾	Every 5 years⁽⁶⁾
EDEN	Argentina		1997		90.00	%	Yes		10,971		327		2,237		2012	⁽⁷⁾		N/A		undefined

Central America/Caribbean
Elektra	Panama		1998		51.00	%	Yes		5,605		348		2,351		2013	⁽⁸⁾		10.73	%	2010 (every 4 years)
Delsur	El Salvador		1996		86.41	%	Yes		5,313		314		1,141	Indefinite		⁽⁹⁾		10.00	%	2012 (every 5 years)


(1)		Inflation adjusted on regulated asset base before tax.

(2)		Terminates only if the company breaches the concession.

(3)		Elektro’s concession is renewable for 30 years.

(4)		The current administrative period of the concessions for EDELAR, EDESA, and EDESAL expire in 2010, 2016 and 2018, respectively. The concessions for EDELAR and EDESAL are renewable for 10-year periods through 2090 and 2088, respectively, subject to winning a new bid. The concession for EDESA is renewable for 15-year periods through 2046, subject to winning a new bid.

(5)		The regulated returns for EDELAR, EDESA and EDESAL are 10.59%, 9.54% and 12.00% respectively.

(6)		The expected tariff reviews for EDESA and EDELAR are 2011 and 2013 respectively. The tariff for EDESAL is currently under review.

(7)		EDEN’s concession is renewable for 10-year terms through 2092, subject to winning a new bid.

(8)		Elektra’s concession is renewable for 15 years, subject to winning a new bid.

(9)		Terminates only if the company breaches the license.

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Andean Power Distribution

Luz del Sur S.A. (Luz del Sur)

Luz del Sur supplies electricity to a service area with a population of approximately 4.0 million that encompasses approximately 1,100 square miles in the Provinces of Lima (southern half) and Cañete. As of December 31, 2009, Luz del Sur had approximately 833,000 customers and sold approximately 5,488 GWh of electricity in 2009. We co-control and own 37.97% of Luz del Sur. The remaining ownership interest is owned by Sempra Energy International, or Sempra, and by local Peruvian investors. Luz del Sur is a public company traded on the Peruvian Stock Exchange under the symbol “LUSURC1” with negligible liquidity.

Luz del Sur holds an exclusive indefinite concession from the Peruvian Ministry of Energy and Mines, or MEM. Luz del Sur’s concession is renewed annually and provides exclusive distribution rights within its concession area. The annual renewal is automatic subject to Luz del Sur’s compliance with applicable law and regulation. An existing concession of an electricity distribution company in Peru may only be cancelled by the MEM if such electricity distribution company fails to remediate any specific breach of applicable law or regulations after receiving notice of any such breach.

Tariffs for Peruvian electricity distribution companies are reviewed by the Peruvian Supervisory Organization of Investment in Energy and Mining (Organismo Supervisor de la Inversión en Energía y Mineria), or OSINERGMIN, periodically. Luz del Sur has tariff reviews every four years, and its last review was in November 2009. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted every 12 months for inflation of controllable costs (but may be adjusted more frequently based on a threshold for inflation) and to pass-through adjustments to noncontrollable costs.

Chilquinta Energía S.A. (Chilquinta)

Chilquinta supplies electricity to a service area with a population of approximately 1.5 million that encompasses approximately 2,000 square miles in the Fifth Region of Chile (including the city of Valparaíso). As of December 31, 2009, Chilquinta had approximately 486,000 customers and sold approximately 2,281 GWh of electricity in 2009. We co-control and own 50.0% of Chilquinta. The remaining ownership interest is owned by Sempra. Chilquinta also controls and owns 75.61%, 56.59%, 85.00% and 69.75% of Compañía Eléctrica del Litoral S.A., LuzParral S.A., LuzLinares S.A and Energía de Casablanca S.A. respectively, which also supply electricity in the Fifth and Seventh Regions of Chile through exclusive concessions.

Chilquinta holds an exclusive indefinite concession from the National Energy Commission (Comisión Nacional de Energía) or CNE. Chilquinta’s concession is renewed annually and provides exclusive distribution rights within its concession area. The annual renewal is automatic, subject to Chilquinta’s compliance with applicable law and regulation. An existing concession of an electricity distribution company in Chile may only be cancelled by CNE if such electricity distribution company fails to remediate any specific breach of applicable law or regulations after receiving notice of any such breach. Compañía Eléctrica del Litoral S.A., LuzParral S.A., LuzLinares S.A. and Energía de Casablanca S.A. each also hold an exclusive indefinite concession from the CNE.

Tariffs for Chilean electricity distribution companies are reviewed by CNE periodically. Chilquinta has tariff reviews every four years, and its last review was in November 2008. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted monthly for inflation of controllable costs and every six months to pass-through adjustments to noncontrollable costs.

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Southern Cone Power Distribution

Elektro Eletricidade e Serviços S.A. (Elektro)

Elektro supplies electricity to a service area with a population of approximately 5.5 million that encompasses approximately 46,000 square miles and 228 municipalities in the states of São Paulo and Mato Grosso do Sul, Brazil. As of December 31, 2009, Elektro had approximately 2.1 million customers and sold approximately 11,036 GWh of electricity in 2009. We own 99.97% of the voting rights and 99.68% of the economic rights in Elektro. The remaining economic and voting rights are owned by local Brazilian investors. Elektro is a public company and traded on the São Paulo Stock Exchange with negligible liquidity under the symbol “EKTR3” for its ordinary shares and “EKTR4” for its preferred shares.

Elektro holds an exclusive 30-year renewable concession from the Brazilian National Electric Energy Agency (Agência Nacional de Energia Elétrica), or ANEEL. Elektro’s concession agreement, the first term of which expires in 2028, provides exclusive distribution rights within its concession area. We can seek an extension of the concession agreement for an additional term of 30 years by submitting a written request to ANEEL accompanied by proof of compliance with various regulatory, fiscal and social obligations required by law.

Tariffs for Brazilian electricity distribution companies are reviewed by ANEEL periodically. Elektro has tariff reviews every four years, and its last review was in August 2007. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted every 12 months for inflation of controllable costs and to pass-through adjustments to noncontrollable costs. The X factor (inflation reductor of the annual controllable costs adjustment) aims to capture scale gains due to market growth and pass those gains through to customers.

The pass-through mechanism has historically allowed distribution companies to benefit from higher energy sales or improved sales mix in comparison with the parameters utilized in the preceding tariff review during the four year cycle until the following tariff review. Nevertheless, losses could also be incurred if sales or mix were less favorable than forecasted. However, ANEEL has indicated that the pass-through of noncontrollable costs should be neutral, meaning that it should not cause any gains or losses to the distribution companies. In December 2009, a new methodology relating to the pass-through of noncontrollable costs was negotiated between ANEEL and the local distribution companies. With respect to Elektro, the effect of this new methodology is that any pass-through will now be neutral. In February 2010, ANEEL approved an amendment to the concession contracts of the distribution companies reflecting the new methodology, and Elektro signed the amendment in March 2010.

Under its concession, Elektro is also entitled to an extraordinary tariff review to restore economic equilibrium if significant macroeconomic events or changes in law alter its cost and revenue structure.

Elektro’s energy requirements are supplied by: (i) contracts from the Itaipu hydro power plant which expire in 2023; (ii) contracts from regulated public auctions; (iii) a renewable energy government program; or (iv) through bilateral contracts which were signed before the 2003 regulatory changes. These contracts are denominated in Brazilian reais and adjusted for inflation, except for those with Itaipu, which are U.S. dollar-denominated and accounted for about 24% of Elektro’s power supply in 2009. The applicable regulation uses a tracking account mechanism to capture possible foreign exchange effects which are passed through to tariffs upon the annual adjustment.

Current legislation requires that distribution companies contract of their energy needs through federally regulated public auctions. The power purchase agreements, or PPAs, resulting from these auctions are nonnegotiable adhesion contracts, which are regulated by the government in every aspect except for volume (defined by the distribution companies’ load forecast profile) and price (the maximum purchase price as defined by the government). The purchase price for the distribution companies is established during the federal auction bidding process and is fully passed through to the customer tariff. Distribution companies can also purchase up to 10% of their energy needs from distributed generation within their concession areas.

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Distribution companies can purchase their energy needs three to five years ahead. In order to mitigate demand forecast uncertainties, distribution companies have the right to reduce up to 4% of the initially contracted amount in case of market variations and any amount related to eligible customers which become “free customers” without penalty. Energy purchases of up to 3% in excess of a distribution company’s total demand are allowed to be fully passed through to customers. If the distribution company foresees that it may be short of energy in the following years, it may buy additional energy up to 1% of its total demand of the previous year in annual auctions (except 2009, when the limit was 5%); distribution companies can also swap energy contracts of existing power plants with other distribution companies that have a surplus of energy through the swap operation managed by the Chamber of Electric Energy Commercialization (Câmara de Comercialização de Energia Elétrica), or CEEE. If a distribution company has not contracted a sufficient volume to cover its energy needs due to a miscalculation of the demand forecast, it will be subject to penalties by the regulator. A distribution company can also be subject to losses if its long position is higher than 3% of its total demand and prices in the spot market are lower than the average cost of energy purchased.

In order to comply with these regulations, Elektro has purchased energy in auctions to cover its estimated market growth through eight-year term contracts with existing power plants, 30-year term contracts with new hydro power plants and 15-year term contracts with new thermal power plants. With these purchases, Elektro believes it has met its forecasted energy needs through the year 2012.

Empresa Distribuidora Eléctrica Regional S.A. (EMDERSA)

EMDERSA, through its subsidiaries Empresa Distribuidora de San Luis S.A., or EDESAL, Empresa Distribuidora de La Rioja S.A., or EDELAR, and Empresa Distribuidora de Salta S.A., or EDESA, supplies electricity to a service area with a population of approximately 2.0 million that encompasses approximately 124,000 square miles in the Provinces of San Luis, La Rioja and Salta, respectively. As of December 31, 2009, EMDERSA had approximately 509,000 customers and sold approximately 2,814 GWh of electricity in 2009. EDESA also owns 90% of Empresa de Sistemas Elétricos Dispersos, or ESED, an electricity generation and distribution company that supplies energy to customers in remote areas of the Province of Salta through the utilization of photovoltaic solar panels. In addition, EMDERSA’s subsidiary, EMDERSA Generación Salta S.A., or EGSSA, is in the process of obtaining the operational approval from the Argentine Secretary of Energy to generate electricity through a natural gas-fired 30MW plant located in the northeast region of the Province of Salta which is expected to start operations in the first half of 2010. We own 77.10% of EMDERSA. A substantial amount of the remaining ownership interest is owned by Argentine government pension funds. EMDERSA is a public company and traded on the Buenos Aires Stock Exchange with negligible liquidity under the symbol “EMDEHR”. EMDERSA owns 99.99%, 99.99%, 90.00% and 99.98% of EDESAL, EDELAR, EDESA and EGSSA respectively. Our acquisition of EMDERSA is still pending local anti-trust approval.

EDESAL, EDELAR and EDESA each hold an exclusive long-term renewable concession from the San Luis, La Rioja and Salta Province regulators respectively. EDESAL’s concession agreement is divided into several administrative periods, the first of which was 15 years and expired in 2008, followed by eight successive ten-year periods, the next of which will expire in 2018. At the end of each period a competitive bid process for the sale of a minimum of 51% of the share capital of EDESAL will take place. We can participate in the bidding and will only be required to sell and transfer control of our interest in EDESAL if there is a higher bidder, in which case we will receive the amount bid by the higher bidder. Following the auction, a new ten-year concession will be granted to EDESAL at the end of which the auction process would be held again. EDELAR’s concession is divided similarly with an initial period of 15 years (ending in 2010) followed by eight successive ten-year periods with a competitive bidding process at the end of each period which follows the same process as described for EDESAL. EDESA’s concession has an initial period of 20 years (ending 2016) followed by two successive 15-year periods with a competitive bidding process at the end of each period which follows the same process as described for EDESAL and EDELAR.

Tariffs for Argentine electricity distribution companies are periodically reviewed by the regulators within the service area that the concession is located. EMDERSA’s subsidiaries generally have tariff reviews every five years. EDESAL’s tariff is currently under review, and the tariffs for EDESA and EDELAR are expected to be reviewed in 2011 and 2013, respectively. The tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted every six or 12 months for inflation of controllable costs and to pass-through adjustments to noncontrollable costs.

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Empresa Distribuidora de Energía Norte S.A. (EDEN)

EDEN supplies electricity to a service area with a population of approximately 1.0 million that encompasses approximately 42,000 square miles in the Province of Northern Buenos Aires. As of December 31, 2009, EDEN had approximately 327,000 customers and sold approximately 2,237 GWh of electricity in 2009. We own 90% of EDEN. The remaining ownership interest is owned by EDEN employees. Our acquisition of EDEN is still pending local anti-trust approval.

EDEN holds an exclusive long-term renewable concession from the Buenos Aires Province regulator. EDEN’s concession agreement is divided into several administrative periods, the first term of which is 15 years and expires in 2012, followed by ten-year periods thereafter. At the end of this term, a competitive bid process for the sale of a minimum of 51% of the share capital of EDEN will take place. We can participate in the bidding and will only be required to sell and transfer control of our interest in EDEN if there is a higher bidder, in which case we will receive the amount bid by the higher bidder. Following the auction, a new ten-year concession will be granted to EDEN at the end of which the auction process would be held again.

Tariffs for Argentine electricity distribution companies are reviewed periodically by the regulators within the service area that the concession is located (in the case of EDEN this is the Buenos Aires Province). EDEN has tariff reviews periodically. However, such tariff reviews are currently not well defined, which results in distribution companies advocating adjustments on an ad hoc basis. Although not well defined, the tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted for inflation of controllable costs and to pass-through adjustments to noncontrollable costs.

Central America/Caribbean Power Distribution

Elektra Noreste, S.A. (Elektra)

Elektra supplies electricity to a service area with a population of approximately 1.5 million that encompasses approximately 11,000 square miles in the Provinces of Colon and Eastern Panama City. As of December 31, 2009, Elektra had approximately 348,000 customers and sold approximately 2,351 GWh of electricity in 2009. We own 51% of Elektra. A substantial majority of the remaining ownership interest is owned by the Panamanian government.

Elektra holds an exclusive 15-year renewable concession from the Panamanian National Authority of Public Services (Autoridad Nacional de los Servicios Públicos), or ASEP. Elektra’s concession agreement, the first term of which expires in 2013, provides exclusive distribution rights within the concession area. At the end of this term, a competitive bid process for the sale of a minimum of 51% of the share capital of Elektra will take place. We can participate in the bidding and will only be required to sell and transfer control of our interest in Elektra if there is a higher bidder, in which case we will receive the amount bid by the higher bidder. Following the auction, a new 15-year concession will be granted to Elektra, and at the end of this term the auction process would be held again.

Tariffs for Panamanian electricity distribution companies are reviewed by ASEP periodically. Elektra has tariff reviews every four years, and its last review was in June 2006 (with its next review expected in June 2010). Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted every six months for inflation of controllable costs and monthly to pass-through adjustments to noncontrollable costs.

Distribuidora de Electricidad Del Sur, S.A. de C.V. (Delsur)

Delsur supplies electricity to a service area with a population of approximately 1.5 million and encompasses approximately 1,700 square miles in the south-central region of El Salvador. As of December 31, 2009, Delsur had approximately 314,000 customers and sold approximately 1,141 GWh of electricity in 2009. We own 86.41% of Delsur. The remaining ownership interest is owned by employees and other private investors. Delsur is a public company and traded on the El Salvadoran Stock Exchange with negligible liquidity under the symbol “ADELSUR.”

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Delsur holds a non-exclusive indefinite license from the El Salvador General Superintendency of Electricity and Telecommunications (Superintendencia General de Electricidad y Telecomunicaciones), or SIGET. Delsur’s license is renewed annually and provides non-exclusive distribution rights in El Salvador. The annual renewal is automatic subject to Delsur’s compliance with applicable law and regulation. An existing license of an electricity distribution company in El Salvador may only be cancelled by SIGET if such electricity distribution company fails to remediate any specific breach of applicable law or regulations after receiving notice of any such breach. Although electricity distribution companies in El Salvador have no exclusivity over a specific territory, in practice they serve specific geographic areas.

Tariffs for El Salvadoran electricity distribution companies are reviewed by SIGET periodically. Delsur has tariff reviews every five years, and its last review was in December 2007 (with an amendment in March 2008). Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted every 12 months for inflation (50%) of controllable costs, and every six months to pass-through adjustments to noncontrollable costs.

Power Generation

Our Power Generation businesses generate and sell wholesale capacity and energy primarily to power distribution businesses and other large off-takers. Most of the businesses in this segment sell substantially all of their generating capacity and energy under long-term PPAs. Our PPAs generally are structured to minimize our exposure to fluctuations in commodity fuel prices. In addition, our PPAs are generally dollar-denominated.

For the year ended December 31, 2009, the Power Generation segment accounted for 13% of our operating income and 14% of our Adjusted EBITDA.

The table below provides a summary of our Power Generation segment stand-alone commercial and operational information as of and for the dates indicated:


								Long-term
							Energy	Capacity		Fuel Supply
		Commercial	Ownership	Operating	Primary	Capacity	Sold	Contracted	PPA	Agreement
	Location	Operations	(%)	Control	Fuel	(MW)	(GWh)	(%)	Termination	Termination
Southern Cone
Cuiabá — EPE	Brazil	1999	100.00%	Yes	Natural Gas	480	0	0%	N/A		N/A
Emgasud	Argentina	1991⁽¹⁾	42.73%	No	Natural Gas	205	234	100%	2011-2012⁽²⁾	Monthly

Central America/Caribbean
PQP	Guatemala	1993	100.00%	Yes	Bunker Fuel	234	1,502	47%	2013		2013	⁽³⁾
San Felipe	Dominican Rep.	1994	100.00%	Yes	Bunker Fuel	180	762	94%	2015		N/A
Corinto	Nicaragua	1999	57.67%	Yes	Bunker Fuel	71	510	71%	2014		2014	⁽⁴⁾
JPPC	Jamaica	1998	84.42%	Yes	Bunker Fuel	60	438	100%	2018		2018
Tipitapa	Nicaragua	1999	57.67%	Yes	Bunker Fuel	51	391	100%	2014		2014
Amayo	Nicaragua	2009	13.42%	No	Wind	40	109	100%	2024		N/A

China
Luoyang	China	2006	50.00%	Yes	Coal	270	1,036	0%	Annually		N/A

Europe/Middle East/North Africa
Trakya	Turkey	1999	90.00%	Yes	Natural Gas	478	3,794	100%	2019		2014	⁽⁵⁾
ENS	Poland	2000	100.00%	Yes	Natural Gas	116	755	0%	2010		2019
DCL	Pakistan	2008	60.23%	Yes	Natural Gas	94	57	76%	2010		2038


(1)		Power Generation operations began in 2008.

(2)		The majority of Emgasud’s PPAs terminate in 2011 or 2012 and provide for an extension of two additional years.

(3)		PQP’s fuel supply agreement has an option to extend to 2016.

(4)		Corinto’s fuel supply agreement has an option to extend to 2017.

(5)		Trakya’s fuel supply agreement provides for an extension to 2019, subject to the availability of natural gas.

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Southern Cone Power Generation

Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE)

Cuiabá Integrated Project consists of four companies that on an integrated basis own and operate a power plant in Brazil, purchase natural gas in Bolivia and transport it through pipelines to Brazil for use as fuel for the power plant. The four companies are EPE, GOB, Transborder Gas Services Ltd., or TBS, and GasOcidente do Mato Grosso Ltda., or GOM. See also “— Natural Gas Transportation and Services — Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS).” EPE is a combined-cycle dual-fuel natural gas/diesel fired power generation plant with a nominal capacity of 480 MW. The power plant is located in Cuiabá in the state of Mato Grosso do Sul, Brazil. The power plant consists of two Siemens V 84.3A combustion turbine generators, two Hanjung heat recovery system generators and one Siemens steam turbine generator. The power plant commenced commercial operations in 2002. We own 100.00% of EPE. EPE has generally not operated since August 2007 due to lack of natural gas supply. For more information, see Note 25 to our consolidated financial statements.

Emgasud S.A. (Emgasud)

Emgasud is an Argentine energy company which primarily operates in power generation, but also currently operates in the natural gas transportation and services, natural gas distribution, natural gas pipeline construction and energy commercialization businesses. Emgasud is currently reviewing its non-power generation businesses. As a result of this review, Emgasud may consider the sale, or discontinuation of these businesses. Emgasud’s power generation business consists of various natural gas-fired simple cycle power generation plants with a combined nominal capacity of approximately 205 MW. The power plants are located at various locations in Argentina and commenced commercial operations at various times throughout 2009. Emgasud has contracts in place to develop a 63 MW power plant which is currently scheduled to come on line in 2011. We own 42.73% of Emgasud. The remaining ownership interest is owned by local Argentine investors. Our acquisition of Emgasud is still pending local anti-trust approval.

Emgasud’s revenue from its power generation business is derived from selling the capacity and energy produced by the power plants to Energía Argentina S.A., or ENARSA, a state-run power company (ENARSA entered into an agreement with Compañía Administradora del Mercado Mayorista Eléctrico S.A., or CAMMESA, the state-run power pool administrator, who ceded rights to Emgasud), under PPAs with terms ending in 2011 and 2012 with an option for CAMMESA to extend for two additional years. The tariffs under the PPAs with CAMMESA are based on a structure with fixed capacity and variable energy components that allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in U.S. dollars.

Natural gas is the power plants’ primary fuel and is provided by Repsol YPF, PanAmerican Energy, Petrobras, and Total Austral under monthly fuel supply agreements. The dispatch for power plants in Argentina is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched.

The agreement that we currently have with Emgasud provides for the acquisition by us or our affiliates of an equity interest in Emgasud of up to a total of 63.1% through our contribution of certain assets to Emgasud, subject to certain conditions including local anti-trust and regulatory approvals.

Emgasud is currently experiencing financial difficulties and has recently missed an interest payment on an intercompany note held by us. For more information, see Note 3 to our consolidated financial statements. If Emgasud is unable to repay its creditors on a timely basis, such creditors may seek to exercise various remedies, including foreclosing on some or all of Emgasud’s assets, or Emgasud may elect to seek a reorganization filing. Such events would have a corresponding negative impact on our financial performance and results of operations, but we do not believe this would have a material adverse effect on our business as a whole.

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Central America/Caribbean Power Generation

Puerto Quetzal Power LLC (PQP)

PQP is a bunker fuel oil-fired power generation plant with a nominal capacity of 234 MW. The power plant is located on the Pacific coast at Puerto Quetzal, Guatemala, approximately 60 miles south of Guatemala City. The power plant consists of three barges with 20 Wartsila 18V32 reciprocating engines and seven MAN B&W 18V48/60 reciprocating engines. The power plant commenced commercial operations in 1993 for the Wartsila engines and 2000 for the MAN B&W engines. We own 100.00% of PQP.

A portion of PQP’s revenue is derived from selling 110 MW of the capacity and energy produced by the power plant to Empresa Eléctrica de Guatemala S.A., or EEGSA, which is owned by Ibedrola, TECO Energy and EDP, under a PPA with a term ending in 2013. PQP, through its wholly-owned subsidiary Poliwatt Limitada, or Poliwatt, sells the remaining 124 MW of the capacity and energy produced by the power plant in the Guatemalan and regional wholesale electricity market typically under one- to-four year PPAs. The tariffs under the PPAs with EEGSA and the market are based on structures with fixed capacity and variable energy components that allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in U.S. dollars.

Bunker fuel is the power plant’s primary fuel and is provided by Glencore under a fuel supply agreement with a term ending in 2013 and an option to extend to 2016. The dispatch for power plants in Guatemala is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched. From time to time PQP enters into hedging arrangements to reduce exposure to the volatility of fuel prices.

Generadora San Felipe Limited Partnership (San Felipe)

San Felipe is a combined-cycle bunker fuel oil-fired power generation plant with a nominal capacity of 180 MW. The power plant is located on the Atlantic coast at Puerto Plata, Dominican Republic, approximately 150 miles northwest of Santo Domingo. The power plant is located on a land-locked barge and consists of one GE 7EA combustion turbine generator, one GE heat recovery system generator and a land-based boiler (burning bunker fuel oil) and one GE steam turbine generator. Under the current PPA, San Felipe began delivering its full capacity in January 1996. We own 100.00% of San Felipe.

San Felipe’s revenue is derived from selling 170 MW of the capacity and energy produced by the power plant to the Dominican Corporation of State Electricity Companies (Corporación Dominicana de Empresas Eléctricias Estatales), or CDEEE, a state-run power company, under a PPA with a term ending in 2015. The tariffs under the PPA with CDEEE are based on a structure with fixed capacity and variable energy components that allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in U.S. dollars. As of December 31, 2009, the CDEEE was in payment arrears of approximately $53 million (which excludes $31 million of current accounts receivable), on which it is currently paying interest. As a result of payment delays, San Felipe has from time to time stopped delivering energy. The CDEEE has requested that San Felipe renegotiate the PPA, reducing the present level of energy and capacity charges, but there has been no material progress in the renegotiation.

Bunker fuel is the power plant’s primary fuel source; however, currently San Felipe has no fuel supply agreement and buys 100% of its fuel requirements on a spot, prepaid basis. The dispatch for power plants in the Dominican Republic is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched.

Empresa Energética Corinto Ltd. (Corinto)

Corinto is a bunker fuel oil-fired power generation plant with a nominal capacity of 70.5 MW. The power plant is located on the Pacific coast at Puerto Corinto, Nicaragua, approximately 100 miles northwest of Managua. The power plant is located on a barge and consists of four MAN B&W 18V48/60 reciprocating engines. The power plant commenced commercial operations in 1999. We own 57.67% of Corinto. The remaining ownership interest is owned by Centrans Energy Services Inc., or Centrans.

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Corinto’s revenue is derived from selling 50 MW of the capacity and energy produced by the power plant to Disnorte and Dissur, private power distribution companies owned by Union Fenosa, which was recently acquired by Gas Natural, under a PPA with a term ending in 2014. Corinto sells the remaining 20.5 MW of the capacity and energy produced by the power plant in the Nicaraguan and regional wholesale electricity market typically under one to three year PPAs. The tariffs under the PPAs with Disnorte and Dissur and the market are based on structures with fixed capacity and variable energy components that allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in U.S. dollars.

Bunker fuel is the power plant’s primary fuel source and is provided by Glencore under a fuel supply agreement with a term ending in 2014 and an option to extend to 2017. The dispatch for power plants in Nicaragua is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched. From time to time Corinto enters into hedging arrangements to reduce exposure to the volatility of fuel prices.

Jamaica Private Power Company Ltd. (JPPC)

JPPC is a bunker fuel oil-fired power generation plant with a nominal capacity of 60 MW. The power plant is located in Kingston, Jamaica. The power plant consists of two MAN B&W 9K80MC-S reciprocating engines. The power plant commenced commercial operations in 1998. We own 84.42% of JPPC. The remaining ownership interest is owned by Inkia Energy.

JPPC’s revenue is derived from selling 60 MW of the capacity and energy produced by the power plant to Jamaica Public Services Company Limited, or JPS, a private/public power company (owned by Marubeni, TAQA and Government of Jamaica), under a PPA with a term ending in 2018. The tariffs under the PPA with JPS are based on a structure with fixed capacity and variable energy components that allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in a combination of U.S. dollars and Jamaican dollars.

Bunker fuel is the power plant’s primary fuel source and is provided by Petrojam Limited under a fuel supply agreement with a term ending in 2018. The dispatch for power plants in Jamaica is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched.

Tipitapa Power Company Ltd. (Tipitapa)

Tipitapa is a bunker fuel oil-fired power generation plant with a nominal capacity of 51 MW. The power plant is located in Tipitapa, Nicaragua, approximately 12 miles east of Managua. The power plant consists of five Wartsila 18V38 reciprocating engines. The power plant commenced commercial operations in 1999. We own 57.67% of Tipitapa. The remaining ownership interest is owned by Centrans.

Tipitapa’s revenue is derived from selling 51 MW of the capacity and energy produced by the power plant to Disnorte and Dissur, private power distribution companies owned by Union Fenosa, which was recently acquired by Gas Natural, under a PPA with a term ending in 2014. The tariffs under the PPAs with Disnorte and Dissur are based on a structure with fixed capacity and variable energy components that allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in U.S. dollars.

Bunker fuel is the power plant’s primary fuel source and is provided by Esso under a fuel supply agreement with a term ending in 2014. The dispatch for power plants in Nicaragua is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched. From time to time Tipitapa enters into hedging arrangements to reduce exposure to the volatility of fuel prices.

Consorcio Eólico Amayo S.A. (Amayo)

Amayo is a wind power generation plant with a nominal capacity of 39.9 MW. The power plant is located in Rivas, Nicaragua, approximately 80 miles south of Managua. The power consists of 19 2.1 MW Suzlon S88 50HZ wind turbines. The power plant commenced commercial operations in 2009. We own 13.42% of Amayo. The remaining ownership interest is owned by local and international investors.

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Amayo has entered into two 15-year PPAs with Dissur and Disnorte, private power companies owned by Union Fenosa, which was recently acquired by Gas Natural, for 100% of the energy generated; the PPAs will expire in 2024. The tariffs under the PPAs with Disnorte and Dissur are based on structures with fixed capacity and variable energy components that allow for pass-through of variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in U.S. dollars.

China Power Generation

Luoyang Sunshine Cogeneration Co., Ltd. (Luoyang)

Luoyang is a coal-fired power co-generation plant with a nominal capacity of 270 MW. The power plant is located in Luoyang in the Province of Henan, China, approximately 415 miles from Beijing. The power plant consists of two Harbin circulated fluidized bed boilers and two Harbin steam turbine generators. The power plant commenced commercial operations in 2006. We own 50.00% of Luoyang. The remaining ownership interests of Luoyang are held by private investors and state-owned enterprises.

Luoyang’s revenue is derived from selling 100% of the capacity, energy and steam produced by the power plant to Henan Provincial Power Company, a state-run power company, under a PPA and to the Luoyang Municipal Heating Company, a state-run steam company, under a steam purchase agreement, both of which renew annually. The tariffs under the PPA and steam purchase agreement are designed to allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariffs are denominated and paid in Chinese renminbi.

Coal is the power plant’s primary fuel source and is provided by various coal suppliers. The dispatch for power plants in Henan Province is planned by the Henan Provincial Development and Reform Commission. Luoyang is a priority dispatched plant according to newly adopted energy conservation and efficiency regulations and, as long as it supplies steam and heat in addition to power, it has preferential dispatch of its power generated, in priority to other non-cogeneration power plants in the same grid using gas, coal or oil as their fuel.

Luoyang is currently experiencing liquidity issues. If Luoyang is unable to pay its creditors on a timely basis as a result of its current financial difficulties, such creditors may seek to exercise various remedies including foreclosing on some or all of Luoyang’s assets. Such event would have a corresponding negative impact on our financial performance and results of operations, but we do not believe this would have a material adverse effect on our business as a whole.

Europe/Middle East/North Africa Power Generation

Trakya Elektrik Uretim ve Ticaret A.S. (Trakya)

Trakya is a combined-cycle natural gas/diesel-fired power generation plant with a nominal capacity of 478 MW. The power plant is located in the Province of Tekirdag, Turkey, on the northern coast of the Sea of Marmara approximately 60 miles west of Istanbul. The power plant consists of two Siemens V 94.2 combustion turbine generators, two Nooter/Eriksen heat recovery system generators and one Siemens steam turbine generator. The power plant commenced commercial operations in 1999. We own 90.00% of Trakya. The remaining ownership interest is owned by Gama Holdings, a Turkish conglomerate.

The power plant was constructed on a build, operate and transfer basis pursuant to an implementation contract entered into by Trakya with the Turkish Ministry of Energy and Natural Resources, or MENR. Trakya beneficially owns and operates the power plant during the authorization period, the initial term of which ends in 2019. The authorization period may be extended until 2046, subject to tariff modification, sufficient natural gas supply and other conditions set out in the implementation contract. At the end of the authorization period, the ownership of the power plant will be transferred free of charge to MENR.

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Trakya’s revenue is derived from selling 100% of the capacity and energy produced by the power plant to Türkiye Elektrik Ticaret ve Taahhut A.S., or TETAŞ, a state-run power company, under a PPA with an initial term ending in 2019. The tariff under the PPA is based on a structure with fixed capacity, variable capacity and variable energy components that allow for pass-through of fuel and other variable costs and recovery of operation and maintenance costs, fixed capital costs, servicing of debt and a return on investment. The tariff is denominated and paid in U.S. dollars, except for payments relating to the natural gas energy price, a percentage of variable capacity payments and certain taxes, which are paid in Turkish lira equivalent at the exchange rate for U.S. dollars on the date of payment. The PPA was designed with larger upfront fixed capacity payments, and therefore payments under it decrease over time. However, revenue recognition is levelized over the full contract period.

Natural gas is the power plant’s primary fuel source and is provided by the Turkish government-owned natural gas monopoly, Boru Hatlari Ile Petrol Tasima A.S., or BOTAŞ, under a gas supply agreement with a term ending in 2014 (but which may be extended to 2019 subject to availability of natural gas). As a result of the recent liberalization of the natural gas market in Turkey, Trakya would be able to purchase natural gas from other sellers of natural gas, subject to availability, if BOTAŞ does not make natural gas available after 2014. In the case of supply disruptions of natural gas, Trakya’s ability to operate using diesel may be limited by its current inventory of diesel and/or by working capital constraints.

Elektrocieplownia Nowa Sarzyna Sp. z.o.o. (ENS)

ENS is a combined-cycle natural gas fired power co-generation plant with a nominal electrical capacity of 116 MW and nominal thermal capacity of 70 MW. The power plant is located in Nowa Sarzyna, Poland, approximately 180 miles south of Warsaw. The power plant consists of two GE 6B combustion turbine generators, two Deutsche Babcock Energia y Media heat recovery system generators, five Hocon Kesselbau HKB Venlo boilers and one GHH Borsig Turbomaschinen Gmbh steam turbine generator. The power plant commenced commercial operations in 2000. We own 100.00% of ENS.

The Polish government has been working on restructuring the Polish electric energy market since the beginning of 2000 in an effort to introduce a competitive market in compliance with European Union legislation. In 2007, legislation was passed in Poland that allowed for power generators producing under long term contracts to voluntarily terminate their contracts subject to payment of compensation for stranded costs. ENS sent notice of its termination of its long-term PPA in December 2007, with such termination being effective as of April 1, 2008. The compensation system consists of stranded costs compensation, based upon the capital expenditures incurred before May 1, 2004 that could not be recovered from future sales in the free market, and additional natural gas costs compensation. Both will be paid in quarterly installments of varying amounts. ENS’s revenue is derived from the stranded costs compensation and natural gas costs compensation, which both started in August 2008 and through which ENS received $18 million in 2008 and $50 million in 2009. The maximum remaining compensation, for stranded costs and natural gas costs, attributable to ENS is 922 million Polish zloty (approximately US$324 million based on the exchange rate as of December 31, 2009). In order to effect the delivery of the capacity and energy of the power plant in 2008, ENS entered into a new power delivery agreement with Mercuria Energy Trading Sp. z.o.o., a private company owned by Mercuria Energy Group Ltd. with a term ending in December 2010. Should neither party terminate it, this agreement will be automatically extended for an additional three full calendar years.

Additionally, ENS sells 90% of its steam under a long-term thermal energy supply agreement to Zaklady Chemiczne Organika-Sarzyna S.A., a private company owned by Ciech S.A. under a thermal energy supply agreement with a term ending in 2020. Capacity payments under this agreement are expressed and paid in Polish zlotys, but indexed to the U.S. dollar. The remaining 10% is sold to the city of Nowa Sarzyna under a medium-term thermal energy supply agreement with a term ending in November 2010.

Natural gas is the power plant’s primary fuel source and is provided by Polskie Górnictwo Naftowe i Gazownictwo, the Polish state-owned oil and gas monopoly, under a fuel supply agreement with a term ending in 2019. The dispatch for power plants in Poland is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched.

DHA Cogen Limited (DCL)

DCL is a combined-cycle natural gas-fired power generation plant with a nominal capacity of 94 MW. The power plant is located in Karachi, Pakistan. The power plant consists of one Siemens V64.3A combustion turbine generator, one Hitachi Babcock heat recovery system generator, one Siemens steam turbine generator and a water desalination plant with the capacity to process three million gallons of water per day. The power plant commenced commercial operations in 2008. We own 60.23% of DCL. The remaining ownership interest is owned by Pakistan Defence Officers Housing Authority, Faysal Bank, Optima Trading and other smaller investors.

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In September 2008, DCL shut down the plant on the recommendation of Siemens due to vibrations. Siemens identified the root cause of the problem as an existing defect in the gas turbine. Due to the shut down, DCL did not generate revenues and positive cash flow to pay vendors, which delayed the repairs. On June 17, 2009, DCL entered into loan agreements to finance repairs to the plant. These repairs were completed, and the plant became operational, in October 2009. In early November 2009, due to a sudden and drastic frequency drop in the grid which overloaded the DCL generator, DCL’s turbine tripped on surge protection and the plant was shut down for repairs. The repairs have been completed, and DCL resumed commercial operations in February 2010.

Initially DCL’s revenue was primarily derived from selling 94 MW of the capacity and energy produced by the power plant to Karachi Electric Supply Company, or KESC, a private power company, under a PPA with a term ending in 2038. However, KESC terminated the PPA on April 23, 2009. Subsequently, the parties arrived at an interim PPA arrangement which terminates in May 2010 for 71 MW of energy and capacity. DCL is in discussions with KESC with respect to a new PPA. Additionally, DCL sells approximately three million gallons per day of water produced by the power plant to Cantonment Board Clifton, or CBC, under a water-purchase agreement with a term ending in 2038. The tariffs under the water-purchase agreement with CBC are based on a structure with a fixed tariff escalated by 5% per year.

Natural Gas is the power plant’s primary fuel source and is provided by Sui Southern Gas Company Ltd., or SSGC, under a fuel supply agreement with a term ending in 2038. Although the fuel supply agreement has a term ending in 2038, the fuel supply agreement guarantees natural gas only through 2015, after which quantities are subject to availability in SSGC’s sole determination. The dispatch for power plants in Pakistan is based on a marginal cost and merit-based system with the most efficient power plants being the first to be dispatched.

Due to the extended shutdown, DCL is experiencing financial difficulties, and several of its lenders have filed claims against DCL. If DCL is unable to enter into an acceptable PPA, the operations of DCL may be materially adversely affected or the lenders may exercise their right to take ownership of the plant, in either event with a corresponding negative impact on our financial performance and cash flows. However, we do not believe that this would have a material adverse effect on our business as a whole.

Power Generation Growth

We are actively involved in several development projects in this segment. These are long-term projects involving siting, permitting, sourcing, marketing, constructing, financing and ultimately operating activities. Our greenfield development activities in power generation are focused in the markets where we currently operate, including opportunities that are advancing in Guatemala, Peru and Chile, namely Jaguar, Fenix and our joint development project with Pattern Energy, or Pattern, for the El Arrayán project, all described below.

Jaguar Energy Guatemala LLC (Jaguar)

The Jaguar project consists of the development, construction, operation and maintenance of a 300 MW (approximately 275 MW net capacity) solid fuel-fired power generation facility to be located approximately 15 miles from Puerto Quetzal, Guatemala. The project includes two identical 150 MW power blocks and will use circulated fluidized bed, or CFB, boiler technology. Jaguar entered into two 15-year PPAs in 2008 with Union Fenosa’s local distribution companies Distribuidora de Electricidad de Occidente S.A. and Distribuidora de Electricidad de Oriente, S.A. to supply a total of 200 MW of capacity and associated energy. The remaining 75 MW of capacity and associated energy are expected to be sold in the Guatemalan and regional wholesale power markets. The project has executed a lump-sum, fixed-price, date-certain turnkey engineering, procurement and construction contract, or EPC, with China Machine New Energy Corporation. In March 2010, Jaguar entered into a $350 million 10-year construction and term loan with a syndicate of regional and international banks led by Banca de Inversion BanColombia Corporación Financiera, S.A. and the Central American Bank of Economic Integration and issued a notice to commence to China Machine New Energy Corporation. Funding under the facility is subject to the satisfaction of various conditions, including a minimum equity contribution and the issuance of a parent guarantee by AEI. AEI has no direct obligations under the facility until the guarantee is signed and funding under the facility commences. Jaguar also has the ability to cancel the facility commitment at any time prior to the satisfaction of these conditions and the drawing of funds. We anticipate commencing commercial operations in 2013.

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Fenix Power Peru S.A. (Fenix)

The Fenix project consists of the development, construction, operation and maintenance of a nominal 530 MW combined-cycle natural gas-fired power generation facility to be located approximately 40 miles south of Lima, Peru. In June 2008, we purchased an 85% interest in the project from a privately-held group based in Panama, which remains a minority shareholder, holding a 15% interest. The project has purchased its primary power island equipment and has executed a purchase order for two new heat recovery steam generators. Fenix also has obtained the primary permits, including the environmental and generation permits, as well as a certificate of the non-existence of archeological remains, and anticipates selling 100% of its capacity and associated energy through a long-term PPA with its affiliate Luz del Sur. Subject to securing financing and completion of other project milestones, we anticipate commencing construction in the first half of 2010 and commercial operations in the second half of 2012.

Pattern Energy Joint Development

In November 2009, we signed a Joint Development Agreement, or JDA, with Pattern, setting forth the basis upon which our company and Pattern will develop wind projects in Brazil, Argentina and Chile. Upon signing the JDA, we also purchased from Pattern a 75% interest in its project, Parque Eólico Bahía Blanca, or Bahía Blanca, an approximately 50 MW wind project near the port city of Bahía Blanca in Buenos Aires Province. The project has completed more than one year of wind measurements collected from three meteorological towers located on the site. AEI and Pattern continue to explore development opportunities for the project.

In January 2010, we bought from Pattern a 55% interest in its project, Parque Eólico El Arrayán, or El Arrayán, an approximately 100 MW wind project in the Fourth Region of Chile. The project has completed more than one year of wind measurements collected from six meteorological towers located on the site. All rights of way have been secured. The environmental impact study was submitted in September 2009, and its approval is expected in 2010. We are currently in the process of selecting the turbine supplier, EPC contractor, financial advisor and other key third-party contractors and consultants. Pursuant to the terms of Annex II to the JDA, we have appointed the CEO of the project, and Pattern has appointed the Lead Development Officer. Commercial operations are expected to commence by the fourth quarter of 2011.

Natural Gas Transportation and Services

Our Natural Gas Transportation and Services businesses sell natural gas transportation capacity and related services to oil and gas producers, natural gas distribution companies and other large off-takers. Most of the businesses in this segment operate either through regulated concessions or long-term contracts, include tariffs that are periodically reviewed by regulators or adjusted in accordance with the contracts and are designed to provide for a pass-through to customers of the main noncontrollable cost items, recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on their respective regulated asset base.

For the year ended December 31, 2009, the Natural Gas Transportation and Services segment accounted for 4% of our operating income and 13% of our adjusted EBITDA.

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The table below provides a summary of our Natural Gas Transportation and Services segment stand-alone commercial and operational information as of and for the dates indicated:


					Network		Avg.	Capacity
		Commercial	Ownership	Operating	Length	Capacity	Throughput	Contracted	Concession	Regulated			Next Tariff
	Location	Operations	(%)	Control	(miles)	(mmcfd)	(mmcfd)	(%)	Termination	Return⁽¹⁾			Review
Andean
Promigas — Promigas Pipeline	Colombia	1974	52.13%	Yes ⁽²⁾	1,271	545	359	100%	2026		12.96-16.94	%	2010 (every 5 years)
Promigas — Centragas	Colombia	1996	13.03%	Yes ⁽²⁾	458	200	172	N/A	2011		N/A			N/A
Promigas — Transmetano	Colombia	1993	50.65%	Yes ⁽²⁾	93	73	34	92%	2044		12.56-16.56	%	2010 (every 5 years)
Promigas — Transoccidente	Colombia	1998	35.89%	Yes ⁽²⁾	7	69	35	42%	N/A		13.04-17.00	%	2010 (every 5 years)
Promigas — GBS	Colombia	1999	49.54%	Yes ⁽²⁾	196	62	10	N/A	2009		N/A			N/A
Promigas — Transoriente	Colombia	1994	15.31%	No	98	50	12	30%	2045		13.47-17.41	%	2010 (every 5 years)
Promigas — PSI	Colombia	2003	50.52%	Yes ⁽²⁾	N/A	N/A	313	N/A	N/A		N/A			N/A
Accroven	Venezuela	2001	49.25%	Joint control	N/A	800	780	100%	N/A		N/A			N/A

Southern Cone
Bolivia to Brazil — TBG	Brazil	1999	8.27%	No	1,611	1,063	773	100%	N/A		N/A			N/A
Bolivia to Brazil — GTB	Bolivia	1999	34.65%	No	346	1,063	785	100%	2037		N/A			N/A
Cuiabá — GOB	Bolivia	2002	100%	Yes	225	141	N/A	N/A	2039		N/A			N/A
Cuiabá — GOM	Brazil	2002	100%	Yes	175	120	N/A	N/A	Indefinite		N/A			N/A
Cuiabá — TBS	Bolivia	1999	100%	Yes	N/A	N/A	N/A	N/A	N/A		N/A			N/A
Emgasud	Argentina	1992⁽³⁾	42.73%	No	440	32	23⁽⁴⁾	100%	N/A		N/A			N/A


(1)		Inflation adjusted on a regulated asset base before tax.

(2)		AEI has operating control through Promigas.

(3)		Natural gas transportation operations began in 2007.

(4)		Emgasud, through its subsidiary Enersud Energy S.A., or Enersud, also bought and sold to third parties on average 7 mmcfd of natural gas.

Andean Natural Gas Transportation and Services

Promigas S.A., ESP (Promigas)

Promigas S.A. ESP is a Colombian energy company with investments primarily in Natural Gas Transportation and Services and Natural Gas Distribution. Although the subsidiaries of Promigas are stand-alone legal entities with their own management teams, Promigas provides financial, commercial, administrative, legal and regulatory support as well as operates and maintains many of the operations of such subsidiaries. We own 52.13% of Promigas. The remaining ownership interest is owned by local Colombian investors. Promigas is a public company and is traded on the Colombian Stock Exchange with negligible liquidity under the symbol “PROMIG:CB.” Below is a summary of Promigas’ Natural Gas Transportation and Services businesses. Promigas’ investments in natural gas distribution businesses are described in “— Natural Gas Distribution”. Our Retail Fuel business was until July 2009 a subsidiary of Promigas, at which time it was spun off and is now an indirect subsidiary of AEI.

Promigas Pipeline

The Promigas Pipeline is a 1,271 mile natural gas pipeline with a capacity of 545 mmcfd which transports natural gas from fields in the region of La Guajira to the Jobo terminal station in the Department of Sucre. The Promigas Pipeline also provides subcontracted pipeline design, construction, operation and maintenance services for government and/or third-party-owned natural gas transportation customers who own pipelines. Promigas owns 100% of Promigas Pipeline.

The Promigas Pipeline holds an exclusive long-term renewable concession from the Colombian Ministry of Mines and Energy, or the Colombian MME. Promigas Pipeline’s concession agreement, the first term of which expires in 2026, provides for exclusive transportation rights within the concession area. The Colombian government has the option to buy the assets at a to-be-determined fair value price in 2025. Otherwise, the concession contemplates extensions in 20-year increments. Since 1994, concessions have not been required to operate new pipelines in Colombia.

Transportation tariffs for Colombian natural gas transportation companies are reviewed by the Colombian Regulatory Commission for Energy and Gas (Comisión de Regulación de Energía y Gas), or CREG. The Promigas Pipeline has tariff reviews every five years, and its last review was in 2002. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items, recovery of efficient operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted annually for inflation of controllable costs and to pass-through adjustments to noncontrollable costs. There are two basic tariffs: a tariff for firm capacity and a tariff for interruptible capacity. The capacity contracted is either take-or-pay (for generators only) or under a fixed/variable arrangement, whereby the tariff is typically 90% fixed/10% variable for industrial, CNG and distribution companies and 50% fixed/50% variable for the thermoelectric generators. The average length of these contracts is currently one to two years, and the expectation is that these contracts are generally renewed. The current tariff structure in place minimizes the sensitivity of revenues to volume transported because the majority of the revenue comes from the fixed component of the tariffs, which provides for savings achieved through cost management and efficiency to boost returns (which may be partially lost at the next tariff review).

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As the tariff for the Promigas Pipeline was last set in 2002, the current tariff has expired. The new tariffs are expected to be applied in 2010. The Promigas Pipeline is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for U.S. dollar-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of general and administrative expenses and operation and maintenance expenses, or G&A and O&M), according to the methodology established by CREG.

Promigas — Centragas (Centragas)

Centragas is a 458 mile natural gas pipeline with a capacity of 200 mmcfd which transports natural gas from Ballena to the city gate in Barrancabermeja in the Department of Santander. The natural gas transported comes from La Guajira gas field. Promigas owns 25.00% of Centragas. Centragas operates under a build, operate, maintain and transfer, or BOMT, agreement with Transportadora de Gas del Interior, or TGI, which expires in February 2011. Under the terms of the BOMT agreement, ownership of the pipeline reverts to TGI at the end of the term. Under the terms of the BOMT agreement, Centragas is paid by TGI a certain tariff, independent of volumes transported. Centragas’ tariff is set by the terms of its BOMT agreement and is not regulated by CREG. Additionally Promigas operates the Centragas pipeline under a long-term operations and maintenance contract with Centragas. The term of the contract is through the transfer of the pipeline to TGI in February 2011.

Promigas — Transmetano S.A. ESP (Transmetano)

Transmetano is a 93 mile natural gas pipeline with a capacity of 73 mmcfd which transports natural gas from Sebastopol to the city gate in Medellín in the Department of Antioquia. The natural gas transported comes from La Guajira gas field. Promigas owns 94.99% of Transmetano.

Transmetano holds an exclusive long-term renewable concession from the Colombian MME. Transmetano’s concession agreement, the first term of which expires in 2044, provides for exclusive transportation rights within the concession area. The Colombian government has the option to buy the assets at a to-be-determined fair value price in 2043. Otherwise, the concession contemplates extensions in 20-year increments. Since 1994, concessions have not been required to operate new pipelines in Colombia.

Tariffs for Transmetano are determined as was described for the Promigas Pipeline. As the tariff for Transmetano was last set in 2001, the current tariff has expired. The new tariffs are expected to be applied in 2010. Transmetano is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for U.S. dollar-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by CREG.

Ecopetrol S.A., or Ecopetrol, the Colombian state-controlled petroleum company, is currently Transmetano’s sole customer under a Transportation Contract which expires in 2012. At the end of the term, Ecopetrol has an option to renew the contract for ten successive one-year terms. Independent of volumes transported, Ecopetrol pays a tariff established by the contract. If the tariff to be approved by CREG differs from the one in Ecopetrol’s contract, Transmetano will assume any discount, as applicable.

Promigas — Transoccidente S.A. ESP (Transoccidente)

Transoccidente is a seven mile natural gas pipeline with a capacity of 69 mmcfd which transports natural gas from Yumbo to the city gate in Cali in the Department of Valle del Cauca. The natural gas transported comes from the Llanos Orientales gas field. Promigas owns 68.86% of Transoccidente. Transoccidente was established in 1998 as a result of a spin-off overseen by CREG. Because of the spin-off and because it began to operate after the public services law was issued in 1994, Transoccidente does not have a concession agreement for its operation.

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Tariffs for Transoccidente are determined as was described for the Promigas Pipeline. As the tariff for Transoccidente was last set in 2004, the current tariff has expired. The new tariffs are expected to be applied in 2010. Transoccidente is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for U.S. dollar-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by CREG.

Promigas — Gases de Boyacá y Santander, GBS S.A. (GBS)

GBS is a 196 mile natural gas pipeline with a capacity of 62 mmcfd which transports natural gas from the Cusiana — La Ballez pipeline to the city gates of Olero Santana and Teatinos Belencito in the Departments of Boyacá and Santander. The natural gas transported comes from the Llanos Orientales gas field. Promigas owned 93.87% of GBS. GBS operated under BOMT agreement with Empresa Colombiana de Gas which expired in October 2009. Under the terms of the BOMT agreement, ownership of the pipeline reverted to TGI with no payment made to us.

Promigas — Transoriente S.A. ESP (Transoriente)

Transoriente is a 98 mile natural gas pipeline with a capacity of 50 mmcfd which transports natural gas from Barrancabermeja to the city gate in Payao in the Department of Santander. The natural gas transported comes from the La Guajira gas field. In addition to the existing pipeline, Transoriente is currently developing the Gibralter pipeline, an approximately 100 mile gas pipeline from the Gibralter gas field to Bucaramanga. All regulatory approvals for this project have been obtained. Promigas owns 20% of Transoriente.

Transoriente holds an exclusive long-term renewable concession from the Colombian MME. Transoriente’s concession agreement, the first term of which expires in 2045, provides for exclusive transportation rights within the concession area. The Colombian government has the option to buy the assets at a to-be-determined fair value price in 2044. Otherwise, the concession contemplates extensions in 20-year increments. Since 1994, concessions have not been required to operate new pipelines in Colombia.

Tariffs for Transoriente are determined as was described for the Promigas Pipeline. As the tariff for Transoriente was last set in 2001, the current tariff has expired. The new tariffs are expected to be applied in 2010. Transoriente is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for U.S. dollar-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by CREG.

Promigas — Promigas Servicios Integrados S.A. (PSI)

PSI provides services related to the dehydration and compression of natural gas at the Ballena station in Colombia. Promigas owns 94.22% of PSI. PSI dehydrates and compresses natural gas in the La Guajira fields for its sole customer, Chevron Texaco. The dehydration contract with Chevron Texaco expires on December 31, 2011. The compression contract expires on December 31, 2013. In addition, PSI has also entered into a backup compression contract with Chevron Texaco which expires on December 31, 2013. As of December 31, 2009, PSI dehydrated an average of 313 mmcfd of natural gas and compressed natural gas.

Accroven S.R.L. (Accroven)

Accroven is a natural gas liquids, or NGL, extraction, fractionation and storage and refrigeration project located in Venezuela. Accroven’s NGL extraction facilities are located at the San Joaquín and Santa Bárbara gas fields, and the NGL fractionation, storage and refrigeration facilities are located in the Jose petrochemical complex on Venezuela’s northeastern coast. PDVSA Gas, a wholly owned subsidiary of the Venezuelan government-owned PDVSA, is Accroven’s sole customer, under contracts primarily denominated in U.S. dollars with a term ending in 2021. The project commenced commercial operations in 2001. We own 49.25% of Accroven. The remaining ownership interest is owned by Williams Companies and by small international investors.

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Currently, PDVSA Gas payments are delayed and such delays constitute an event of default under certain of Accroven’s finance agreements. To date Accroven has not been notified by its lenders of the acceleration of its obligations under its financing agreements. The amount owed by PDVSA Gas is approximately $73.9 million as of December 31, 2009. This delay in payment has resulted in PDVSA Gas being in default under its service agreements with Accroven. Accroven is entitled to enforce its rights under those agreements, which include terminating the agreements, but is currently trying to resolve the situation through other means. In September 2009, we signed a non-binding Letter of Intent with PDVSA Gas pursuant to which we agreed to transfer our interest in Accroven to PDVSA Gas. This Letter of Intent has expired. However, negotiations are continuing, and we expect to close this transaction during the first half of 2010.

Southern Cone Natural Gas Transportation and Services

Bolivia-to-Brazil Pipeline (BBPL)

BBPL is a 1,957 mile pipeline which transports natural gas from Bolivia to Brazil. The pipeline is owned by two companies: GTB and TBG. Our ownership in these companies and further details about the pipelines are described below.

Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (TBG)

TBG is a 1,611 mile natural gas pipeline with a capacity of 1,063 mmcfd which transports natural gas from the Station Mutún interconnection with the GTB pipeline at the Bolivian border to southeastern Brazil (Brazilian portion of the BBPL). We own 8.27% of TBG. The remaining ownership is held by Petrobras, BBPP Holding Ltda. and Transredes.

TBG holds an indefinite authorization granted by the Brazilian National Petroleum Agency (Agência Nacional do Petróleo) in 1999, which provides for exclusive transportation rights within the concession area. Petrobras, the Brazilian state-owned oil and gas company, accounts for approximately 97% of TBG’s volume transported and British Gas plc, or British Gas, accounts for the remainder. TBG’s customers sell the transported natural gas to local distribution companies, which resell natural gas to power generating plants, industrial, commercial and residential users. TBG’s contracts with Petrobras are U.S.-dollar based “ship-or-pay” contracts.

Gas Transboliviano S.A. (GTB)

GTB is a 346 mile natural gas pipeline with a capacity of 1,063 mmcfd which transports natural gas from Station Rio Grande to Station Mutun in Bolivia, which is located at the Brazilian border (Bolivian portion of the BBPL), where it interconnects to TBG, the Brazilian portion of the BBPL. We own 34.65% of GTB. The remaining ownership interest is owned by Transredes, Petrobras, British Gas and El Paso.

GTB holds an exclusive long-term renewable concession from the Bolivian Hydrocarbons Superintendency. GTB’s concession agreement provides for exclusive transportation rights within the concession area and expires in 2037. The majority of GTB’s revenues come from YPFB, the Bolivian state-owned oil and gas company, under its current long-term contracts for firm capacity and gas transportation services. All tariff charges associated with the gas transported by GTB under its transportation agreements with YPFB for servicing Petrobras are paid for directly by Petrobras, under direct payment agreements with GTB. The YPFB contracts account for 1.1 Bcf/d of the approximately 1.2 Bcf/d of capacity currently available on the GTB pipeline. GTB’s contracts with Petrobras and YPFB are “ship-or-pay” contracts that require Petrobras to pay substantially all of the amounts due under the contracts as capacity payments regardless of whether YPFB and Petrobras actually ship gas through the pipeline. Petrobras and YPFB have preferred treatment on the GTB pipeline relative to other shippers. GTB’s contracts with YPFB are U.S. dollar-based “ship-or-pay” contracts.

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Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS)

Cuiabá Integrated Project consists of four companies that on an integrated basis own and operate a power plant in Brazil, purchase natural gas in Bolivia and transport it through pipelines to Brazil for use as fuel for the power plant. See also “— Power Generation — Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE).” The four companies are EPE, TBS, GOB and GOM. GOM is a 175 mile natural gas pipeline with a capacity of 120 mmcfd and interconnected to the GOB pipeline at the Bolivia-Brazil border which is a 225 mile natural gas pipeline with a capacity of 141 mmcfd which transports natural gas from the border to EPE. TBS is a natural gas shipper that purchases natural gas, arranges for transportation of the natural gas, including through GOB and GOM, and sells the natural gas to EPE. We own 100% of GOM, GOB and TBS. GOM, GOB and TBS have generally not operated since August 2007 due to lack of natural gas supply.

Emgasud S.A. (Emgasud)

Emgasud has a license through 2042 to use the Patagonian Pipeline, a 354 mile natural gas pipeline with a capacity of 26.1 mmcfd which transports natural gas from fields in the region of Cerro Dragon in the Province of Chubut to the delivery point in the city of Esquiel. Emgasud has contracted a total of 24.6 mmcfd of natural gas firm capacity with Camuzzi Gas del Sur S.A. until 2027. Emgasud, through its subsidiary Enersud, has also been assigned transportation capacity of approximately 5.8 mmcfd through the San Martin Pipeline of the Transportadora de Gas del Sur S.A., or TGS, system with the right to sell gas until 2042. Emgasud has sold such capacity under dollar-denominated ship or pay contracts for a 15-year term with several industrial customers. In 2009, Emgasud had total natural gas transportation volume of 23.2 mmcfd, plus an additional 7.1 mmcfd of gas commercialization activities for third parties and related parties.

Natural Gas Distribution

Our Natural Gas Distribution businesses distribute and sell natural gas primarily to residential, industrial and commercial customers. Most of the businesses in this segment operate in a designated service area defined in a concession agreement. All of the concession agreements and/or associated regulations include tariffs that are periodically reviewed by regulators and are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly natural gas purchases), recovery of reasonable operating and administrative costs, incentives to continue to reduce costs and make needed capital investments and a regulated rate of return. Most of these concession agreements are structured to minimize our exposure to fluctuations in commodity prices.

For the year ended December 31, 2009, the Natural Gas Distribution segment accounted for 17% of our operating income and 13% of our adjusted EBITDA.

The table below provides a summary of our Natural Gas Distribution segment stand-alone commercial and operational information as of and for the dates indicated:


								Network				Avg.
		Commercial		Ownership			Operating	Length		Customers		Throughput		Concession			Regulated			Next Tariff
	Location	Operations		(%)			Control	(miles)		(000s)		(mmcfd)		Termination			Return			Review
Andean
Promigas — Gases del Caribe	Colombia		1966		16.16	%	No		8,845		986		114		2028	⁽¹⁾		16.06	%	2011 (every 5 years)
Promigas — Gases de Occidente	Colombia		1992		46.87	%	Yes ⁽²⁾		4,398		673		50		2014, 2047	⁽³⁾		16.06	%	2011 (every 5 years)
Promigas — Surtigas	Colombia		1968		51.57	%	Yes ⁽²⁾		5,083		466		48		2034	⁽⁴⁾		16.06	%	2011 (every 5 years)
Cálidda	Peru		2004		80.85	%	Yes		559		19		164		2033	⁽⁵⁾		12.00	% ⁽⁶⁾	2013 (every 2-4 years)

Southern Cone
Emgasud	Argentina		1992		42.73	%	No		507		26		7		2027			N/A			N/A

China
Huatong — BMG	China		1988		70.00	%	Yes		1,015		162		13		2038-2058	⁽⁷⁾		N/A		Annually
Huatong — Tongda	China		1998		100.00	%	Yes		1,425		174		7		2038-2058	⁽⁷⁾		N/A		Annually


(1)		Gases del Caribe’s concession is extendable for 20 additional years.

(2)		AEI has operating control through its control of Promigas.

(3)		Gases de Occidente has an exclusive concession which expires in 2014 and a non-exclusive concession which expires in 2047.

(4)		Surtigas’ concession is extendable for 20 additional years.

(5)		Cálidda’s concession is extendable for 60 years in 30-year increments.

(6)		Cálidda tariff is currently under review.

(7)		Varies by franchise.

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Andean Natural Gas Distribution

Promigas

Promigas is a Colombian energy company with investments primarily in Natural Gas Transportation and Services and Natural Gas Distribution. Below is a summary of Promigas’ Natural Gas Distribution businesses. See “— Natural Gas Transportation and Services — Promigas S.A., ESP (Promigas)” for a description of Promigas’ Natural Gas Transportation and Services businesses.

Promigas owns interests in three natural gas distribution businesses (Gases del Caribe, Gases de Occidente and Surtigas) which serve more than two million customers throughout Colombia. Each natural gas distribution company has limited competition in its area and competes only with alternative energy sources.

Each of Gases del Caribe, Gases de Occidente and Surtigas also provide ancillary non-bank financing to customers with good payment records to finance items such as appliances, household items, CNG car conversions and materials for construction. The financing is provided directly by each company as part of its non-regulated business. In the case of Gases del Caribe, Promigas provides the financing and Gases del Caribe receives a fee. Total non-bank financing loans receivable as of December 31, 2009 are $77.4 million. The loans are unregulated and cannot exceed the usury rate.

Promigas — Gases del Caribe S.A. E.S.P. (Gases del Caribe)

Gases del Caribe supplies natural gas to a service area with a population of approximately 7.0 million that encompasses approximately 32,000 square miles in the area of Magdalena, Cesar and Atlántico, located on Colombia’s north coast and indirectly in the area of La Guajira, Quindio, Risaralda and Caldas. As of December 31, 2009, Gases del Caribe had approximately 986,000 customers and distributed approximately 114 mmcfd of natural gas in 2009. Promigas owns 30.99% of Gases del Caribe.

Gases del Caribe holds an exclusive long-term renewable concession from the Colombian MME. Gases del Caribe’s concession agreement, the first term of which expires in 2028, provides for exclusive natural gas distribution rights within the concession area. Since 1994, a concession has no longer been required to distribute natural gas in Colombia.

Tariffs for Colombian natural gas distribution companies are reviewed by the CREG periodically. Gases del Caribe has tariff reviews every five years; its last review was in 2004. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items, recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted annually for inflation of controllable costs and to pass-through adjustments to noncontrollable costs.

As the tariff for Gases del Caribe was last set in 2004, the current tariff has expired. The new tariffs are expected to be applied in 2011. Gases del Caribe is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for U.S. dollar-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by CREG.

Natural gas distribution companies in Colombia are obligated to contract 100% of the volume for the regulated natural gas distribution market. Most of Gases del Caribe’s natural gas supply comes from La Guajira field (the price of natural gas from this field has a cap that is pegged to oil prices with a six-month lag).

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Promigas — Gases de Occidente S.A. E.S.P. (Gases de Occidente)

Gases de Occidente supplies natural gas to a service area with a population of approximately 5.5 million that encompasses approximately 20,000 square miles in the area of Valle del Cauca and in Cauca, located on Colombia’s west coast. As of December 31, 2009, Gases de Occidente had approximately 672,500 customers and distributed approximately 50 mmcfd of natural gas in 2009. Promigas owns 89.90% of Gases de Occidente.

Gases de Occidente holds an exclusive long-term renewable concession from the Colombian MME. Gases de Occidente’s concession agreement provides for exclusive natural gas distribution rights within the concession area until 2014, at which time the regulator will change from MME to CREG, and for non-exclusive gas distribution rights within the concession area until 2047. Since 1994, a concession has no longer been required to distribute natural gas in Colombia.

Tariffs for Gases de Occidente are determined as was described for Gases del Caribe. As the tariff for Gases de Occidente was last set in 2004, the current tariff has expired. The new tariffs are expected to be applied in 2011. Gases de Occidente is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for U.S. dollar-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the renumeration of G&A and O&M), according to the methodology established by CREG.

Natural gas distribution companies in Colombia are obligated to contract 100% of the volume for the regulated natural gas distribution market. Most of Gases de Occidente’s natural gas supply comes from the Cusiana field (the price of natural gas from this field is not capped).

Promigas — Surtigas S.A. E.S.P. (Surtigas)

Surtigas supplies natural gas to a service area with a population of approximately 4.0 million that encompasses approximately 24,000 square miles in the area of Bolívar, Sucre and Córdoba, located on Colombia’s north coast. As of December 31, 2009, Surtigas had approximately 466,000 customers and distributed approximately 48 mmcfd of natural gas in 2009. Promigas owns 98.92% of Surtigas.

Surtigas holds an exclusive long-term renewable concession from the Colombian MME. Surtigas’s concession agreement, the first term of which expires in 2034, provides for exclusive natural gas distribution rights within the concession area. The concession contemplates extensions in 20-year increments. Since 1994, concessions have not been required to distribute natural gas in Colombia.

Tariffs for Surtigas are determined as was described for Gases del Caribe. As the tariff for Surtigas was last set in 2004, the current tariff has expired. The new tariffs are expected to be applied in 2011. Surtigas is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for U.S. dollar-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by CREG.

Natural gas distribution companies in Colombia are obligated to contract 100% of the volume for the regulated natural gas distribution market. Most of Surtigas’ natural gas supply comes from La Guajira field (the price of natural gas from this field has a cap that is pegged to oil prices with a six-month lag).

Gas Natural de Lima y Callao S.A. (Cálidda)

Cálidda supplies natural gas to a service area with a population of approximately 9.0 million that encompasses approximately 14,000 square miles in the Department of Lima and the Province of Callao. As of December 31, 2009, Cálidda had approximately 19,000 customers and distributed 164 mmcfd of natural gas in 2009. We own 60% of Cálidda. The remaining ownership interest is owned by Promigas; therefore, we own directly and indirectly 80.85% of Cálidda.

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Cálidda holds an exclusive long-term renewable concession from the Peruvian Government. Cálidda’s concession agreement, the first term of which expires in 2033, provides for exclusive natural gas distribution rights within the concession area. The concession contemplates extensions in 30-year increments.

Tariffs for Peruvian natural gas distribution companies are reviewed by OSINERGMIN periodically. Cálidda has tariff reviews every four years, and its last review was in 2004. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items, recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on its regulated asset base. Tariffs are also adjusted annually for inflation of controllable costs and to pass-through adjustments to noncontrollable costs. Additionally, Cálidda also receives a guaranteed return on its main grid that is separate from the distribution tariffs and which was also set at the time of the concession.

New tariffs for Cálidda were approved by OSINERGMIN on February 28, 2010 and include the Other Network Tariffs and the Single Tariffs. Although the Single Tariffs is a new tariff system that integrates both the other network and main grid tariffs, these tariffs can only be applied after Cálidda’s concession contract is amended to reflect the new tariff system. In the meantime, Cálidda will apply the new Other Network Tariffs which have been effective since March 1, 2010. We expect the Single Tariffs to become effective on July 1, 2010, after we complete the negotiations with MEM to amend the concession contract.

In July 2004, Cálidda entered into a five-year contract with the Camisea Consortium, which operates, through a sub-contract with Pluspetrol Peru Corporation S.A., the Camisea gas field in Peru, for the supply of natural gas. This agreement can automatically be renewed for consecutive two-year periods through 2033. An amendment to the natural gas supply contract to adjust Cálidda’s future demand requirements and also to synchronize the supply and transportation contracts has been proposed by Cálidda to the Camisea Consortium (this amendment is still pending). Regarding the transmission contract, in August 2008, Cálidda increased the firm and interruptible transportation capacity with Transportadora de Gas del Perú S.A. through June 2012 and August 2033, respectively.

Southern Cone Natural Gas Distribution

Emgasud S.A. (Emgasud)

Emgasud is an Argentine energy company which primarily operates in power generation, but also operates in the natural gas transportation and services, natural gas distribution, natural gas pipeline construction and energy commercialization businesses. Emgasud is currently reviewing its non-power generation businesses. As a result of this review, Emgasud may consider the sale or discontinuation of these businesses. Emgasud supplies natural gas to a service area with a population of approximately 75,000 in Dolores, Pinamar and Santa Clara in Buenos Aires Province that encompasses approximately 785 square miles. As of December 31, 2009, Emgasud had approximately 26,000 customers and distributed 7.5 mmcfd of natural gas in 2009.

China Natural Gas Distribution

Huatong (Shanghai) Investment Co., Ltd. (Huatong)

In December 2009, we signed an agreement to acquire our partners’ 30% interest in Beijing MacroLink Gas Co., Ltd., or BMG. In connection with this transaction, we formed a new company, Huatong, which will hold and manage all of our natural gas distribution business in China going forward, including those businesses held in Tongda Energy Private Limited, or Tongda. Following the closing of this acquisition, we will own 95% of Huatong. The remaining ownership interest will be owned by our current partner in BMG, a local Chinese investor.

BMG and Tongda sell and distribute piped gas and operate auto-filling stations and LNG regasification stations in China. Each of the companies has pursued and developed new city gas businesses through franchise acquisitions and privatizations. As of December 31, 2009, BMG held controlling interests in 15 city gas companies and a minority interest in a long-distance pipeline and served a total of approximately 162,000 connected users out of a total of approximately 1.4 million connectable users. As of December 31, 2009, Tongda held controlling interests in ten city gas companies and minority interests in two long-distance pipelines, servicing a total of approximately 174,000 connected users out of a total of approximately 657,000 connectable users.

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BMG and Tongda’s subsidiaries have certain rights for city gas operations in municipalities in China (such rights take a variety of forms and are not always documented with a formal concession contract) relating to, among other things, their respective franchise area and duration. Each company has the right to build out its franchise area but is not obligated to do so.

Tariffs for Chinese natural gas distribution companies are periodically reviewed by the regulators within the service area that the concession is located. BMG and Tongda have tariff reviews periodically; however, such tariff reviews are currently not well defined, which results in distribution companies advocating adjustments on an ad hoc basis. Although not well defined, tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items, recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments, and a regulated rate of return on its regulated asset base. Tariffs are also adjusted periodically for inflation of controllable costs and to pass-through adjustments to noncontrollable costs.

Growth of Our Natural Gas Distribution Business

We are developing and expanding our gas distribution segment in Peru, China and Colombia through our Cálidda, Huatong and Promigas businesses, respectively. These companies and their subsidiaries service markets with low penetration rates and significant growth potential.

In the case of Cálidda, our company holding the exclusive gas distribution franchise for the Department of Lima, we are focusing on expanding its primary and secondary distribution networks in order to capture new industrial, commercial and residential customers. Lima has a substantial and readily available indigenous gas supply and a very low penetration rate. With approximately 1.4 million potential customers within our franchise, we hope to significantly grow over an extended period.

With respect to the Chinese gas franchises that we hold through Huatong, our focus is on cities in the interior of the country that are in the early stage of industrialization and urbanization. This follows the Chinese government’s initiative to promote and develop a new wave of growth away from the already relatively affluent and developed coastal areas. We believe that as the new industrial parks and commercial developments in our franchises further develop, we will be well positioned to capture significant growth opportunities. In addition to capturing new industrial and commercial clients that are currently building major manufacturing facilities and recreational centers, the urbanization and economic prosperity that comes along with such industrialization should enhance growth in our residential customer base. We are currently experiencing rapid growth in volumes and new customers in the markets served by both these companies and we expect this trend to continue.

With respect to Promigas, we are actively pursuing new franchises for virtual pipelines, whereby natural gas is transported using vehicles to connect cities that do not have gas pipelines connected to their gas infrastructure.

Retail Fuel

Our Retail Fuel businesses distribute and sell liquid fuels and CNG primarily to wholesale and retail customers. In addition to owning, licensing and operating retail outlets, these businesses own fleets of bulk-fuel distribution vehicles. The businesses in this segment operate in a combination of regulated and unregulated markets. Retail Fuel is a non-core business for us and we are currently exploring strategic alternatives with respect to this business.

For the year ended December 31, 2009, the Retail Fuel segment accounted for 19% of our operating income and 16% of our adjusted EBITDA.

The table below provides a summary of our Retail Fuel segment stand-alone commercial and operational information as of and for the dates indicated:

Commercial

Ownership

Operating

Product

Volume

Owned

Affiliate

Location

Operations

(%)

Control

Sold

Stations

Andean

Proenergía — Terpel

Colombia, Chile,

1968

24.40

Yes

Gasoline, Diesel,

4.7 mm gal/day

374

1,241

Ecuador, Panama

Jet Fuel,

Lubricants

Proenergía — Gazel

Colombia, Chile,

1986

24.40

Yes

Compressed Natural

34.9 mmcfd

246

N/A

Peru, Mexico

Gas

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Andean Retail Fuel

Proenergía Internacional S.A. (Proenergía)

Proenergía is a Colombian retail fuel company that operates through two businesses, Organización Terpel S.A., or Terpel, and Gas Natural Comprimido S.A., or Gazel, which cover the Terpel and Gazel brands, respectively. Terpel is a retail gasoline and petroleum lubricants distribution business operating in Colombia, Chile, Ecuador and Panama. As of December 31, 2009, Terpel had 374 owned and 1,241 affiliated service stations and sold on average 4.7 million gallons per day of products. Gazel is a retail CNG business operating primarily in Colombia, Chile, Mexico and Peru. As of December 31, 2009 Gazel had 246 service stations and sold on average 34.9 mmcfd of CNG per day in 2009. We own 52.13% of Proenergía, which in turn owns 52.66% of Sociedad de Inversiones en Energía, or SIE, which owns 88.89% of Terpel which in turn owns 100% of Gazel. The remaining interests in SIE and Terpel are owned by local Colombian investors. Our Retail Fuel business was a subsidiary of Promigas until July 2009, at which time it was spun off and is now an indirect subsidiary of AEI. Retail Fuel is a non-core business for us, and we are currently exploring strategic alternatives with respect to this business.

Tariffs for retail fuel companies in Colombia (which represents the majority of Terpel’s revenue) are reviewed by the Colombian MME periodically. Such review is not company-specific but rather country-wide whereby regulated prices are set for the various retail fuel products. Such regulated prices are typically indexed (with a lag) to international oil prices. The last review was implemented in July 2008. In the case of Gazel, CNG in Colombia (which represents the majority of Gazel’s revenue) is not regulated, but is priced to compete against gasoline which is regulated.

Environmental Considerations

Our businesses in the various emerging market countries in which we operate are subject to comprehensive national, state and municipal laws and regulations relating to the preservation and protection of the environment to which those businesses must adhere. These laws and regulations require most of our businesses to obtain permits or licenses which have to be renewed periodically in order to be allowed to continue to operate. If such permits or licenses lapse or are not renewed, or if we fail to obtain any required environmental licenses and permits, or if we do not comply with any other requirements or obligations established under the applicable environmental laws and regulations, we may be subject to fines, civil or criminal sanctions, and might face partial or total suspension of our operations and suspension or cancellation of environmental licenses and permits. In addition, our businesses which hold debt from banks, and multilateral lenders in particular, are typically required to adhere to environmental standards which exceed those of the country in which the business operates (e.g., adhere to World Bank standards).

We have environmental policies and procedures in place, which are based on the requirements of ISO 14001, governing our businesses and we regularly audit each business’ compliance with these policies, local laws and permit requirements managed directly by each business with oversight and audit through our operations, environmental, health and safety department. Many of our businesses have achieved ISO 14001 certifications, including Centragas, Corinto, EPE, Elektro, GBS, GOB, GOM, GTB, Promigas, Terpel, TBG and Trakya.

We are currently either in compliance with, have a waiver from or are in the process of applying for a permit that would put us in compliance with all applicable environmental laws and material environmental licenses and permits. Our operating businesses have the required environmental monitoring, equipment and procedures, and we utilize third-party contractors to conduct regular environmental audits. Our environmental expenses relate to our continuous control and monitoring policies, and we currently do not have any material future environmental liabilities related to our ongoing operations. However, as environmental regulations are expected to become more stringent in some of the countries we operate, including with respect to proposed climate change legislation, our environmental compliance costs are likely to increase due to the cost of compliance with any future environmental regulations. While at this time there are no known material environmental liabilities, there may be from time to time a requirement to replace underground and above ground fuel storage tanks which may require risk-based clean-up. Such future costs are not likely to be material.

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C. Organizational Structure

Our Segments and Businesses

The following summary tables set forth our ownership interests in the businesses comprising our segments as of December 31, 2009.


Business	Full Legal Name	Region — Country	AEI Ownership %⁽¹⁾
*Power Distribution*
Luz del Sur ⁽²⁾	Luz del Sur S.A.A.	Andean — Peru		37.97	%
Chilquinta	Chilquinta Energía S.A.	Andean — Chile		50.00	%
Elektro	Elektro Eletricidade e Serviços S.A.	Southern Cone — Brazil		99.68	%
EMDERSA	Empresa Distribuidora Eléctrica Regional S.A.	Southern Cone — Argentina		77.10	%
EDEN ⁽³⁾	Empresa Distribuidora de Energía Norte S.A.	Southern Cone — Argentina		90.00	%
Elektra	Elektra Noreste, S.A.	Central America/Caribbean -Panama		51.00	%
Delsur	Distribuidora de Electricidad Del Sur, S.A. de C.V.	Central America/Caribbean -El Salvador		86.41	%

*Power Generation*
EPE	Empresa Produtora de Energia Ltda. (Cuiabá Integrated Project)	Southern Cone — Brazil		100.00	%
Emgasud	Emgasud S.A.	Southern Cone — Argentina		42.73	%
PQP	Puerto Quetzal Power LLC	Central America/Caribbean -Guatemala		100.00	%
San Felipe	Generadora San Felipe Limited Partnership	Central America/Caribbean -Dominican Republic		100.00	%
Corinto	Empresa Energética Corinto Ltd.	Central America/Caribbean -Nicaragua		57.67	%
JPPC	Jamaica Private Power Company Ltd.	Jamaica		84.42	%
Tipitapa	Tipitapa Power Company Ltd.	Central America/Caribbean -Nicaragua		57.67	%
Amayo	Consorcio Eólico Amayo S.A.	Central America/Caribbean -Nicaragua		13.42	%
Luoyang	Luoyang Sunshine Cogeneration Co., Ltd.	China — China		50.00	%
Trakya	Trakya Elektrik Uretim ve Ticaret A.S.	Europe/Middle East/North Africa — Turkey		90.00	%
ENS	Elektrocieplownia Nowa Sarzyna Sp. Z o.o.	Europe/Middle East/North Africa — Poland		100.00	%
DCL	DHA Cogen Limited	Europe/Middle East/North Africa — Pakistan		60.23	%

*Natural Gas Transportation and Services*
Promigas Pipeline	Promigas Pipeline (Promigas S.A., ESP)	Andean — Colombia		52.13	%
Centragas	Centragas (Promigas S.A., ESP)	Andean — Colombia		13.03	%
Transmetano	Transmetano S.A. ESP (Promigas S.A., ESP)	Andean — Colombia		50.65	%
Transoccidente	Transoccidente S.A. ESP (Promigas S.A., ESP)	Andean — Colombia		35.89	%
GBS	Gases de Boyacá y Santander, GBS S.A. (Promigas S.A., ESP)	Andean — Colombia		49.54	%
Transoriente	Transoriente S.A. ESP (Promigas S.A., ESP)	Andean — Colombia		15.31	%
PSI	Promigas Servicios Integrados S.A. (Promigas S.A., ESP)	Andean — Colombia		50.52	%
Accroven	Accroven S.R.L.	Andean — Venezuela		49.25	%
TBG	Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (Bolivia-to-Brazil Pipeline)	Southern Cone — Brazil		8.27	%
GTB	Gas Transboliviano S.A. (Bolivia-to-Brazil Pipeline)	Southern Cone — Bolivia		34.65	%
GOB	GasOriente Boliviano Ltda. (Cuiabá Integrated Project)	Southern Cone — Bolivia		100.00	%
GOM	GasOcidente do Mato Grosso Ltda. (Cuiabá Integrated Project)	Southern Cone — Brazil		100.00	%
TBS	Transborder Gas Services Ltd. (Cuiabá Integrated Project)	Southern Cone — Brazil		100.00	%
Emgasud	Emgasud S.A.	Southern Cone — Argentina		42.73	%

*Natural Gas Distribution*
Gases del Caribe	Gases del Caribe S.A. E.S.P. (Promigas S.A., ESP)	Andean — Colombia		16.16	%

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Business	Full Legal Name	Region — Country	AEI Ownership %⁽¹⁾
Gases de Occidente	Gases de Occidente S.A. E.S.P. (Promigas S.A., ESP)	Andean — Colombia		46.87	%
Surtigas	Surtigas S.A. E.S.P. (Promigas S.A., ESP)	Andean — Colombia		51.57	%
Cálidda	Gas Natural de Lima y Callao S.A.	Andean — Peru		80.85	%
Emgasud	Emgasud S.A.	Southern Cone — Argentina		42.73	%
Huatong — BMG	Beijing Macrolink Gas Co., Ltd	China — China		70.00	%
Huatong — Tongda	Tongda Energy Private Limited	China — China		100.00	%

*Retail Fuel*
Proenergía — Terpel	Organización Terpel Inversiones S.A. (Proenergía Internacional S.A.)	Andean — Colombia, Chile, Ecuador and Panama		24.40	%
Proenergía — Gazel	Gas Natural Comprimido S.A. (Proenergía Internacional S.A.)	Andean — Colombia, Chile, Mexico and Peru		24.40	%


(1)		Represents AEI’s net interest via direct and indirect ownerships.

(2)		In May 2008, we acquired an additional 0.03% of Luz del Sur in a public tender. We currently own 37.97% of Luz del Sur. Our stake in Luz del Sur is owned indirectly through our 50.00% ownership of its holding company, Peruvian Opportunity Company SAC, or POC.

(3)		We acquired our 90.00% interest in EDEN in 2007. The transaction is subject to local anti-trust approval.

D. Property, Plant and Equipment

Properties by each business segment are presented below, as of December 31, 2009, unless otherwise noted.

Power Distribution


		Approximate Miles of
		Power Distribution and
Business	Location	Transmission Lines
Luz del Sur	Peru	11,565
Chilquinta	Chile	5,169
Elektro	Brazil	66,597
EMDERSA⁽¹⁾	Argentina	15,885
EDEN⁽¹⁾	Argentina	10,971
Elektra	Panama	5,605
Delsur	El Salvador	5,313


(1)		Pending local anti-trust approval.

Power Generation


		Generating Capacity
Business	Power Plant Location	(MW)		Fuel Type
Cuiabá — EPE	Brazil		480	Natural gas and fuel oil⁽¹⁾
Emgasud	Argentina		205	Natural gas and fuel oil
PQP	Guatemala		234	Bunker fuel
San Felipe	Dominican Republic		180	Diesel oil/bunker fuel
Corinto	Nicaragua		71	Bunker fuel
JPPC	Jamaica		60	Bunker fuel
Tipitapa	Nicaragua		51	Bunker fuel
Amayo	Nicaragua		40	Wind
Luoyang	China		270	Coal
Trakya	Turkey		478	Natural gas and fuel oil⁽²⁾
ENS	Poland		116	Natural gas
DCL	Pakistan		94	Natural gas


(1)		Upon ANEEL request and based on reimbursement of fuel oil, EPE is able to run its power plant on a dual fuel basis.

(2)		Trakya is able to run its power plant on fuel oil on a backup basis.

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Natural Gas Transportation and Services


Business	Location	Description
Promigas
Promigas Pipeline	Colombia	1,271 miles pipeline system in La Guajira region, to Jobo station in Department of Sucre
Centragas	Colombia	458 mile pipeline in the Department of Santander
Transmetano	Colombia	93 mile pipeline in the Department of Antioquia
Transoccidente	Colombia	7 mile pipeline in the Department of Valle del Cauca
GBS	Colombia	196 mile pipeline in the Departments Boyacá and Santander
Transoriente	Colombia	98 mile pipeline in the Department of Santander
PSI	Colombia	Natural gas drying and compression facility at Ballena station
Accroven	Venezuela	NGL extraction facilities at San Joaquín and Santa Bárbara gas fields and NGL fractionation, storage and refrigeration facilities in Jose petrochemical complex on Northeastern coast
BBPL
TBG	Brazil	1,611 mile pipeline from GTB pipeline at Station Mutún, Bolivia to southeastern Brazil
GTB	Bolivia	346 mile pipeline from Station Rio Grande to Station Mutún and connecting to TBG pipeline
Cuiabá
GOB	Bolivia	225 mile pipeline connecting to GOM pipeline
GOM	Brazil	175 mile pipeline in Mato Grosso connecting to GOB pipeline
Emgasud	Argentina	440 miles of pipeline in the Patagonia region

Natural Gas Distribution


Business	Location	Description
Promigas
Gases del Caribe	Colombia	8,845 miles of mains in Magdalena, Cesar, Atlántico and La Guajira
Gases de Occidente	Colombia	4,398 miles of mains in Valle del Cauca
Surtigas	Colombia	5,083 miles of mains in Bolívar, Sucre and Córdoba
Cálidda	Peru	559 miles of mains in Lima and Callao Provinces
Emgasud	Argentina	507 miles of mains in Southeast Buenos Aires
BMG	China	1,015 miles of mains in 15 service areas
Tongda	China	1,425 miles of mains in 10 service areas in Jiangsu Province

Retail Fuel


Business	Location	Description
SIE
Terpel	Colombia	1,296 service stations, including 28 supply stations
	Chile	198 service stations
	Ecuador	63 service stations
	Panama	58 service stations
Gazel	Colombia	224 service stations
	Mexico	3 service stations
	Peru	16 service stations
	Chile	3 service stations

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Item 5. Operating and Financial Review and Prospects

This discussion should be read together with the “Item 3. Key Information — A. Selected Financial Data,” and the consolidated financial statements (including the notes thereto) and PEI’s consolidated financial statements included elsewhere in this annual report. Unless otherwise indicated, the financial data contained in this annual report has been prepared in accordance with accounting principles generally accepted in the United States, or U.S. GAAP. See “Forward-Looking Statements” and “Item 3. Key Information — D. Risk Factors” for a discussion of factors that could cause future financial condition and results of operations to be different from those discussed below.

Interests in certain companies are accounted for under the equity method, which means that their net income or losses are included into consolidated profit and loss accounts in proportion to the ownership interest that is owned of the relevant company or entity during the respective periods. See Note 11 to the consolidated financial statements for the year ended December 31 2009.

Overview

We own and operate essential energy infrastructure assets in emerging markets. We group our businesses into five reporting segments: Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel. For the years ended December 31, 2009, 2008 and 2007, we generated consolidated revenues of $8.2 billion, $9.2 billion and $3.2 billion, respectively, consolidated operating income of $731 million, $813 million and $577 million, respectively, consolidated net income of $288 million, $282 million and $196 million, respectively, and consolidated net income attributable to AEI of $297 million, $158 million and $131 million, respectively.

Critical Accounting Policies and Estimates

This “Operating and Financial Review and Prospects” is based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP and require management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Accounting policies are applied that management believes best reflect the underlying business and economic events, consistent with U.S. GAAP. The more critical accounting policies include those related to the basis of presentation, acquisition accounting, long-lived assets, valuation and impairment of goodwill and indefinite-lived intangibles, revenue recognition, recognition of regulatory assets and liabilities, accruals for income taxes, accruals for long-term employee benefit costs such as pension and other postretirement costs, foreign currency translation and measurement and contingencies. Inherent in such policies are certain key assumptions and estimates made by management. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates, which by their nature bear the risk of change related to the ability to accurately forecast a future event and its potential impact. Management periodically updates its estimates used in the preparation of the consolidated financial statements based on its latest assessment of the current and projected business and general economic environment. These critical accounting policies have been discussed with the Audit Committee of the Board of Directors. Significant accounting policies are summarized in Note 2 to our consolidated financial statements.

Basis of Presentation

The consolidated financial statements include the accounts of all wholly-owned companies, majority-owned subsidiaries and controlled affiliates. Investments in entities where we held an ownership interest of at least 20%, and which we neither control nor are the primary beneficiary, but in which we exercise significant influence, are accounted for under the equity method of accounting. Other investments, in which we own less than a 20% interest, unless we can clearly exercise significant influence over operating and financing policies, are recorded at cost. The consolidated financial statements are presented in accordance with U.S. GAAP.

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Acquisition Accounting

The purchase method of accounting is used for accounting for acquired businesses which requires that the assets acquired and liabilities assumed be recorded at the date of acquisition at their respective fair values. The application of the purchase method requires estimates and assumptions, in particular concerning the determination of the fair values of the acquired property, plant and equipment and intangible assets, as well as the liabilities assumed at the date of the acquisition. Additionally, the useful lives of the acquired property, plant and equipment and intangibles have to be determined. The judgments made in the context of purchase price allocation can materially impact future results of operations, as reported under U.S. GAAP. For example, if it was determined that the allocated fair value of the acquired property, plant and equipment were lower than the actual fair value by $100 million, goodwill would be higher by a corresponding after-tax amount, and depreciation expense would be reduced by approximately $5 million annually, based on an estimated average remaining useful asset life of approximately 19 years. Accordingly, we utilize valuations based on information available at the acquisition date.

Significant judgments and assumptions made regarding the purchase price allocation for acquisitions include the following:

For acquired entities with regulated operations, management determines the fair values which reflected the regulatory framework of the specific country in which the assets reside. For non-regulated operations, which do not conform to a regulatory framework, management utilizes appraisals, in part, to determine asset and liability fair values. These appraisals are typically based on either a depreciated replacement cost method to value property, plant and equipment or a discounted cash-flow analysis, to value, for example, long-term contracts, impairments of property plant and equipment and to determine enterprise value.

Appraisals using the depreciated replacement cost approach consider the replacement value taking into consideration market reports and technology, as well as, adjustments for an estimated remaining useful life considering new construction. These appraisals use an indirect cost approach considering replacement costs. These replacement costs are depreciated on a straight-line basis over the assets’ economic useful life according to an age analysis.

For power distribution and generation intangible assets associated with concession rights, the valuation is based on the expected future cash flows and earnings. This method employs a discounted cash flow analysis using the present value of the estimated cash flows expected to be generated from the contract using risk adjusted discount rates and revenue forecasts as appropriate. The period of expected cash flows is based on the term of the concession agreements taking into account regulatory stability and the ability to renew these agreements.

Long-Lived Assets

With respect to long-lived assets, key assumptions include the estimates of useful asset lives and the recoverability of carrying values of fixed assets and other intangible assets, as well as the existence of any obligations associated with the retirement of fixed assets. Such estimates could be significantly modified and/or the carrying values of the assets could be impaired by such factors as the relative pricing of wholesale electricity by region, the anticipated costs of fuel, changes in legal factors or in the business climate, including an adverse action or assessment by regulators, or a significant change in the market value, operation or profitability of an asset.

For long-lived assets, impairment would exist when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery was probable. The best information available is used to estimate fair value of long-lived assets and more than one source may be used.

The estimated useful lives of long-lived assets range from three to 50 years. Depreciation and amortization expense of these assets under the straight-line method over their estimated useful lives totaled $272 million in 2009. If the useful lives of the assets were found to be shorter than originally estimated, depreciation and amortization charges would be accelerated over the revised useful life.

Goodwill and Indefinite Life Intangible Assets

Goodwill and intangible assets with indefinite useful lives are tested annually for impairment and whenever events or circumstances make it more likely than not that impairment may have occurred, such as a significant adverse change in the business climate or a decision to sell or dispose all or a portion of a business unit. Determining whether an impairment has occurred requires valuation of the respective business unit, which is estimated using a discounted cash flow method based on actual operating results, future business plans, economic projections and market data. If this analysis indicates goodwill is impaired, measuring the impairment requires a fair value estimate of each identified tangible and intangible asset.

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Revenue Recognition

A significant portion of our businesses’ revenues are related either to regulated tariffs or to long-term contracts, most of which include pass-through provisions for the cost of energy, fuel and gas. Our revenues and cost of sales may be significantly affected by the volatility in energy and fuel prices. However, because of the pass-through provisions, fluctuations in revenues and cost of sales taken in absolute terms may themselves not be meaningful in the analysis of our financial results.

Revenues are attributable to sales and other revenues associated with the transmission and distribution of power and natural gas; sales from the generation of power; and the wholesale and retail sale of gasoline and CNG.

Revenues from the sale of energy are recognized in the period in which the energy is delivered. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Revenues received from other distribution companies for use of the basic transmission or distribution network are recognized in the month that the network services are provided. The revenues from the Power Generation segment are recorded in each period based upon output delivered and capacity provided at rates specified under contract terms or prevailing market rates. Additionally, when the underlying contract meets the requirements of a lease, the associated revenues are recognized over the term of the lease. In addition, some contracts contain decreasing rate schedules, which results in revenue being levelized and recognized based upon the energy delivered rather than on customer billings. All other revenues are recognized when products are delivered.

An allowance for doubtful accounts for estimated uncollectible accounts receivable is determined based on the length of time the receivables are past due, economic and political trends and conditions affecting customers, significant events and historical experience. Established reserves have historically been sufficient, and are based on specific customer circumstances, historical experience and current knowledge of the related political and economic environments. The balance of our allowance for doubtful accounts totaled $78 million at December 31, 2009.

Regulatory Assets and Liabilities

Assets and liabilities that result from the regulated rate making process are recorded that would not be recorded under U.S. GAAP for non-regulated entities. We capitalize incurred allowable costs as deferred regulatory assets if it is a probable that future revenue at least equal to the costs incurred will be billed and collected through approved rates. If future recovery of costs is not considered probable, the incurred cost is recognized as an expense. Regulatory liabilities are recorded for amounts expected to be passed to the customer as refunds or reductions on future billings. Regulatory assets totaled $131 million and regulatory liabilities totaled $149 million at December 31, 2009.

Income Taxes

We operate through various subsidiaries in many countries throughout the world. Deferred tax assets and liabilities are recognized based on the estimated future tax effects of differences between the financial statement and tax bases of assets and liabilities given the enacted tax laws. Income taxes have been provided based upon the tax laws and rates of the countries in which operations are conducted and income is earned. The need for a deferred tax asset valuation allowance is evaluated by assessing whether it is more likely than not that deferred tax assets will be realized in the future. The assessment of whether or not a valuation allowance is required often requires significant judgment, including the forecast of future taxable income and the evaluation of tax planning initiatives. Adjustments to the deferred tax valuation allowance are made to earnings in the period when such assessment is made.

Certain AEI subsidiaries are under examination by relevant taxing authorities for various tax years. The potential outcome of these examinations in each of the taxing jurisdictions is regularly addressed when determining the adequacy of the provision for income taxes. The tax benefit from an “uncertain tax position” is only recognized when it is more-likely-than-not that, based on the technical merits, the position will be sustained by taxing

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authorities or the courts. When a tax position meets the more-likely-than-not recognition threshold, the recognized tax benefit is measured as the largest amount of tax benefit having a greater than fifty percent likelihood of being sustained upon ultimate settlement with a taxing authority that has full knowledge of the relevant information. Liabilities for uncertain tax positions have been established, which management believes to be adequate in relation to the potential for additional assessments. In the preparation of the consolidated financial statements, management exercises judgments in estimating the potential exposure to unresolved tax matters. While actual results could vary, in management’s judgment, accruals with respect to the ultimate outcome of such unresolved tax matters are adequate.

Pension and Other Postretirement Obligations

Through Elektro, two supplementary retirement and pension plans are sponsored for Elektro employees. Pension benefits are generally based on years of credited service, age of the participant and average earnings. The measurement of pension obligations, costs and liabilities depends on a variety of actuarial 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, return on plan assets 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 discount rates, expected return on plan assets, retirement rates, inflation, salary growth and mortality rates. The effects of actual results differing from assumptions are accumulated and amortized over future periods and, therefore, generally affect recognized expense in such future periods. A variance in the assumptions listed above could have an impact on the December 31, 2009 funded status. A one percentage point reduction in the assumed discount rates would increase our benefit obligation for pensions and other postretirement benefits by approximately $45 million, and would reduce our net income by approximately $3 million. Based on the market value of plan assets at December 31, 2009, a one percentage point decrease in the expected rate of return on plan assets assumption would decrease our net income by approximately $3 million.

In certain countries, including Panama, El Salvador, Turkey, Brazil and Colombia, local labor laws or union agreements require us to pay severance indemnities to employees when their employment is terminated. Our Argentine companies are required to pay certain benefits to employees upon retirement. In Brazil, we have agreed with the local union to create a special retirement program in which we provide incentives to retirement-eligible employees to retire. We accrue these benefits based on historical experience and valuations performed by third parties or us.

Foreign Currency

We translate the financial statements of our international subsidiaries from their respective functional currencies into the U.S. dollar. An entity’s functional currency is the currency of the primary economic environment in which it operates and is generally the currency in which the business generates and expends cash. Subsidiaries whose functional currency is other than the U.S. dollar translate their assets and liabilities into U.S. dollars at the exchange rates in effect as of the balance sheet date. The revenues and expenses of such subsidiaries are translated into U.S. dollars at the average exchange rates for the year. Translation adjustments are included in accumulated other comprehensive income (loss), a separate component of shareholders’ equity. Foreign exchange gains and losses included in net income result from foreign exchange fluctuations on transactions denominated in a currency other than the subsidiary’s functional currency.

We have determined that the functional currency for some subsidiaries is the U.S. dollar due to their operating, financing and other contractual arrangements. The operating companies that are considered to have their local currency as the functional currency are EDEN and EMDERSA in Argentina; BMG, Tongda and Luoyang in China; Elektro in Brazil; DCL in Pakistan; ENS in Poland; Chilquinta in Chile; Luz del Sur in Peru; certain operating companies of Proenergía in Colombia and Chile; and certain operating companies of Promigas in Colombia.

Intercompany notes between subsidiaries that have different functional currencies result in the recognition of foreign currency exchange gains and losses unless we do not plan to settle or are unable to anticipate settlement in the foreseeable future. All intercompany balances eliminate upon consolidation.

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Contingencies

Estimates of loss contingencies, with respect to legal, political and environmental issues, including estimates of legal defense costs when such costs are probable of being incurred and are reasonably estimable and related disclosures are updated when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, status of laws and regulations and the information available about conditions in the various countries. Accruals for loss contingencies are recorded based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. The range of potential liabilities could be significantly different than amounts currently accrued and disclosed, with the result that our financial condition and results of operations could be materially affected by changes in the assumptions or estimates related to these contingencies.

Accounting Standards adopted in 2009

Please see Note 2 to our consolidated financial statements.

Recent Accounting Standards — to be Adopted

In October 2009, the FASB issued ASU 2009-13, “Revenue Recognition — Multiple-Deliverable Revenue Arrangements”, on ASC 605, “Revenue Recognition.” This update addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services (deliverables) separately rather than as a combined unit. Subtopic 605-25, Revenue Recognition — Multiple-Element Arrangements, establishes the accounting and reporting guidance for arrangements under which the vendor will perform multiple revenue- generating activities. Specifically, this update addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. In addition, this update expands the disclosures related to a vendor’s multiple-deliverable revenue arrangements. This update will be effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. We will adopt this update as of January 1, 2011 and have not determined the impact, if any, on our consolidated financial statements.

In December 2009, the FASB issued an update on ASC 810, “Consolidation.” This update (ASC 810-10) amends certain requirements associated with the consolidation of variable interest entities, or VIEs, to improve financial reporting by enterprises involved with VIEs and to provide more relevant and reliable information to users of financial statements. This standard will increase the use of qualitative considerations in identifying which entity in the VIE has a controlling financial interest that enables them to direct the activities that most significantly impact the entity’s economic performance. The provisions of this update are effective for interim and annual reporting periods beginning after November 15, 2009, or January 1, 2010 for us. Based on our initial evaluation performed in accordance with this update, we determined that there were no entities qualifying as VIEs

In January 2010, the FASB issued ASU 2010-06 “Improving Disclosures About Fair Value Measurements” on ASC 820, “Fair Value Measurements and Disclosures.” This update adds new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. The provisions of this update are effective for the interim or annual reporting period beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the roll forward activity in Level 3 fair value measurements. Those disclosures are effective for interim and annual reporting periods beginning after December 15, 2010. We will incorporate the additional disclosure requirements in our financial statements beginning with the quarter ended March 31, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward activity in Level 3 fair value measurements, which will be incorporated in our financial statements beginning with the quarter ended March 31, 2011.

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A. Operating Results

Results of Operations — Overview

Our management reviews the results of operations using a variety of measurements including an analysis of the statement of operations, and more specifically, revenues, costs of sales and operating expenses and operating income line items. These measures are important factors in our performance analysis. In order to better understand the discussion of operating results, detail regarding certain line items has been provided below.

Revenues

	•		Power Distribution revenues are derived primarily from contracts with retail customers in the residential, industrial and commercial sectors. These revenues are based on tariffs, reviewed by the applicable regulator on a periodic basis, and recognized upon delivery. In addition to a reasonable rate of return on regulatory assets and other amounts, tariffs include a pass-through of nearly all wholesale energy costs included in our Power Distribution costs of sales. Therefore, Power Distribution revenues are significantly impacted by wholesale energy costs. Upon each periodic regulatory review, tariffs are reset to the appropriate level, which might be higher or lower than the current level, to align the business’ revenue to the authorized pass-through of costs and the applicable return on the business asset base. Therefore, revenues for a specific business may vary substantially from one period to the next if there has been a tariff reset in between.

	•		Power Generation revenues are generated from the sale of wholesale power under long-term contracts to large off-takers, which in many circumstances are state-controlled entities. JPPC’s, Trakya’s and San Felipe’s contracts contain decreasing rate schedules, which results in revenues being deferred due to differences between the amounts billed to customers and the average revenue stream over the life of the contract.

	•		Natural Gas Transportation and Services revenues are primarily service fees received based on regulated rates set by a government controlled entity, and the capacity volume allocated for natural gas transportation in pipelines. Additional revenues are recognized for other natural gas related services, such as compression or liquefaction. As with the Power Distribution segment, businesses in this segment are subject to periodic regulatory review of their tariffs.

	•		Natural Gas Distribution revenues are primarily generated from service and connection fees received based on regulated rates, set by a government controlled entity, and the volume of natural gas sold to retail customers in the residential, industrial and commercial sectors. Similar to the Power Distribution segment, businesses in this segment are subject to periodic regulatory review of their tariffs.

	•		Retail Fuel revenues represent primarily the distribution and retail sale of gasoline and CNG. Gasoline prices are normally regulated, whereas CNG prices are normally free of regulation, but tend to correlate with gasoline prices.

Costs of sales

Power Distribution costs of sales relate directly to the purchase of wholesale energy either under long-term contracts or in the spot market. The Power Distribution businesses are permitted to pass on nearly all wholesale energy costs to the customers, although there may be a lag in time as this pass-through takes place through the tariff process. Therefore, increases and decreases in Power Distribution costs of sales directly impact Power Distribution revenues. The Power Generation segment costs of sales consist primarily of purchases of natural gas and other fuels for generation. Natural Gas Distribution and Retail Fuel costs of sales represent the cost of wholesale purchasing of natural gas and other fuels that are resold to the final customers. Generally, costs of sales are not recorded in the Natural Gas Transportation and Services businesses.

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Operating expenses

Operating expenses include the following line items: operations, maintenance and general and administration expenses, depreciation and amortization, taxes other than income, other charges and (gain) loss on disposition of assets. Operations, maintenance and general and administration expenses include primarily direct labor, insurance, repairs and maintenance, utilities and other contracted expenses. These expenses are usually independent of the volumes of energy produced or distributed through the systems, but may fluctuate on a period to period basis. In the case of the principal executive offices, which are included as part of Headquarters/Other Eliminations, these expenses include the salaries and benefits of the personnel in that office as well as professional services contracted on behalf of the entire organization that do not pertain or relate to a particular business or group of businesses.

Foreign Currency

The financial statements are reported in U.S. dollars. The financial statements of some of our subsidiaries are prepared using the local currency as the functional currency and translated into U.S. dollars. Period-end and average foreign currency rates impact our financial position and results of operations.

The following table presents the period-end and average exchange rates of the U.S. dollar into the local currency where we are primarily exposed to fluctuations in the exchange rate.


	Exchange rates on December 31,
	2008		2009
Period-end exchange rates:
Brazilian real		2.40		1.74
Colombian peso		2,253		2,043


	Average Exchange Rates for the Twelve Months Ended
	December 31,
	2007		2008		2009
Average period exchange rates:
Brazilian real		1.95		1.83		1.99
Colombian peso		2,120		1,990		2,172

Source: Bloomberg financial website for December 2009 and 2008; OANDA Corporation financial website for 2007.

AEI Results of Operations

The results of the following significant operating companies are reflected in the results of continuing operations in the periods indicated:


	For the Year Ended December 31,
	2009	2008	2007
Power Distribution
Chilquinta	Equity Method	Equity Method	Equity Method⁽¹⁾
Delsur	Consolidated	Consolidated	Consolidated⁽¹⁾
EDEN	Consolidated	Consolidated	Consolidated⁽¹⁾
Elektra	Consolidated	Consolidated	Consolidated
Elektro	Consolidated	Consolidated	Consolidated
EMDERSA	Consolidated⁽²⁾	—	—
Luz del Sur	Equity Method	Equity Method	Equity Method⁽¹⁾
Power Generation
Amayo	Equity Method⁽²⁾⁽³⁾	—	—
Corinto	Consolidated⁽³⁾	Consolidated	Consolidated
Cuiabá — EPE	Consolidated⁽⁴⁾	Consolidated	Consolidated
DCL	Consolidated	Consolidated⁽⁵⁾	—
ENS	Consolidated	Consolidated	Consolidated
Emgasud	Equity Method	Equity Method⁽⁵⁾	—
Fenix	Consolidated	Consolidated⁽⁵⁾	—
Jaguar	Consolidated	Consolidated	—
JPPC	Consolidated	Consolidated	Consolidated⁽¹⁾
Luoyang	Consolidated	Consolidated⁽⁵⁾	—
PQP	Consolidated	Consolidated	Consolidated
San Felipe	Consolidated	Consolidated	Consolidated
Subic	—⁽⁶⁾	Equity Method	Equity Method
Tipitapa	Consolidated⁽³⁾	Consolidated⁽⁵⁾	—

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	For the Year Ended December 31,
	2009	2008	2007
Trakya	Consolidated⁽⁷⁾	Consolidated	Consolidated
Natural Gas Transportation and Services
Accroven	Equity Method	Equity Method	Equity Method
Cuiabá — GOB/GOM/TBS	Consolidated⁽⁴⁾	Consolidated	Consolidated
GTB	Equity Method⁽⁸⁾	Cost Method	Equity Method
Promigas	Consolidated	Consolidated	Consolidated
TBG	Cost Method⁽⁸⁾	Cost Method	Cost Method
TGS	Cost Method⁽²⁾	—	—
Transredes	Cost Method	Cost Method	Equity Method
Natural Gas Distribution
BMG	Consolidated	Consolidated	Cost Method⁽¹⁾
Cálidda	Consolidated	Consolidated	Consolidated⁽¹⁾
Promigas	Consolidated	Consolidated	Consolidated
Tongda	Consolidated	Consolidated	Consolidated⁽¹⁾
Retail Fuel
Proenergía	Consolidated⁽⁹⁾	Consolidated	Equity Method


(1)		Our initial interest was purchased during 2007.

(2)		Our initial interest was purchased during 2009.

(3)		During the first quarter of 2009, as part of the Nicaragua Energy Holdings, or NEH, transaction, our ownership in Corinto increased from 50% to 57.67% and our ownership in Tipitapa decreased from 100% to 57.67%. In addition, we own, through its 57.67% interest in NEH, a 12.72% equity interest in Amayo. See Note 3 to our consolidated financial statements.

(4)		On December 18, 2009, we acquired an additional 50% of each of EPE, GOM, GOB and TBS from a third party. As a result, we currently own 100% of each of EPE, GOM, GOB and TBS. See Note 3 to our consolidated financial statements.

(5)		Our initial interest was purchased during 2008.

(6)		In February 2009, the 15-year build-to-operate-transfer agreement, or BOT, between Subic Power Corp., or Subic, and the National Power Corporation of the Philippines, or NPC, expired on schedule and the plant was turned over to the NPC without additional compensation.

(7)		In August 2009, we increased our ownership in Trakya from 59% to 90%. See Note 3 to our consolidated financial statements.

(8)		On December 18, 2009, we acquired an additional 4% of TBG and an additional 17% of GTB from a third party. As a result, we currently own 8.27% of TBG and 34.65% of GTB. See Note 3 to our consolidated financial statements.

(9)		On January 2, 2008, Promigas contributed its ownership interests in Gazel to SIE in exchange for additional shares of SIE. As a result of this transaction, Promigas’ ownership in SIE increased from 37.19% as of December 31, 2007 to 54% with SIE owning 100% of Gazel. See Note 3 to our consolidated financial statements. Proenergía, a holding company for the retail fuel operations, was spun-off from Promigas in July 2009.

In some of the period-to-period comparisons contained in this section, reference is made to the “stand-alone” performance of our subsidiaries, which is their unaudited 12-month results and which is prepared in accordance with U.S. GAAP. This is intended to provide information on the performance of the underlying business, regardless of when it was acquired by us and whether the business is accounted for using the equity method or is consolidated.

On November 15, 2007, we completed the sale, through a holding company, of 98.16% of Vengas, S.A. , or Vengas, (constituting its entire interest in Vengas) for $73 million in cash. The company recorded a gain of $41 million in the fourth quarter of 2007 for which no taxes were recorded due to certain exemptions under the holding company’s tax status. Vengas was previously presented as part of the Retail Fuel segment.

Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

The following discussion compares our results of continuing operations for the year ended December 31, 2009 to the year ended December 31, 2008.

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Revenues

The table below presents our consolidated revenues by significant geographical location for the years ended December 31, 2009 and 2008. Revenues are reported in the country in which they are earned. Intercompany revenues between countries have been eliminated in Other and eliminations below.


	For the Years Ended
	December 31,
	2009			2008
	Millions of dollars (U.S.)
Andean
Colombia	$	3,603		$	3,926
Chile		907			1,311
Other countries		248			219

Subtotal		4,758			5,456

Southern Cone
Brazil		1,418			1,503
Argentina		173			122
Other countries		17			21

Subtotal		1,608			1,646

Central America/Caribbean
Panama		602			808
El Salvador		214			172
Guatemala		193			206
Other countries		319			384

Subtotal		1,328			1,570

Europe/Middle East/North Africa
Turkey		357			416
Other countries		103			123

Subtotal		460			539

China		151			104

Other and eliminations		(120	)		(104	)

Total	$	8,185		$	9,211

The following table reflects revenues by segment:


	For the Years Ended
	December 31,
	2009			2008
	Millions of dollars (U.S.)
Power Distribution	$	2,151		$	2,217
Power Generation		1,027			1,175
Natural Gas Transportation and Services		197			202
Natural Gas Distribution		654			584
Retail Fuel		4,245			5,137
Headquarters/Other/Eliminations		(89	)		(104	)

Total revenues	$	8,185		$	9,211

Revenues decreased by $1,026 million to $8,185 million for the year ended December 31, 2009 compared to $9,211 million for the year ended December 31, 2008. The decrease was primarily due to the decrease in revenues at the Retail Fuel segment ($892 million), the Power Generation segment ($148 million) and the Power Distribution segment ($66 million), partially offset by the increase in revenues at the Natural Gas Distribution segment ($70 million) as described below. Generally, revenues decreased year-on-year due to the decrease in fuel prices which is passed on to the end customers and the devaluation of the local currency (a stronger U.S. dollar) based on the average annual exchange rate which negatively impacts revenues when translated to U.S. dollars.

Power Distribution

Revenues from the Power Distribution segment decreased by $66 million to $2,151 million for the year ended December 31, 2009 compared to $2,217 million for the year ended December 31, 2008. The decrease was primarily due to the appreciation of the U.S. dollar partially offset by higher volumes and the acquisition of EMDERSA made in 2009.

Decreased revenues at Elektra ($121 million) and Elektro ($39 million) for the 12 month comparison period were partially offset by increased revenues at Delsur ($42 million) and additional revenues from the acquisition of EMDERSA ($61 million) during 2009. The decreased revenues at Elektra were primarily due to lower pricing ($140 million) as a result of the monthly and bi-annual tariff adjustments to the energy cost component of its customer tariff driven by lower fuel costs, partially offset by higher energy sales volumes ($23 million) as a result of expanded customer base and increased customer demand. Elektro revenues based on local currency, or a constant dollar rate, increased compared to the prior year. The increase was primarily due to higher pricing ($102 million) as a result of the net favorable impact of tariff adjustments and higher sales volumes ($17 million) as a result of the

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increased number of residential and commercial customers and improved sales mix, partially offset by higher revenues ($22 million) recognized in 2008 as a result of a 2008 tariff adjustment and regulatory determinations made by ANEEL combined with the residual 2007 tariff re-review impacts ($31 million) recorded in 2009, both of which negatively impact the comparison for this year. Revenues at Elektro reported in U.S. dollars actually decreased due to the devaluation of the Brazilian real relative to the U.S. dollar ($109 million). The increased revenues at Delsur were primarily due to higher pricing ($45 million) as a result of the elimination of the government subsidy to power generators which reduced prices to the end customers as a result of lower pass-through of energy costs.

Power Generation

Revenues from the Power Generation segment decreased by $148 million to $1,027 million for the year ended December 31, 2009 from $1,175 million for the year ended December 31, 2008 due to generally lower prices. The decrease was primarily due to decreased revenues at Trakya ($59 million), San Felipe ($56 million), ENS ($17 million), PQP ($13 million), Corinto ($13 million) and JPPC ($12 million), partially offset by the increased revenues at Luoyang ($25 million) and additional revenues in 2009 compared to 2008 from the acquisition of Tipitapa ($15 million) during June 2008. The decreased revenues at Trakya were primarily due to lower billable fuel prices which were passed on to its customer, partially offset by higher generation volume in 2009 as a result of a major plant maintenance performed in the second quarter of 2008. The decreased revenues at San Felipe were primarily due to lower generation volume as a result of generally lower dispatch orders received in 2009 and lower billable fuel prices which were passed on to its customer. The decreased revenues at ENS were primarily due to the devaluation of the Polish zloty relative to the U.S. dollar, partially offset by the higher fuel cost compensation revenues obtained from the Polish government as a result of the voluntary termination of its PPA effective on April 1, 2008. The decreased revenues at PQP were primarily due to lower fuel prices passed on to its customers, partially offset by higher generation volume as a result of higher dispatch orders primarily due to the unavailability of hydro generation units. The decreased revenues at Corinto were primarily due to lower billable fuel prices which were passed on to its customers. The decreased revenues at JPPC were primarily due to lower fuel prices which were passed on to its customers and lower generation volumes as a result of major plant maintenance performed in September and October 2009. The increased revenues at Luoyang were primarily due to our acquisition of Luoyang in February 2008 and the increased revenues as a result of higher generation volume and a higher tariff rate approved by the Chinese government.

Natural Gas Transportation and Services

Revenues from the Natural Gas Transportation and Services segment of $197 million for the year ended December 31, 2009 were relatively flat compared to $202 million for the year ended December 31, 2008. Increased revenues at Promigas and its subsidiaries ($6 million) as a result of new contracts obtained in 2009 and an increased tariff on ancillary services provided by one of Promigas’ subsidiaries (PSI) were offset by a decrease in revenues generated at TBS.

Natural Gas Distribution

Revenues from the Natural Gas Distribution segment increased by $70 million to $654 million for the year ended December 31, 2009 compared to $584 million for the year ended December 31, 2008. The increase was primarily due to increased revenues at Promigas’ subsidiaries ($24 million), Cálidda ($24 million) and BMG ($19 million). The increased revenues at Promigas’ subsidiaries (Gases de Occidente and Surtigas) were primarily due to the increased distribution volume as a result of higher residential and industrial customer demand and tariff increase associated with higher gas well head prices, partially offset by the devaluation of the Colombian peso relative to the U.S. dollar. The increased revenues at Cálidda were primarily due to higher volumes distributed as a result of an increased customer base and a tariff increase as a result of monthly tariff adjustments for foreign currency and inflation. The increased revenues at BMG were primarily due to increased customer demand, increased connection and construction fee revenues and additional revenues as a result of our acquisition of BMG on January 30, 2008.

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Retail Fuel

Revenues from the Retail Fuel segment decreased by $892 million to $4,245 million for the year ended December 31, 2009 compared to $5,137 million for the year ended December 31, 2008. The decrease was primarily due to lower retail fuel prices which were passed on to customers resulting from lower gasoline prices and generally lower aviation fuel prices which are based on regulatory-set rates. In addition, revenues decreased due to the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar based on the average rates for the 12 month comparison periods.

Costs of sales

The following table reflects costs of sales by segment:


	For the Years Ended
	December 31,
	2009			2008
	(Millions of dollars U.S.)
Power Distribution	$	1,312		$	1,374
Power Generation		753			984
Natural Gas Transportation and Services		14			13
Natural Gas Distribution		416			386
Retail Fuel		3,846			4,697
Headquarters/Other/Eliminations		(103	)		(107	)

Total costs of sales	$	6,238		$	7,347

Costs of sales decreased by $1,109 million to $6,238 million for the year ended December 31, 2009 compared to $7,347 million for the year ended December 31, 2008. The decrease was primarily due to the decrease in costs of sales of the Retail Fuel segment ($851 million), the Power Generation segment ($231 million) and the Power Distribution segment ($62 million) as described below. Generally, costs of sales decreased year-on-year due to the decrease in fuel prices which are passed on to the end customers.

Power Distribution

Costs of sales for the Power Distribution segment decreased by $62 million to $1,312 million for the year ended December 31, 2009 compared to $1,374 million for the year ended December 31, 2008. The decrease was primarily due to lower prices for purchased electricity. Decreased costs of sales at Elektra ($125 million) were partially offset by increased costs of sales at Delsur ($44 million) and the impact of the acquisition of EMDERSA ($32 million). The decreased costs of sales at Elektra were primarily due to a lower average price of purchased electricity ($147 million) as a result of decreased fuel costs, partially offset by higher electricity volume purchased ($22 million) associated with expanded customer base and higher customer demand. The increased costs of sales at Delsur were primarily due to the higher average price of purchased electricity as a result of the elimination of the government subsidy to power generators. Costs of sales at Elektro were flat primarily due to higher energy prices and transportation charges fully passed-through to customers, offset by the devaluation of the Brazilian real relative to the U.S. dollar based on the average rates for the twelve month comparison periods.

Power Generation

Costs of sales for the Power Generation segment decreased by $231 million to $753 million for the year ended December 31, 2009 compared to $984 million for the year ended December 31, 2008. The decrease was primarily due to the decreased costs of sales at San Felipe ($102 million), Trakya ($69 million), PQP ($29 million), JPPC ($15 million), Corinto ($14 million) and ENS ($12 million), partially offset by the additional costs of sales from the acquisition of interests in Tipitapa ($11 million) and Luoyang ($8 million) during June and February 2008, respectively. The decreased costs of sales at San Felipe were primarily due to lower generation volume as a result of generally lower dispatch orders received in 2009 and lower fuel prices which will be passed on to its customers with certain time lag. The decreased costs of sales at Trakya were primarily due to lower fuel prices, partially offset by higher generation volume in 2009 as a result of a major plant maintenance performed in the second quarter of 2008. The decreased costs of sales at PQP were primarily due to lower fuel prices, partially offset by higher generation volume as a result of the unavailability of hydro generation units. The decreased costs of sales at JPPC were primarily due to lower fuel prices and lower generation volumes as a result of major plant maintenance performed in September and October 2009. The decreased costs of sales at Corinto were primarily due to lower fuel prices. The decreased costs of sales at ENS were primarily due to the devaluation of the Polish zloty relative to the U.S. dollar and lower excise tax as a result of the new tax law enacted in March 2009, which requires the excise tax to be paid by distribution companies, partially offset by higher fuel prices.

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Natural Gas Transportation and Services

Costs of sales for the Natural Gas Transportation and Services segment increased by $1 million to $14 million for the year ended December 31, 2009 compared to $13 million for the year ended December 31, 2008.

Natural Gas Distribution

Costs of sales for the Natural Gas Distribution segment increased by $30 million to $416 million for the year ended December 31, 2009 compared to $386 million for the year ended December 31, 2008. The increase was primarily due to the increased costs of sales at Cálidda ($18 million) and Promigas’ subsidiaries ($9 million). The increased costs of sales at Cálidda were primarily due to higher distribution volume as a result of an increased customer base. The increased costs of sales at Promigas’ subsidiaries (Gases de Occidente and Surtigas) were primarily due to higher distribution volume as a result of higher residential and industrial customer demand and higher gas wellhead prices, partially offset by the devaluation of the Colombian peso relative to the U.S. dollar based on the average rates for the twelve month comparison periods.

Retail Fuel

Costs of sales for the Retail Fuel segment decreased by $851 million to $3,846 million for the year ended December 31, 2009 compared to $4,697 million for the year ended December 31, 2008. The decrease was primarily due to lower gasoline and aviation fuel prices and the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar based on the average rates for the twelve month comparison periods.

Gross Margin

Gross margin is defined as revenues less costs of sales which may differ from the manner in which other companies may define gross margin (see “Non-GAAP Financial Measures”). The following table reflects gross margin by segment:


	For the Years Ended
	December 31,
	2009		2008
	Millions of dollars (U.S.)
Power Distribution	$	839	$	843
Power Generation		274		191
Natural Gas Transportation and Services		183		189
Natural Gas Distribution		238		198
Retail Fuel		399		440
Headquarters/Other/Eliminations		14		3

Total gross margin	$	1,947	$	1,864

Gross margin increased by $83 million to $1,947 million for the year ended December 31, 2009 compared to $1,864 million for the year ended December 31, 2008. The increase was primarily due to the increase in gross margin of the Power Generation segment ($83 million) and the Natural Gas Distribution segment ($40 million), partially offset by the decrease in gross margin of the Retail Fuel segment ($41 million), as described below.

Power Distribution

Gross margin for the Power Distribution segment of $839 million for the year ended December 31, 2009 was relatively flat compared to $843 million for the year ended December 31, 2008. The decrease in gross margin at Elektro ($40 million) due to the translation impact of the devaluation of the Brazilian real relative to the U.S. dollar and the unfavorable tariff adjustments registered in 2009 from finalization of the 2007 tariff was partially offset by higher pricing and volume distributed as discussed above. On a local currency basis, Elektro margins increased slightly due to increases in both residential volume and price. The decrease in gross margin from Elektro was partially offset by an increase due to the acquisition of EMDERSA ($29 million) in 2009.

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Power Generation

Gross margin for the Power Generation segment increased by $83 million to $274 million for the year ended December 31, 2009 compared to $191 million for the year ended December 31, 2008. The increase was primarily due to the increased gross margin at San Felipe ($46 million), Luoyang ($18 million), PQP ($16 million) and Trakya ($10 million), and the acquisition of Tipitapa ($4 million) in June 2008, partially offset by the decreased gross margin at ENS ($5 million). The increased gross margin at San Felipe was primarily due to the timing of recognition of pass-through costs under the PPA structure. Under the PPA, the revenue pricing is based on the costs incurred for a portion of the heavy fuel used in generation on an approximate one-year lag (when the fuel prices were generally higher) while the costs of sales are based on current fuel prices (which were generally lower in 2009 compared to 2008). The increased gross margin at Luoyang was primarily due to the increased tariff approved by the Chinese government as well as additional margin in 2009 as Luoyang was not acquired until February 2008. No pass-through mechanism for the cost of coal was built into the PPA of Luoyang. The increased gross margin at Trakya and PQP was primarily due to higher generation volume as discussed above. The decreased gross margin at ENS was primarily due to the devaluation of the Polish zloty relative to the U.S. dollar based on the average rates for the twelve month comparison periods.

Natural Gas Transportation and Services

Gross margin for the Natural Gas Transportation and Services segment of $183 million for the year ended December 31, 2009 was relatively flat compared to $189 million for the year ended December 31, 2008. The increase in gross margin at Promigas and its subsidiaries due to new contracts obtained in 2009 and the increased tariff on ancillary services provided by one of Promigas’ subsidiaries (PSI) was offset by the decreased revenues of TBS.

Natural Gas Distribution

Gross margin for the Natural Gas Distribution segment increased by $40 million to $238 million for the year ended December 31, 2009 compared to $198 million for the year ended December 31, 2008. The increase was primarily due to the increased gross margin at BMG ($15 million), one of the Promigas subsidiaries, Gases de Occidente ($14 million) and Cálidda ($6 million). The increased gross margin at BMG was primarily due to increased customer demand and increased connection and construction fee revenues which do not have associated costs of sales as well as the additional month of margin in 2009 as BMG was not acquired until January 30, 2008. The increased gross margin at Gases de Occidente was primarily due to increased industrial customer demand and a higher tariff, partially offset by the devaluation of the Colombian peso relative to the U.S. dollar based on the average rates for the 12 month comparison periods. The increased gross margin at Cálidda was primarily due to increased customer base and a higher tariff in 2009.

Retail Fuel

Gross margin for the Retail Fuel segment decreased by $41 million to $399 million for the year ended December 31, 2009 compared to $440 million for the year ended December 31, 2008. The decrease was primarily due to the higher inventory cost of diesel, regular and aviation fuel compared to current regulatory-set rates as prices have generally decreased in 2009 and the decreased wholesale fuel and retail fuel prices to be more competitive in both CNG and liquid fuel markets. Additionally, the decrease was due to the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar based on the average rates for the twelve month comparison periods.

Operating Expenses

Operations, Maintenance and General and Administrative Expenses

The following table reflects operations, maintenance and general and administrative expenses by segment:


	For the Years Ended December 31,
	2009		2008
	Millions of dollars (U.S.)
Power Distribution	$	329	$	323
Power Generation		106		123
Natural Gas Transportation and Services		61		62
Natural Gas Distribution		91		82
Retail Fuel		197		215
Headquarters/Other/Eliminations		79		89

Total operations, maintenance and general and administrative expenses	$	863	$	894

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Operations, maintenance and general and administrative expenses decreased by $31 million to $863 million for the year ended December 31, 2009 compared to $894 million for the year ended December 31, 2008. The overall general decrease was in part due to the appreciation of the U.S. dollar and our focus on conserving cash in response to the global economic crisis. The decrease was primarily in the Retail Fuel segment ($18 million) and the Power Generation segment ($17 million), partially offset by the increase in the Natural Gas Distribution segment ($9 million) and the Power Distribution segment ($6 million), as described below. In addition, the operations, maintenance and general and administrative expenses decreased at the parent level by $10 million as a result of reduced expenses for outside services and professional fees.

Power Distribution

Operations, maintenance and general and administrative expenses for the Power Distribution segment increased by $6 million to $329 million for the year ended December 31, 2009 compared to $323 million for the year ended December 31, 2008. The increase was primarily due to the acquisition of EMDERSA in 2009 ($16 million), partially offset by the decreased expenses at Elektro ($6 million) as a result of the devaluation of the Brazilian real relative to the U.S. dollar.

Power Generation

Operations, maintenance and general and administrative expenses for the Power Generation segment decreased by $17 million to $106 million for the year ended December 31, 2009 compared to $123 million for the year ended December 31, 2008. The decrease in expenses was primarily due to a decrease at Trakya ($26 million) as a result of the absence of cost related to major plant maintenance primarily performed in the second quarter of 2008, partially offset by an increase at EPE ($11 million) as a result of a charge in the third quarter of 2009 for the settlement of an arbitration related to the social contributions taxes (PIS and COFINS) collected by EPE in 2007 and prior years.

Natural Gas Transportation and Services

Operations, maintenance and general and administrative expenses for the Natural Gas Transportation and Services segment decreased by $1 million to $61 million for the year ended December 31, 2009 compared to $62 million for the year ended December 31, 2008.

Natural Gas Distribution

Operations, maintenance and general and administrative expenses for the Natural Gas Distribution segment increased by $9 million to $91 million for the year ended December 31, 2009 compared to $82 million for the year ended December 31, 2008. The increase was primarily due to increases in provisions for doubtful accounts at Promigas’ subsidiaries and increases in professional fees and information technology services fees at certain subsidiaries. The increase was partially offset by the devaluation of the Colombian peso relative to the U.S. dollar based on the average rates for the 12 month comparison periods.

Retail Fuel

Operations, maintenance and general and administrative expenses for the Retail Fuel segment decreased by $18 million to $197 million for the year ended December 31, 2009 compared to $215 million for the year ended December 31, 2008. The decrease was primarily due to the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar based on the average rates for the 12 month comparison periods.

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Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the Years Ended December 31,
	2009		2008
	Millions of dollars (U.S.)
Power Distribution	$	134	$	138
Power Generation		42		24
Natural Gas Transportation and Services		21		21
Natural Gas Distribution		23		18
Retail Fuel		46		61
Headquarters/Other		6		6

Total depreciation and amortization expenses	$	272	$	268

Total depreciation and amortization expenses increased by $4 million to $272 million for the year ended December 31, 2009 compared to $268 million for the year ended December 31, 2008. The increase was primarily due to increased depreciation and amortization expenses at EPE as a result of the termination of lease accounting treatment for its power supply agreement as of December 31, 2008; at DCL as a result of the termination of lease accounting treatment in March 2009; at San Felipe primarily due to lower amortization to income associated with the unfavorable PPA which is amortized based on the generated volumes produced by the power plant; and the acquisition of EMDERSA in 2009. These increases were partially offset by decreased depreciation and amortization expenses in the Retail Fuel segment and at Elektro. The decrease in the Retail Fuel segment was primarily due to the full amortization of customer relationship intangibles in 2008. The decrease at Elektro was primarily due to the devaluation of the Brazilian real relative to the U.S. dollar.

Other Charges

During the years ended December 31, 2009 and 2008, we recorded other charges totaling $123 million and $56 million, respectively. In the fourth quarter of 2009, we recorded an impairment charge of $96 million related to our investments in the Cuiabá Integrated Project and a total of $25 million, including a $5 million impairment of goodwill, related to our investment in DCL ($17 million net of tax and noncontrolling interests). Additionally, we recorded a $2 million impairment related to our cost method investment in Synthesis Energy Systems, Inc., or SES. In the third quarter of 2008, we recorded a charge totaling $44 million ($30 million net of tax and noncontrolling interests) related to our then existing lease investment receivable at EPE. During the fourth quarter of 2008, we recorded a $12 million impairment of our then $16 million cost method investment in SES. See Note 4 to the consolidated financial statements.

(Gain) Loss on Disposition of Assets

For the year ended December 31, 2009, we recorded a net loss on disposition of assets totaling $20 million compared to a net gain of $93 million for the year ended December 31, 2008. The $20 million loss in 2009 was primarily related to the ordinary course sale of operating equipment at Elektro compared to $18 million in 2008. During 2008, we recognized a gain of $68 million on the sale of 46% of Gazel to noncontrolling shareholders of SIE when exchanged for the additional interest in SIE and a gain of $57 million on the nationalization of Transredes, which was partially offset by a loss of $14 million on the sale of debt securities of Gas Argentina S.A., or GASA. See Notes 3, 5, 11 and 13 to the consolidated financial statements.

Equity Income from Unconsolidated Affiliates

The following table reflects equity income from unconsolidated affiliates by segment:


	For the Years Ended December 31,
	2009			2008
	Millions of dollars (U.S.)
Power Distribution	$	64		$	68
Power Generation		3			12
Natural Gas Transportation and Services		30			27
Natural Gas Distribution		14			11
Retail Fuel		2			1
Headquarters/Other/Eliminations		(6	)		(2	)

Total equity income from unconsolidated affiliates	$	107		$	117

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Equity income from unconsolidated affiliates decreased by $10 million to $107 million for the year ended December 31, 2009 compared to $117 million for the year ended December 31, 2008. The decrease was primarily due to the decreased equity income at Subic ($10 million) due to the expiration of the 15-year build-operate-transfer, or BOT, agreement between Subic and the NPC in February 2009, which required us to turn over the plant to the NPC.

Operating Income

The following table reflects the contribution of each segment to operating income in the comparative periods:


	For the Years Ended December 31,
	2009			2008
	Millions of dollars (U.S.)
Power Distribution	$	413		$	427
Power Generation		99			15
Natural Gas Transportation and Services		32			128
Natural Gas Distribution		128			104
Retail Fuel		140			218
Headquarters/Other/Eliminations		(81	)		(79	)

Total operating income	$	731		$	813

Operating income for the year ended December 31, 2009 decreased by $82 million to $731 million compared to $813 million for the year ended December 31, 2008. The decrease was primarily due to the decrease in the Natural Gas Transportation and Services segment ($96 million), the Retail Fuel segment ($78 million) and the Power Distribution segment ($14 million), partially offset by the increase in the Power Generation segment ($84 million) and the Natural Gas Distribution segment ($24 million).

Power Distribution

Operating income for the Power Distribution segment decreased by $14 million to $413 million for the year ended December 31, 2009 compared to $427 million for the year ended December 31, 2008. The decrease was mainly due to lower operating income at Elektro ($29 million) primarily due to the devaluation of the Brazilian real relative to the U.S. dollar and unfavorable residual 2007 tariff re-review impacts recorded in 2009, partially offset by increased operating income of $7 million at EDEN due to a tariff increase authorized in August 2008 and an $8 million increase due to the acquisition of EMDERSA in 2009.

Power Generation

Operating income for the Power Generation segment increased by $84 million to $99 million for the year ended December 31, 2009 compared to $15 million for the year ended December 31, 2008, primarily due to increases at San Felipe, Trakya, EPE and Luoyang, partially offset by the decrease at DCL. The increased operating income at San Felipe was primarily due to the timing of recognition of pass-through costs under the PPA structure. Under the PPA, the revenue pricing is based on the costs incurred for a portion of the heavy fuel used in generation on an approximate one-year lag (when the fuel prices were generally higher) while the costs of sales are based on current fuel prices (which are generally lower in 2009 compared to 2008). The increased operating income at Trakya was primarily related to the lower operating expenses due to the absence of cost related to major plant maintenance primarily performed in the second quarter of 2008 and the improved gross margin due to higher generation volume. The increased operating income at EPE was due to a lower operating loss of $67 million recognized in 2009 compared to an operating loss of $90 million in 2008. During the third quarter of 2008, EPE recognized $44 million in other charges to impair the value of its lease investment receivable as collectability was not assured. In December 2008, EPE ceased its lease accounting treatment. During the third quarter of 2009, EPE recognized a one-time charge of $15 million for the settlement of arbitration related to the social contributions taxes (PIS and COFINS) collected by EPE in 2007 and prior years. The increased operating income at Luoyang was primarily due to the improved gross margin as discussed above. The decreased operating income at DCL was primarily associated with the impairment charge recorded in the fourth quarter of 2009 as discussed above.

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Natural Gas Transportation and Services

Operating income for the Natural Gas Transportation and Services segment decreased by $96 million to $32 million for the year ended December 31, 2009 compared to $128 million for the year ended December 31, 2008. The decrease was primarily associated with the impairment charge of $96 million recorded in the Cuiabá Integrated Project during the fourth quarter of 2009. See Note 4 to the consolidated financial statements.

Natural Gas Distribution

Operating income for the Natural Gas Distribution segment increased by $24 million to $128 million for the year ended December 31, 2009 compared to $104 million for the year ended December 31, 2008, primarily related to the improved gross margin at BMG due to increased customer demand and increased connection and construction fee revenues and at one of Promigas’ subsidiaries (Gases de Occidente) due to increased industrial customer demand and higher tariff.

Retail Fuel

Operating income for the Retail Fuel segment decreased by $78 million to $140 million for the year ended December 31, 2009 compared to $218 million for the year ended December 31, 2008. The decrease was primarily due to a gain of $68 million recognized in 2008 on the sale of 46% of Gazel to noncontrolling shareholders of SIE when exchanged for the additional interest in SIE and lower gross margin in 2009 as discussed above.

Interest Income

Interest income decreased by $14 million to $74 million for the year ended December 31, 2009 compared to $88 million for the year ended December 31, 2008. Of the interest income earned during the years ended December 31, 2009 and 2008, 51% was related to Elektro, whose interest income is primarily related to short-term investments and interest on amounts owed by delinquent or financed customers. The decrease at Elektro was primarily due to the devaluation of Brazilian real relative to the U.S. dollar and lower interest rates as a result of lower monetary indexation.

Interest Expense

Interest expense decreased by $51 million to $327 million for the year ended December 31, 2009 compared to $378 million for the year ended December 31, 2008. The decrease was primarily due to the decreased interest expense at Elektro ($26 million) and the parent level ($31 million). Interest expense at Elektro decreased by $26 million to $46 million primarily due to lower interest rates and the devaluation of the Brazilian real relative to the U.S. dollar. Interest expense at the parent level decreased by $31 million to $104 million due to the conversion of Payment in Kind Notes, or PIK Notes, and lower interest rates for approximately $293 million of variable rate debt for which the parent company fixed the interest rate in January 2009 at historically low rates by entering into fixed interest rate swaps.

Foreign Currency Transaction Gain (Loss), Net

Total foreign currency transaction gains were $9 million (less than $1 million net of income tax and noncontrolling interests) for the year ended December 31, 2009 compared to foreign currency transaction losses of $56 million ($19 million net of income tax and noncontrolling interests) for the year ended December 31, 2008. During 2009, foreign currency transaction gains of $9 million at Proenergía were primarily associated with the effects of the appreciation of the Colombian peso relative to the U.S. dollar (based on the month end rate as of December 31, 2008 compared with the month end rate as of June 30, 2009 and September 30, 2009) on a $250 million U.S. dollar-denominated debt instrument held by Proenergía, which was refinanced into Colombian peso denominated debt in the second and third quarters of 2009. During 2008, foreign currency transaction losses of $31 million were primarily associated with the effects of the devaluation of the Colombian peso relative to the U.S. dollar on the same $250 million U.S. dollar-denominated debt instrument mentioned above; foreign currency transaction losses of $17 million at EPE were primarily due to the devaluation of a portion of the lease investments denominated in Brazilian real, which ceased to be accounted for as a lease as of December 31, 2008, as a result of the devaluation of the Brazilian real relative to the U.S. dollar; and foreign currency transaction losses of $8 million at Trakya were primarily due to the devaluation of Turkish lira denominated assets as a result of the devaluation of Turkish lira relative to the U.S. dollar for the year ended December 31, 2008.

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Gain on Early Retirement of Debt

During the second and third quarters of 2009, we recognized $10 million of gains on early retirement of debt related to our purchase from third parties of $31 million of outstanding debt held by our consolidated subsidiary EDEN.

Other Income (Expense), net

We recognized $70 million of other income for the year ended December 31, 2009 compared to $9 million of other income for the year ended December 31, 2008. The income recognized in 2009 was primarily due to a $49 million ($32 million net of income tax and noncontrolling interests) accrual reversal recorded by Elektro for the reversal of a social contribution tax accrual recorded prior to 2004. Additionally, reimbursements of income taxes to be received by San Felipe ($25 million) are recorded in other income (expenses), net. During 2008, other income of $9 million included dividend income of $3 million from TBG. See Note 6 to the consolidated financial statements.

Provision for Income Taxes

We are a Cayman Islands company, and are not subject to income tax in the Cayman Islands. We operate through various subsidiaries in a number of countries throughout the world. Income taxes have been provided based upon the tax laws and rates of the countries in which operations are conducted and income is earned.

The provision for income taxes for the years ended December 31, 2009 and 2008 was $279 million and $194 million, respectively. The estimated effective income tax rate for the year ended December 31, 2009 and 2008 was 49% and 41%, respectively, which was higher than the statutory rate primarily due to taxes generated at the local operating companies, and losses generated by us and our Cayman Island and certain of our Brazilian subsidiaries for which no tax benefit has been provided and which increased the effective tax rate for this period. Excluding the impact of non-cash other charges which provide no tax benefit, the effective tax rate is reduced to 40% and 36% for the years ended December 31, 2009 and 2008, respectively.

Noncontrolling Interests

The following table reflects the main components of net income (loss) — noncontrolling interests:


	For the Years Ended December 31,
	2009			2008
	Millions of dollars (U.S.)
Promigas	$	58		$	138
Proenergía		48			—
Cuiabá Integrated Project		(132	)		(37	)
Trakya		17			2
DCL		(16	)		(2	)
Elektra		10			8
Other		6			15

Total net income (loss) — noncontrolling interests	$	(9	)	$	124

Net income — noncontrolling interests decreased by $133 million to $(9) million for the year ended December 31, 2009 compared to $124 million for the year ended December 31, 2008. The decrease was primarily due to the noncontrolling interests’ share of the Cuiabá Integrated Project impairment ($96 million) and the DCL impairment ($8 million). In addition, the noncontrolling interests share of the Promigas gain ($55 million) on its sale of 46% of Gazel to noncontrolling shareholders of SIE during 2008. The decreases were partially offset by higher income generated at Trakya due to the lack of major maintenance, which was performed in the second quarter of 2008.

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Net Income Attributable to AEI

As a result of the factors discussed above, net income attributable to AEI for the year ended December 31, 2009 was $297 million compared to net income attributable to AEI of $158 million for the year ended December 31, 2008.

Adjusted Net Income Attributable to AEI

Adjusted net income attributable to AEI is defined as net income attributable to AEI excluding impairments and other charges, foreign currency transaction gains and losses, gains and losses on early retirement of debt, gains and losses on sales of assets, and settlements that are not related to the periods presented. We exclude these items from our internal measurements of performance. These items are generally non-cash and are not included by investors, financial analysts and the public when determining valuation and expectations for future performance of the company (see “Non-GAAP Financial Measures”). Adjusted net income attributable to AEI for the year ended December 31, 2009 was $288 million compared to adjusted net income attributable to AEI of $177 million for the year ended December 31, 2008.


	For the Year Ended December 31,
	2009			2008
	Millions of dollars (U.S.)
Net income attributable to AEI	$	297		$	158
EPE — arbitration settlement		14			—
EPE — lease receivable allowance		—			30
SES available-for-sale securities impairment		2			12
Elektro — prior year social contributions accrual reversal		(32	)		—
DCL — impairment		17			—
Foreign currency transaction loss, net		—			19
Gain on early retirement of debt		(10	)		—
Luoyang — net loss attributable to noncontrolling interests recognized by AEI		—			13
Loss on sale of Metrogas securities		—			14
Gain on nationalization of Transredes		—			(57	)
Gain on SIE/Gazel transaction		—			(12	)

Adjusted net income attributable to AEI	$	288		$	177

Factors contributing to adjusted net income attributable to AEI are as follows:

	•		A charge in the third quarter 2009 of $27 million, or $14 million net of tax and noncontrolling interests, for the settlement of arbitration related to the social contributions taxes (PIS and COFINS) collected by EPE in 2007 and prior years

	•		A $44 million charge, or $30 million net of tax and noncontrolling interests, in 2008 related to an allowance for EPE’s lease investment receivable balance

	•		Impairment charges of $2 million and $12 million in 2009 and 2008, respectively, on SES available-for-sale securities to mark to market value

	•		A $32 million net of tax ($49 million gross) accrual reversal recorded by Elektro in Other income in the second quarter of 2009 for the reversal of a social contribution tax accrual recorded prior to 2004

	•		A $25 million, or $17 million net of tax and noncontrolling interests, impairment charge on DCL, including a $5 million impairment of goodwill, in the fourth quarter of 2009

	•		Non-cash foreign currency losses on financial assets and liabilities

	•		Gain of $10 million on the extinguishment of debt from purchases in the second and third quarter of 2009 of EDEN’s debt by us

	•		A loss of $13 million at Luoyang in 2008 otherwise attributable to the noncontrolling shareholders that was required to be recognized by us

	•		Loss of $14 million on the sale of Metrogas available-for-sale securities in the second quarter of 2008

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	•		Gain of $57 million on the settlement of the nationalization of Transredes in the second quarter of 2008

	•		Gain of $68 million, or $12 million net of tax and noncontrolling interests, on the sale of Gazel in exchange for additional ownership interest in SIE in the first quarter of 2008

Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007

The following discussion compares our results of continuing operations for the year ended December 31, 2008 to the year ended December 31, 2007.

On November 15, 2007, we completed the sale, through a holding company, of 98.16% of Vengas (constituting our entire interest in Vengas) for $73 million in cash. We recorded a gain of $41 million in the fourth quarter of 2007 for which no taxes were recorded due to certain exemptions under the holding company’s tax status. We reported Vengas operating results as discontinued operations in 2007 and 2006.

Revenues

The table below presents revenues of our consolidated subsidiaries by significant geographical location for the years ended December 31, 2008 and 2007. Revenues are recorded in the country in which they are earned. Intercompany revenues between countries have been eliminated in Other and eliminations below.


	For the Years
	Ended
	December 31,
	2008			2007

Andean
Colombia	$	3,926		$	563
Chile		1,311			—
Other countries		219			37

Subtotal		5,456			600

Southern Cone
Brazil		1,503			1,406
Argentina		122			52
Other countries		21			21

Subtotal		1,646			1,479

Central America/Caribbean
Panama		808			389
El Salvador		172			97
Guatemala		206			168
Other countries		384			177

Subtotal		1,570			831

Europe/Middle East/North Africa
Turkey		416			337
Other countries		123			93

Subtotal		539			430

China		104			8

Other and eliminations		(104	)		(132	)

Total	$	9,211		$	3,216

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The following table reflects revenues by segment:


	For the Years Ended December 31,
	2008			2007
	Millions of dollars (U.S.)
Power Distribution	$	2,217		$	1,746
Power Generation		1,175			874
Natural Gas Transportation and Services		202			199
Natural Gas Distribution		584			352
Retail Fuel		5,137			160
Headquarters/Other/Eliminations		(104	)		(115	)

Total revenues	$	9,211		$	3,216

Revenues increased by $5,995 million to $9,211 million for the year ended December 31, 2008 compared to $3,216 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE ($4,959 million) during 2008, the acquisitions made during 2007 and 2008 ($407 million), and the increase in revenues at Elektro ($168 million), Elektra ($159 million), Promigas and its subsidiaries ($156 million), Trakya ($79 million) and San Felipe ($72 million), partially offset by the decrease in revenues at EPE ($52 million) and TBS ($20 million), and the sale of Bahía Las Minas Corp, or BLM, ($31 million) as described below.

Power Distribution

Revenues from the Power Distribution segment increased by $471 million to $2,217 million for the year ended December 31, 2008 compared to $1,746 million for the year ended December 31, 2007. The increase was primarily due to the increased revenues at Elektro ($168 million) and Elektra ($159 million) and the acquisitions of Delsur, ($68 million) and EDEN ($56 million) during 2007. The increased revenues at Elektro were primarily due to the appreciation of the Brazilian real relative to the U.S. dollar ($99 million), additional revenue recognition ($55 million) as a result of regulatory determinations made by ANEEL, and higher sales volumes ($33 million) as a result of an increased customer base, partially offset by a revenue decrease caused by a 2007 tax credit ($11 million). The increase in revenues due to regulatory determinations was related to a tariff adjustment ($15 million) as a result of the 2007 tariff review performed by ANEEL in August 2008, transmission costs ($19 million) to be collected from the generators and passed through to transmission companies as a result of the determination made by ANEEL, and the modification of a regulation for low income customers, by ANEEL in July 2008, reversing the accrual previously recorded in 2007 ($21 million). The increased revenues at Elektra were primarily due to higher pricing ($146 million) as a result of the monthly and bi-annual tariff adjustments to the energy cost component of its customer tariff (driven by higher fuel cost) and increased usage ($11 million) resulting from an expanding customer base.

Power Generation

Revenues from the Power Generation segment increased by $301 million to $1,175 million for the year ended December 31, 2008 from $874 million for the year ended December 31, 2007. The increase was primarily due to additional revenues from the acquisition of interests in JPPC ($59 million), Corinto ($53 million), Luoyang ($30 million), Tipitapa ($29 million) and DCL ($5 million), and the increased revenues at Trakya ($79 million), San Felipe ($72 million), PQP ($38 million) and ENS ($25 million), partially offset by decreased revenues at EPE ($52 million) and a decrease of $31 million as a result of the sale of BLM in March 2007. Increased revenues at San Felipe and PQP were primarily due to higher fuel costs which were passed on to their customers and higher usage of the plants’ capacity. Increased revenues at Trakya were primarily due to higher fuel costs which were passed on to its customers, partially offset by decreased generation volume as a result of major plant maintenance in the second quarter of 2008. Increased revenues at ENS were primarily due to the compensation of stranded cost and gas related cost from the Polish government and the appreciation of the Polish zloty relative to the U.S. dollar. Revenues at EPE decreased by $52 million as a result of gas curtailments that the plant experienced during the last quarter of 2007 that continued through the end of 2008.

Natural Gas Transportation and Services

Revenues from the Natural Gas Transportation and Services segment increased by $3 million to $202 million for the year ended December 31, 2008 compared to $199 million for the year ended December 31, 2007. The increase was primarily due to higher revenues generated at Promigas and its subsidiaries ($22 million) as a result of higher customer demand, increased tariffs, new contracts obtained in 2008 and the appreciation of the Colombian peso relative to the U.S. dollar for the year ended December 31, 2008 compared to the same period of 2007, partially offset by the decreased revenues at TBS ($20 million) as a result of gas curtailments that occurred during the last quarter of 2007 and continued through the end of 2008.

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Natural Gas Distribution

Revenues from the Natural Gas Distribution segment increased by $232 million to $584 million for the year ended December 31, 2008 compared to $352 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of Tongda in August 2007 and BMG in January 2008 (totaling $66 million), the acquisition of Cálidda in June 2007 ($41 million), and the increased revenues ($116 million) at Promigas’ subsidiaries as a result of higher distribution volumes due to higher customer demand, increased customer base and higher wellhead prices which were passed on to their customers.

Retail Fuel

Revenues from the Retail Fuel segment increased by $4,977 million to $5,137 million for the year ended December 31, 2008 compared to $160 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($4,959 million). The remaining increase was due to the increased revenues at Promigas’ subsidiary Gazel as a result of the increased cost of natural gas passed on to its customers and the appreciation of the Colombian peso relative to the U.S. dollar for the year ended December 31, 2008 compared to the same period of 2007.

Costs of sales

The following table reflects costs of sales by segment:


	For the Years Ended December 31,
	2008			2007
	Millions of dollars (U.S.)
Power Distribution	$	1,374		$	963
Power Generation		984			610
Natural Gas Transportation and Services		13			36
Natural Gas Distribution		386			224
Retail Fuel		4,697			90
Headquarters/Other/Eliminations		(107	)		(127	)

Total costs of sales	$	7,347		$	1,796

Costs of sales increased by $5,551 million to $7,347 million for the year ended December 31, 2008 compared to $1,796 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE ($4,611 million) during 2008, the acquisitions made during 2007 and 2008 ($299 million), and the increase in costs of sales at Elektro ($159 million), Elektra ($154 million), San Felipe ($102 million), Trakya ($94 million), Promigas and its subsidiaries ($82 million) and PQP ($65 million), partially offset by the decrease in costs of sales at EPE ($25 million) and TBS ($19 million) and the sale of BLM ($26 million) as described below.

Power Distribution

Costs of sales for the Power Distribution segment increased by $411 million to $1,374 million for the year ended December 31, 2008 compared to $963 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of Delsur ($49 million) and EDEN ($31 million) during the second quarter of 2007 and the increased costs of sales at Elektro ($159 million) and Elektra ($154 million). The increased costs of sales at Elektro were primarily due to an increase in the average price of purchased electricity as a result of the overall increase in energy prices ($85 million), the appreciation of the Brazilian real ($41 million) and an increase in volumes purchased ($3 million) as a result of higher sales volumes, and additional costs of sales recognition ($38 million) as a result of recent regulatory determinations made by ANEEL, partially offset by a tax credit of $8 million on costs of sales. The increase in costs of sales due to regulatory determinations was related to a tariff adjustment ($20 million) as a result of the 2007 tariff review performed by ANEEL in August 2008 and the transmission costs ($18 million) to be collected from the generators and passed through to transmission companies as a result of the determination made by ANEEL. The increased costs of sales at Elektra were a result of higher average price of purchased electricity ($146 million) due to increased fuel costs and an increase in volumes purchased ($8 million).

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Power Generation

Costs of sales for the Power Generation segment increased by $374 million to $984 million for the year ended December 31, 2008 compared to $610 million for the year ended December 31, 2007. The increase was primarily due to the acquisition of interests in Corinto ($46 million), JPPC ($46 million), Luoyang ($36 million), Tipitapa ($24 million) and DCL ($2 million), and the increased costs of sales at San Felipe ($102 million), Trakya ($94 million) and PQP ($65 million), partially offset by the decreased costs of sales at EPE ($25 million) and the sale of BLM ($26 million) in March 2007. The increased costs of sales at San Felipe were primarily due to increased fuel prices and higher usage of plant capacity; the increased costs of sales at PQP were primarily due to the increased fuel prices and the increased purchase of electricity from the spot market to fulfill its PPA; the increased costs of sales at Trakya were primarily due to increased fuel prices, partially offset by lower usage of plant capacity as a result of major plant maintenance performed in the second quarter of 2008; the decreased costs of sales at EPE were a result of gas curtailments that the plant experienced during the last quarter of 2007 that continued through the end of 2008.

Natural Gas Transportation and Services

Costs of sales for the Natural Gas Transportation and Services segment decreased by $23 million to $13 million for the year ended December 31, 2008 compared to $36 million for the year ended December 31, 2007. The decrease was primarily due to a decrease in costs of sales at TBS as a result of gas supply curtailments that occurred during the last quarter of 2007 and continued through the end of 2008.

Natural Gas Distribution

Costs of sales for the Natural Gas Distribution segment increased by $162 million to $386 million for the year ended December 31, 2008 compared to $224 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of Tongda in August 2007 and BMG in January 2008 ($39 million), the acquisition of Cálidda in June 2007 ($26 million), and the increased costs of sales ($91 million) at Promigas’ subsidiaries as a result of higher customer demand, market growth, higher natural gas wellhead prices and the appreciation of the Colombian peso relative to the U.S. dollar for the year ended December 31, 2008 compared to the same period of 2007.

Retail Fuel

Costs of sales for the Retail Fuel segment increased by $4,607 million to $4,697 million for the year ended December 31, 2008 compared to $90 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($4,611 million).

Gross Margin


	For the Years Ended December 31,
	2008		2007
	Millions of dollars (U.S.)
Power Distribution	$	843	$	783
Power Generation		191		264
Natural Gas Transportation and Services		189		163
Natural Gas Distribution		198		128
Retail Fuel		440		70
Headquarters/Other/Eliminations		3		12

Total gross margin	$	1,864	$	1,420

Gross margin increased by $444 million to $1,864 million for the year ended December 31, 2008 compared to $1,420 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE ($348 million) during 2008, the acquisitions made during 2007 and 2008 ($108 million) and the increased gross margin at Promigas and its subsidiaries ($73 million), partially offset by the decreased gross margin at certain Power Generation operating companies ($90 million) as described below.

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Power Distribution

Gross margin for the Power Distribution segment increased by $60 million to $843 million for the year ended December 31, 2008 compared to $783 million for the year ended December 31, 2007. The increase in gross margin was primarily due to the acquisitions of Delsur ($19 million) and EDEN ($25 million) during the second quarter of 2007 and the increased gross margin at Elektro ($9 million). The increased gross margin at Elektro was primarily due to the net favorable impact of the additional recognition of both revenues and costs of sales as a result of regulatory determinations made by ANEEL as discussed above.

Power Generation

Gross margin for the Power Generation segment decreased by $73 million to $191 million for the year ended December 31, 2008 compared to $264 million for the year ended December 31, 2007. The decrease in gross margin was primarily due to the decreased gross margin at San Felipe ($30 million), EPE ($27 million), PQP ($27 million), Trakya ($15 million) and BLM ($5 million) as a result of the sale of BLM in March 2007, partially offset by the additional gross margin from the acquisitions of JPPC ($13 million), Corinto ($7 million), Tipitapa ($5 million) and DCL ($3 million). The decreased gross margin at San Felipe was primarily due to the timing of recognition of pass-through costs under the PPA structure. Under the PPA, the revenue pricing is based on the costs incurred for a portion of the heavy fuel used in generation on an approximate one-year lag, while the costs of sales are based on current fuel prices (which are generally higher in 2008 compared to 2007). The decreased gross margin at EPE was a result of gas curtailments that the plant experienced during the last quarter of 2007 that continued through the end of 2008. The decreased gross margin at PQP was primarily due to the higher purchase of electricity from spot market to fulfill its PPA. The decreased gross margin at Trakya was primarily due to lower generation volume in 2008 as a result of a major plant maintenance performed during the second quarter of 2008.

Natural Gas Transportation and Services

Gross margin for the Natural Gas Transportation and Services segment increased by $26 million to $189 million for the year ended December 31, 2008 compared to $163 million for the year ended December 31, 2007. The increase was primarily at Promigas and its subsidiaries ($26 million) as a result of higher customer demand, increased tariffs, new contracts obtained in 2008 and the appreciation of the Colombian peso relative to the U.S. dollar based on the average rate for the twelve month comparison periods.

Natural Gas Distribution

Gross margin for the Natural Gas Distribution segment increased by $70 million to $198 million for the year ended December 31, 2008 compared to $128 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of Tongda in August 2007 and BMG in January 2008 (totaling $27 million), the acquisition of Cálidda in June 2007 ($15 million), and the increased gross margin ($25 million) at Promigas’ subsidiaries as a result of higher distribution volumes due to higher customer demand and increased customer numbers.

Retail Fuel

Gross margin for the Retail Fuel segment increased by $370 million to $440 million for the year ended December 31, 2008 compared to $70 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($348 million).

Operating Expenses

Operations, Maintenance and General and Administrative Expenses

The following table reflects operations, maintenance and general and administrative expenses by segment:

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	For the Years Ended December 31,
	2008		2007
	Millions of dollars (U.S.)
Power Distribution	$	323	$	241
Power Generation		123		118
Natural Gas Transportation and Services		62		57
Natural Gas Distribution		82		49
Retail Fuel		215		33
Headquarters/Other/Eliminations		89		132

Total operations, maintenance and general and administrative expenses	$	894	$	630

Operations, maintenance and general and administrative expenses increased by $264 million to $894 million for the year ended December 31, 2008 compared to $630 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE during 2008 ($173 million), the acquisitions made during 2007 and 2008 ($71 million), and the increased operations, maintenance and general and administrative expenses at Elektro ($48 million) as described below, partially offset by the decreased operations, maintenance and general and administrative expenses at EPE ($15 million) due to reduced generation activity as a result of the curtailment of gas supply and headquarters ($46 million) as a result of decreased professional services fees and decreased stock compensation expenses related to the 2004 stock and long-term incentive plans that fully vested in 2007.

Power Distribution

Operations, maintenance and general and administrative expenses for the Power Distribution segment increased by $82 million to $323 million for the year ended December 31, 2008 compared to $241 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of EDEN ($17 million) and Delsur ($9 million) during the second quarter of 2007 and the increased operations, maintenance and general and administrative expenses at Elektro ($48 million). The increase in these expenses at Elektro was primarily due to increased contingency expenses ($18 million) related to tax and civil claims contingencies (see Note 25 to the consolidated financial statements), the appreciation of the Brazilian real relative to the U.S. dollar ($19 million), and increased payroll expenses ($5 million) as a result of the annual union agreement effective in June 2008.

Power Generation

Operations, maintenance and general and administrative expenses for the Power Generation segment increased by $5 million to $123 million for the year ended December 31, 2008 compared to $118 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of JPPC, Luoyang, Corinto, Tipitapa, Fenix, Jaguar and DCL ($26 million total), partially offset by the decreased operations, maintenance and general and administrative expenses at EPE ($15 million) and San Felipe ($7 million) and the sale of BLM ($2 million) in March 2007. Expenses at EPE decreased by $15 million due primarily to gas curtailments that the plant experienced during the last quarter of 2007 that continued through the end of 2008; these expenses at San Felipe decreased by $7 million due primarily to lower maintenance expenses in 2008.

Natural Gas Transportation and Services

Operations, maintenance and general and administrative expenses for the Natural Gas Transportation and Services segment increased by $5 million to $62 million for the year ended December 31, 2008 compared to $57 million for the year ended December 31, 2007. The increase was primarily due to the increased operations, maintenance and general and administrative expenses at Promigas as a result of higher pipeline maintenance expenses and the appreciation of the Colombian peso relative to the U.S. dollar for the year ended December 31, 2008 compared to the same period of 2007.

Natural Gas Distribution

Operations, maintenance and general and administrative expenses for the Natural Gas Distribution segment increased by $33 million to $82 million for the year ended December 31, 2008 compared to $49 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of Tongda in August 2007 and BMG in January 2008 ($13 million), the acquisition of Cálidda ($6 million) in June 2007, and the increased operations, maintenance and general and administrative expenses at Promigas’ subsidiaries ($13 million) as a result of higher advertising, operating and payroll expenses due to higher customer demand and an expanded customer base.

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Retail Fuel

Operations, maintenance and general and administrative expenses for the Retail Fuel segment increased by $182 million to $215 million for the year ended December 31, 2008 compared to $33 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($173 million) and the increased operations, maintenance and general and administrative expenses at Promigas’ subsidiary Gazel ($9 million) as a result of an increased number of retail fuel service stations.

Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the Years Ended December 31,
	2008		2007
	Millions of dollars (U.S.)
Power Distribution	$	138	$	139
Power Generation		24		42
Natural Gas Transportation and Services		21		20
Natural Gas Distribution		18		8
Retail Fuel		61		3
Headquarters/Other		6		5

Total depreciation and amortization expenses	$	268	$	217

Total depreciation and amortization expenses increased by $51 million to $268 million for the year ended December 31, 2008 compared to $217 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE ($46 million), the acquisitions made during 2007 and 2008 ($24 million), and the increased depreciation and amortization expense at Promigas’ subsidiary Gazel ($12 million) as a result of an increased number of retail fuel service stations, partially offset by an increase at San Felipe ($15 million) due to accretion of the intangible liability associated with the PPA based on the generated volumes produced by the plant, an increase at Elektro ($5 million) due to the amortization to income of a special obligation authorized by ANEEL since September 2007 (see Note 17 to the consolidated financial statements), a decrease in amortization expenses at ENS ($8 million) due to the voluntary termination of its long-term PPA which was accounted for as amortizable intangibles, and the sale of BLM in March 2007 ($1 million).

Other Charges

During the years ended December 31, 2008 and 2007, we recorded other charges totaling $56 million and $50 million ($25 million after tax and noncontrolling interests), respectively. As a result of the current arbitration on the EPE PPA and the continuing lack of a gas supply contract for the EPE plant, in the third quarter of 2008, we recorded an additional charge totaling $44 million ($30 million after tax and noncontrolling interests). During the fourth quarter of 2008, we recorded a $12 million impairment of our $16 million cost method investment in SES. See Note 4 to the consolidated financial statements. The charge in 2007 relates exclusively to the EPE arbitration.

(Gain) Loss on Disposition of Assets

During the year ended December 31, 2008 and 2007, we recorded net gains on disposition of assets totaling $93 million and $21 million, respectively. During 2008, we recognized a gain of $68 million ($12 million after tax and noncontrolling interests) on the sale of 46% of Gazel to noncontrolling shareholders of SIE when exchanged for the additional interest in SIE and a gain of $57 million on the nationalization of Transredes, which was partially offset by a loss of $14 million on the sale of debt securities of GASA and a loss of $18 million on the sale of operating equipment. See Notes 3, 5, 11 and 13 to the consolidated financial statements. During 2007, we recognized a gain of $21 million on the sale of the 51% interest in BLM in March 2007.

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Equity Income from Unconsolidated Affiliates

The following table reflects equity income from unconsolidated affiliates by segment:


	For the Years Ended December 31,
	2008			2007
	Millions of dollars (U.S.)
Power Distribution	$	68		$	2
Power Generation		12			11
Natural Gas Transportation and Services		27			39
Natural Gas Distribution		11			13
Retail Fuel		1			11
Headquarters/Other/Eliminations		(2	)		—

Total equity income from unconsolidated affiliates	$	117		$	76

Equity income from unconsolidated affiliates increased by $41 million to $117 million for the year ended December 31, 2008 compared to $76 million for the year ended December 31, 2007. The increase was primarily due to the increased equity income of $66 million in the Power Distribution segment as a result of the investments in Chilquinta and Luz del Sur acquired in the fourth quarter of 2007, partially offset by the decreased equity income of $12 million in the Natural Gas Transportation and Services segment primarily caused by the nationalization of Transredes and the decreased equity income of $10 million in the Retail Fuel segment primarily caused by the consolidation of SIE which was an equity investment in 2007.

Operating Income

As a result of the factors discussed above, our operating income for the year ended December 31, 2008 increased by $236 million to $813 million compared to $577 million for the year ended December 31, 2007. The following table reflects the contribution of each segment to operating income in both periods:


	For the Years Ended December 31,
	2008			2007
	Millions of dollars (U.S.)
Power Distribution	$	427		$	373
Power Generation		15			77
Natural Gas Transportation and Services		128			128
Natural Gas Distribution		104			85
Retail Fuel		218			49
Headquarters/Other/Eliminations		(79	)		(135	)

Total operating income	$	813		$	577

Interest Income

Interest income decreased by $22 million to $88 million for the year ended December 31, 2008 compared to $110 million for the year ended December 31, 2007. Of the interest income earned during 2008 and 2007, 51% and 53%, respectively, was related to Elektro, whose interest income is primarily related to short-term investments and interest on amounts owed by delinquent or financed customers. The decrease at Elektro, as well as the overall decrease, was primarily due to a lower level of cash invested.

Interest Expense

Interest expense increased by $72 million to $378 million for the year ended December 31, 2008 compared to $306 million for the year ended December 31, 2007. The increase was primarily due to the additional interest expense at the operating companies as a result of acquisitions made during the year of 2007 and 2008 ($34 million), the consolidation of SIE ($46 million), partially offset by the decreased interest expense at the parent level. Interest expense at the parent level decreased by $8 million to $135 million due primarily to lower interest rates, partially offset by higher borrowings to finance acquisitions.

Foreign Currency Transaction Gain (Loss), Net

Total foreign currency transaction losses were $56 million ($19 million after tax and noncontrolling interests) for the year ended December 31, 2008 compared to foreign currency transaction gains of $19 million ($5 million after tax and noncontrolling interests) for the year ended December 31, 2007. During 2008, foreign currency transaction losses of $31 million were primarily associated with the effects of the devaluation of the Colombian peso relative to the U.S. dollar on a $250 million U.S. dollar-denominated debt instrument held by one of Promigas’ subsidiaries; foreign currency transaction losses of $17 million at EPE were primarily due to the devaluation of a portion of the lease investments as a result of the devaluation of the Brazilian real relative to the U.S. dollar; and foreign currency transaction losses of $8 million at Trakya were primarily due to the devaluation of Turkish lira denominated assets as a result of the devaluation of Turkish lira relative to the U.S. dollar for the year ended December 31, 2008. During 2007, foreign currency transaction gains of $21 million at EPE were primarily associated with lease investment receivable and customer receivable balances denominated in Brazilian real.

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Loss on Early Retirement of Debt

Loss on early retirement of debt was $33 million for the year ended December 31, 2007 as a result of the refinancing of the senior credit facility, including additional revolving credit facilities, and the redemption of PIK Notes at the parent level.

Other Income (Expense), net

Other income of $9 million was recognized for the year ended December 31, 2008 compared to other expenses of $22 million for the year ended December 31, 2007. During 2008, other income of $9 million included dividend income of $3 million from TBG. The $22 million of other expense recognized in 2007 included a loss of $14 million associated with foreign currency derivative transactions at the parent company.

Provision for Income Taxes

We are a Cayman Islands company, which is not subject to income tax in the Cayman Islands. We operate through various subsidiaries in a number of countries throughout the world. Income taxes have been provided for based upon the tax laws and rates of the countries in which operations are conducted and income is earned. The provision for income taxes for the years ended December 31, 2008 and 2007 was $194 million and $193 million, respectively. The estimated effective income tax rate for the years ended December 31, 2008 and 2007 was 41% and 56%, respectively, which was higher than the statutory rate primarily due to losses generated by us and our Cayman Islands subsidiaries and other holding companies’ jurisdictions for which no tax benefit has been provided. For the year ended December 31, 2008, the impact on the effective tax rate of the write-down related to EPE and SES, which are not benefited for tax purposes, was offset by the non-taxable nature of the SIE and Transredes gains.

Noncontrolling Interests

Net income — noncontrolling interests increased by $59 million to $124 million for the year ended December 31, 2008 compared to $65 million for the year ended December 31, 2007. The increase was primarily due to higher income before taxes and the impact of the noncontrolling interests share ($55 million) of the Promigas gain on its sale of 46% of Gazel to noncontrolling shareholders of SIE. Net income — noncontrolling interests in 2008 does not include $13 million of losses at Luoyang otherwise attributable to the noncontrolling shareholder that are required to be recognized by us. Recognition of the losses by the noncontrolling shareholder would have resulted in a negative noncontrolling interest balance.

Net Income Attributable to AEI

As a result of the factors discussed above, net income attributable to AEI increased $27 million for the year ended December 31, 2008 to $158 million compared to net income attributable to AEI of $131 million for the year ended December 31, 2007.

B. Liquidity and Capital Resources

Overview

We are a holding company that conducts all of our operations through subsidiaries. We finance our activities through a combination of senior debt, subordinated debt and equity at the AEI level and non-recourse and limited recourse debt at the subsidiary level. We have used non-recourse debt at the subsidiary level to fund a significant portion of the capital expenditures and investments required to construct and acquire power distribution, power generation, retail fuel outlets and natural gas distribution and transportation companies and power plants. Most of our financing at the subsidiary level is non-recourse to our other subsidiaries, our affiliates and us, as the parent company, and is generally secured on a case-by-case basis by a combination of the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. The terms of the subsidiaries’ long-term debt include

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certain financial and non-financial covenants that are limited to the subsidiaries that incurred that debt. These covenants include, but are not limited to, achievement of certain financial ratios, limitations on the payment of dividends unless covenants and financial ratios are met, minimum working capital requirements, and maintenance of reserves for debt service and for major maintenance. A default by certain subsidiaries under the agreements governing their debt could under some circumstances trigger a cross default under our senior secured loan facility. See “— Parent Company Long-term Debt.” We raise local currency or U.S. dollar-denominated debt to match the cash flow of each business as appropriate.

In addition, we, as the parent company, provide a portion, or in some instances all, of the remaining long-term financing or credit to fund development, construction or acquisition. These investments generally take the form of equity investments or shareholder loans, which are subordinated to non-recourse loans at the project level. In addition, for greenfield construction projects, we may provide funding, credit, obtain financing at the subsidiary level or enter into agreements with additional equity investors in the projects.

At December 31, 2009, we had $1,290 million of recourse debt and $2,428 million of non-recourse debt outstanding. For more information on our long-term debt, see Note 15 to the consolidated financial statements.

We intend to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our subsidiaries and affiliates may develop, construct or acquire. However, depending on market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms. As a result of the turmoil in the financial markets in 2008 and 2009, many lenders and investors ceased to provide funding for a period of time. If we decide not to provide any additional funding or credit support to a subsidiary and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent and we may lose our investment in such subsidiary.

We are rated BB by Fitch Ratings, B+ by Standard & Poor’s Ratings Services and B1 by Moody’s Investors Services. The majority of our subsidiaries and the countries in which they operate have received investment grade rating. As a result of our below-investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, for both new and existing commitments, we may be required to provide a form of assurance, such as a letter of credit, to backstop or replace our credit support. We may not be able to provide adequate assurances to such counterparties. In addition, 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 liquidity needs. As of December 31, 2009, we and certain of our subsidiaries had entered into letters of credit, bank guarantees, and performance bonds with balances of $379 million issued of which $11 million of the total facility balances were fully cash collateralized. Additionally, as of December 31, 2009, lines of credit of $416 million were outstanding, with an additional $532 million available.

As of December 31, 2009, we had $682 million of total cash and cash equivalents on a consolidated basis, of which $7 million was at the parent company level, $578 million was at our consolidated operating businesses, and the remaining $97 million was at consolidated holding and service companies. See Note 7 to the consolidated financial statements.

We expect our sources of liquidity at the parent level to include:

	•		cash generated from our operations received in the form of dividends, capital returns, interest and principal payments on intercompany loans and shareholder loans from our businesses;

	•		borrowing under our credit facilities, including a $500 million revolving credit facility, $218 million of which was drawn as of December 31, 2009;

	•		future debt and subordinated debt offerings;

	•		issuance of additional equity; and

	•		fees from management contracts.

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We believe that the cash generated from these sources will be sufficient to meet our requirements for short-term working capital and long-term capital expenditures. Our ability to invest in new projects or make acquisitions may be constrained in the event external financing is not available. Cash requirements at the parent company level are primarily to fund:

	•		interest expense;

	•		principal repayments of debt;

	•		acquisitions;

	•		investment in new and existing projects including greenfield development; and

	•		parent company overhead and development costs.

The amount of cash generated by our businesses may be affected by, among other things, contractual terms and changes in tariff rates. Payments under certain contracts are designed with larger upfront capacity fixed payments to repay the original debt financing and lower payments during the remainder of the contract term. The tariffs of our regulated businesses, particularly those in the Power Distribution, Natural Gas Transportation and Services and Natural Gas Distribution segments, are periodically reviewed by regulators. These tariffs are reset at the review dates generally based on certain forward-looking parameters such as energy sales and purchases, capital expenditures, operations and maintenance expenses and selling, general and administrative expenses. A business’ returns in the period following a tariff reset may exceed those defined in the applicable regulations depending on the business’ performance following a tariff review, as well as factors out of the business’ control, such as the level of electricity or natural gas consumption. As a result, the tariff reviews may result in tariff reductions to reset the business’ returns back to the regulated return levels.

Further, the amount of cash generated by our businesses may be affected by changes in working capital availability. For example, if the primary fuel supply of our Power Generation businesses were impeded or curtailed, their ability to operate using alternate fuel (gasoil) may be limited by their current inventory of gasoil and/or by working capital constraints.

Capital Expenditures

Capital expenditures were $441 million, $372 million and $249 million in 2009, 2008 and 2007, respectively, of which $140 million, $145 million and $137 million, in 2009, 2008 and 2007, respectively, correspond to capital expenditures at Elektro. Capital expenditures for 2009, 2008 and 2007 also include $140 million, $113 million and $50 million, respectively, associated with Promigas, Proenergía and their consolidated subsidiaries. For 2009, capital expenditures comprised $169 million of maintenance capital expenditures, $161 million of regulatory capital expenditures which are required by the regulators or by contract, but contribute to future revenue growth, with the remainder of $111 million of capital expenditures related to growth projects. For 2010, capital spending is expected to total $1,054 million, of which $67 million, $114 million, $210 million and $383 million correspond to capital expenditures at Promigas (including its consolidated subsidiaries), Proenergía (including its consolidated subsidiaries), Elektro and development projects (Jaguar and Fenix), respectively. Planned capital expenditures for 2010 include capital spending on expansions of the asset base in the Power Distribution, Natural Gas Distribution particularly at Cálidda, Natural Gas Transportation and Services and Retail Fuel segments, new project construction expenditures in the Power Generation segment and maintenance expenditures related to existing assets across all segments. These capital expenditures are expected to be financed using a combination of cash provided by the businesses’ operations, business level financing and equity contributions from shareholders.

Cash Flows for the Years Ended December 31, 2009 and December 31, 2008

Cash Flows from Operating Activities

Cash provided by operating activities was $821 million in 2009 compared to $508 million in 2008 representing an increase of $313 million. Cash provided by operating activities before consideration of working capital, regulatory assets and liabilities and other changes was $757 million in 2009 compared to $585 million in 2008. The increase in

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cash flows from operating activities excluding working capital, regulatory and other changes of $172 million was due primarily to higher profitability resulting in more net income after excluding the impact of the noncash impairment charge on the Cuiabá Integrated Project during the fourth quarter of 2009 and noncash losses on disposition of assets in 2009 and gains in 2008. The total change in working capital, excluding regulatory assets and liabilities and other, in 2009 was a net inflow of $21 million, while the total change in working capital in the prior year was an outflow of $76 million. The improvement on cash flow from working capital was primarily due to the increased collectability on accounts receivable in the Power Generation segment. Net regulatory assets decreased during 2009 by $32 million compared to an increase in 2008 of $32 million. The change in net regulatory assets reflects the timing lags in collection of pass-through of energy costs.

Cash Flows from Investing Activities

Cash used in investing activities for the year ended December 31, 2009 was $559 million compared to $414 million for the year ended December 31, 2008. During 2009, we received the second payment of $60 million from YPFB related to the sale of our investment in Transredes. During 2008, we received proceeds of $38 million from the sale of interests in debt securities of GASA and the first payment of $60 million from YPFB related to the sale of our investment in Transredes. Capital expenditures increased by $69 million to $441 million in 2009 compared to $372 million in 2008 due to expansion in our asset base and new project construction during 2009. We paid cash of $171 million for the acquisitions of EMDERSA and an additional equity interest in Emgasud, GTB and TBG in 2009, compared to $253 million in 2008 for the acquisitions of Luoyang, Fenix, Tipitapa, DCL, Emgasud and additional interests in BMG and subsidiaries of Promigas. During 2009, there was $18 million of cash and cash equivalents acquired compared to $60 million in 2008 from the acquisitions noted above. Restricted cash increased by $256 million during 2009 primarily at Elektro and EPE. Elektro issued 300 million Brazilian reais non-convertible debentures (see Note 15 to our consolidated financial statements), requiring the restriction on cash; EPE increased its restricted cash associated with the energy capacity payments received from Furnas (see Note 7 to our consolidated financial statements). Restricted cash decreased by $265 million during 2009 primarily at Elektro, Cálidda and a Chilquinta holding company. Elektro and Cálidda repaid part of their debt (see Note 15 to our consolidated financial statements), releasing the restriction on cash; Chilquinta refinanced its long-term debt, releasing the restriction on cash held by a Chilquinta holding company. During 2009, the Company contributed $9 million to Proenergía and Promigas’ unconsolidated investments for project expansion. Additionally, during 2009, the Company purchased a $15 million senior unsecured convertible note due in July 2012 from one of its unconsolidated investments (Emgasud); Promigas and its subsidiaries purchased $18 million of marketable securities and $22 million of other short-term investments and received the proceeds of $22 million from the matured held-to-maturity debt securities; Proenergía received the proceeds of $7 million from the matured short-term investments.

Cash Flows from Financing Activities

Cash used in financing activities for the year ended December 31, 2009 was $370 million compared to $173 million of cash provided by financing activities for the year ended December 31, 2008. During 2009, Promigas and, subsequent to the spin-off, Proenergía refinanced $250 million of U.S. dollar-denominated debt through Colombian peso denominated notes and $256 million of Colombian peso denominated notes; Promigas issued Colombian peso denominated bonds, Colombian peso denominated notes and U.S. dollar-denominated notes totaling $329 million, repaid $196 million of its Colombian peso notes and $42 million of its U.S. dollar notes, and refinanced $23 million of its Colombian peso notes; Elektro issued unsecured commercial paper totaling 120 million Brazilian reais (approximately U.S. $61 million) and non-convertible debentures in the amount of 300 million Brazilian reais (approximately U.S. $152 million) and used proceeds from the issuance to repay its unsecured commercial paper and debentures that matured in 2009; Trakya issued $80 million in unsecured U.S. dollar-denominated notes; we repaid $558 million and withdrew $234 million under our senior credit facility and revolving credit facility; Cálidda repaid its subordinated loan of $47 million with funds provided through an intercompany loan with its shareholders, us and Promigas. In addition, during 2009, we paid $90 million in total to acquire an additional 31% ownership interest in Trakya, 50% ownership interest in the Cuiabá Integrated Project, and 27.09% ownership interest in EMDERSA subsequent to consolidation of EMDERSA from noncontrolling interest shareholders. During 2008, the Company sold 12.5 million of its ordinary shares to Buckland, and received $200 million in proceeds; Elektra issued corporate bonds; Delsur refinanced its $100 million bridge loan; and Promigas refinanced various credit facilities for the financing of capital expenditures. In addition, we used a portion of the stock issuance proceeds previously mentioned to repay a portion of our revolving credit facility and to make dividend payments to noncontrolling shareholders of the operating companies, and Trakya paid off all of its long-term debt. We paid $70 million and $167 million in dividends to noncontrolling shareholders in 2008 and 2009, respectively.

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Cash Flows for the Years Ended December 31, 2008 and December 31, 2007

Cash Flows from Operating Activities

Cash provided by operating activities decreased by $178 million to $508 million for the year ended December 31, 2008 from $686 million for the same period in 2007. The decrease in cash flows from operating activities is the combined result of a $170 million cash outflow related to working capital builds and other net increases in operating assets and liabilities and a decrease of $8 million in net income after removing non-cash items, including equity income, from unconsolidated affiliates that was not distributed, other charges and the gain on the SIE transaction. The increased cash outflow of $170 million in operating assets and liabilities was primarily due to the decrease in revenue receipts at Elektro as a result of the average tariff decrease in 2008, the increase in accounts receivable at ENS associated with the accrued compensation of stranded cost and gas-related cost from the Polish government and the decrease in accounts payable at Elektra due to lower energy costs during the fourth quarter of 2008 compared to the same period in 2007, partially offset by an increase in accrued liabilities. Additionally, Elektro’s regulatory assets increased as a result of higher energy cost and its regulatory liabilities decreased as result of the reversal of regulatory liabilities associated with the modification of a regulation for lower income customers by ANEEL in July 2008, which have been accrued since 2007.

Cash Flows from Investing Activities

Cash used in investing activities decreased by $737 million to $414 million for the year ended December 31, 2008 from $1,151 million for the same period in 2007. Capital expenditures increased by $123 million in the year ended December 31, 2008 due to expansion in the asset base and new project construction during 2008. Capital expenditures in 2008 include maintenance capital expenditures of $129 million. Cash paid for acquisitions was $253 million in 2008 for the interests in BMG, Luoyang, Fenix, Tipitapa, DCL, Emgasud and Promigas’ additional interests in certain subsidiaries. This is compared to $1,111 million in the same period in 2007 for the acquisitions of Cálidda, EDEN, Delsur, Tongda, Corinto, BMG, JPPC, Chilquinta and POC and the additional interests in San Felipe and PQP. Additionally, in 2008, cash and cash equivalents of $60 million were acquired compared to $21 million in the same period in 2007. During 2008, restricted cash has a net decrease of $78 million due primarily to the release of restricted cash at Trakya upon the repayment of its long-term debt in the third quarter of 2008. Activities in 2008 and 2007 also included proceeds of $38 million from the sale of the Metrogas available-for-sale securities and proceeds of $48 million from the sale of BLM, respectively.

Cash Flows from Financing Activities

Cash provided by financing activities for the year ended December 31, 2008 was $173 million compared to $88 million for the year ended December 31, 2007. In May 2008, we sold 12.5 million of our ordinary shares to Buckland and received $200 million in proceeds. Additionally, during 2008, Elektro did not execute call options and tender offers on its debentures as it had in 2007; Elektra issued corporate bonds; Delsur refinanced its $100 million bridge loan; and Promigas refinanced various credit facilities for the financing of capital expenditures. In addition, we used a portion of the stock issuance proceeds previously mentioned to repay a portion of our revolving credit facility and to make dividend payments to noncontrolling shareholders of the operating companies, and Trakya paid off all of its long-term debt.

Subsidiary Distributions to Parent

Subsidiary Distributions to Parent is the amount of cash distributed by our operating businesses including dividends, returns of capital, management fees, intercompany loan and interest payments, development fees and development cost reimbursements. Subsidiary Distributions to Parent for 2009 and 2008 were $508 million and $448 million, respectively.

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Parent Company Long-term Debt

Credit Agreement

We are the borrower under a $1.5 billion senior secured loan facility with various financial institutions as lenders, Credit Suisse as Administrative Agent and JPMorgan Chase Bank as Collateral Agent. The credit facility consists of a $395 million revolving credit facility and a $105 million synthetic revolving credit facility that both mature on March 30, 2012 and a $1 billion term loan facility that matures on March 30, 2014. At our election, the term loan incurs interest at LIBOR plus 3% or the rate most recently established by the Administrative Agent as its base rate for dollars loaned in the United States plus 1.75%. The revolving credit facility when drawn incurs interest at LIBOR plus 3% or the rate most recently established by the Administrative Agent as its base rate for dollars loaned in the United States plus 1.75%; the undrawn portion of the revolving credit facility incurs a commitment fee of 0.50% per annum. The synthetic revolving credit facility when drawn incurs interest at LIBOR plus 3% or the rate most recently established by the Administrative Agent as its base rate for dollars loaned in the United States plus 1.75%; the undrawn portion of the synthetic revolving credit facility incurs a commitment fee of 3.1% per annum. The Collateral Agent is the beneficiary, on behalf of the lenders, of certain pledges over capital securities held by us in certain of our direct subsidiaries. The purpose of this credit facility was to refinance the previously existing senior and bridge loans on better terms and pricing and also to provide for a revolving credit facility and Letter of Credit sub-facilities that will provide us with additional liquidity. As of December 31, 2009, $113 million was drawn under the revolving credit facility and $105 million was drawn under the synthetic revolving credit facility.

Note Purchase Agreement (PIK Notes)

We are the issuer of PIK Notes under a Note Purchase Agreement in May 2007, as amended. The proceeds from the issuance of the PIK Notes were used by us to repay $279 million of the outstanding PIK Notes, including capitalized interest, that were issued on September 6, 2006. As of December 31, 2009, the aggregate principal and interest amount of the PIK Notes was $179 million. The PIK Notes mature on May 25, 2018.

On March 11, 2009 we, upon amendment of the PIK Note Purchase Agreement, issued an option for up to one year to the PIK Note holders to exchange their PIK Notes for our ordinary shares. The option period expired on March 12, 2010. Additionally, the amendment allows us to purchase, upon the Holders election, the PIK Notes in the open market for cash, subject to certain conditions. In March, August and October 2009, various Ashmore Funds exercised their option to convert their PIK Notes and related interest receivable in the amount of $196 million for 12,084,075 of our ordinary shares. Funds that are managed by Ashmore also own a majority of our shares. We recorded an equity transaction for the issuances of such shares and the early retirement of the related debt. As the PIK Notes exchanged were held by funds having the same investment advisor as our majority shareholders, we recorded a $28 million increase in paid-in-capital representing the difference between the carrying value of the acquired PIK Notes and the estimated fair value of our ordinary shares at the date of issuance.

The interest rate applicable to the PIK Notes is 10.0%. Interest is payable semi-annually in arrears (on May 25 and November 25 each year) and is automatically added to the then outstanding principal amount of each note on each interest payment date.

Events of default under the PIK Note Purchase Agreement are limited and include among other customary items: (1) a failure to timely repay PIK Note principal, interest, and any applicable redemption premium; (2) a failure to make payments or perform other obligations with respect to other of our indebtedness having a principal amount in excess of $50 million or the acceleration of any such indebtedness; and (3) becoming insolvent, filing for bankruptcy protection, or having a court appoint a trustee with respect to a substantial portion of our property or enter an order for bankruptcy protection.

The PIK Notes are expressly subordinate to our existing senior and bridge loans. The noteholders agree not to accelerate the payment of the note obligations or exercise other remedies available to them with respect to the notes until satisfaction of all obligations under our existing senior and bridge loan facilities.

We may, upon notice to the noteholders, redeem the notes prior to maturity by paying the then outstanding principal amount of the note, plus a redemption premium, together with any accrued but unpaid and uncapitalized interest.

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The redemption premium is as follows: up to May 24, 2010 — at 106% of the face amount of the note, May 24, 2011 and thereafter — at 108% of the face amount of the note.

Subsidiaries Financing Activities

In March 2009, Cálidda repaid its subordinated loan of $47 million with funds provided through a loan with its shareholders, us and Promigas. The letter of credit, associated with the previous subordinated loan, was allowed to expire at repayment, which released $29 million of cash collateral.

During the second and third quarters of 2009, we purchased from third parties $31 million of the $37 million of outstanding debt held by our consolidated subsidiary EDEN. A gain of $10 million was recognized and is included in “Gain on early retirement of debt” in the consolidated statements of operations.

In July 2009, Elektro issued 300 million Brazilian reais (approximately U.S. $172 million) in debentures. The proceeds of the debentures were used to refinance its existing debentures.

In July and August 2009, Promigas and its subsidiary, Gases de Occidente, issued debentures totaling 550 billion Colombian pesos (approximately U.S. $271 million) on the Colombian Stock Exchange. These debentures have a weighted average annual interest rate of 8.3% and maturity between 2014 and 2024.

During the second and third quarters of 2009, Promigas and, subsequent to the spin-off, Proenergía repaid all of its U.S. dollar-denominated notes totaling $250 million. The payment was primarily refinanced in Colombian peso denominated notes. These new notes have a weighted average annual interest rate of 9.8% and maturity between 2011 and 2014. The new notes are primarily unsecured.

During the fourth quarter of 2009, Trakya obtained financing consisting of an $80 million unsecured loan agreement maturing in 2014. After a one year grace period, principal is paid in nine semi-annual installments. Interest is payable on a semiannual basis. The loan bears interest at six month LIBOR plus 4%.

Subsidiaries’ Long-term Debt Schedule

The following table summarizes our consolidated subsidiaries’ credit facilities as of December 31, 2009:

Currency of

Balance as of

Summary of Distribution

Business

Borrowing

December 31, 2009

Maturity Profile

Collateral

Restrictions

Millions of
dollars (U.S.)

Cálidda

U.S.$

2015

Security includes the gas distribution concession and income trust

No restrictions, but must meet leverage and debt service coverage ratios, among others.

DCL⁽¹⁾

Pakistani rupees

2010 -2019

Charges over fixed and current assets

Restriction on dividend distribution: — 1 year period from the Commercial Operate Date — subject to satisfaction of the Debt Service Coverage Ratio (>=1.5) and the Leverage Ratio (Debt to Equity <=75:25, Current Ratio>=0.75:1) and Applicable Law

Delsur

U.S.$

2015

Security includes subsidiary guarantees and pledges of shares

No default/must meet
distribution ratios/local
laws

EDEN⁽²⁾

U.S.$

2013

Unsecured

No default/limited to% of excess cash

Elektra

U.S.$

119

2018-2021

Unsecured

None

Elektro

Brazilian real

616

2010-2021

Security includes pledge of account receivables cash flow and cash collateral

— Default under any Eletrobrás agreement and certain agreements with Banco Nacional de Desenvolvimento Econômico

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Currency of

Balance as of

Summary of Distribution

Business

Borrowing

December 31, 2009

Maturity Profile

Collateral

Restrictions

Millions of
dollars (U.S.)

e Social, or BNDES — Dividends/Shareholder Interest less than 110% of the Net Profit

EMDERSA

U.S.$

2010

EMDERSA guarantee

Debt / EBITDA < 2.25

EMDERSA

Argentine peso

2010

Unsecured

No default / local laws

ENS

Polish zloty

2010-2018

Security includes mortgage on assets, assignment of contracts, pledge of shares, DSRA, DSA, insurance assignments, etc.

No default/must meet
distribution ratios/local
laws

Luoyang

Chinese renminbi

119

2010-2016

Security includes assignment of rights to collection of revenues and pledge of shares

China Development Bank
approval for dividends

PQP

U.S.$

2012-2015

Security includes mortgage on assets, assignment of contracts, pledge of shares etc.

No default/must meet
distribution ratios/local
laws

Proenergía⁽³⁾

Colombian pesos

543

2010-2016

Unsecured

Debt Service Ratio (>=1.3)

Proenergía⁽³⁾

Chilean pesos

2019

Security includes
mortgage over
assets

((Royalty + Dividends) / (Royalty + Net Income)) < 0.6

Proenergía⁽³⁾

U.S.$

2010-2012

Security includes
mortgage over
assets

Dividends must not exceed 30% of Net Income

Promigas⁽⁴⁾

Colombian pesos

469

2011-2024

Unsecured

None

Promigas⁽⁵⁾

U.S.$

2010-2012

Unsecured

None

Trakya

U.S.$

2014

Unsecured

No default/must meet
distribution ratios/local
laws

Others

U.S.$ and Chinese renminbi

2010-2016

Total

$2,428


(1)		In June 2009, DCL entered into loan agreements with its senior lenders and Sacoden pursuant to which the senior lenders and Sacoden made loans to DCL to fund its rehabilitation efforts. In connection with these loan agreements, DCL and Sacoden entered into a Standstill Agreement with the senior lenders pursuant to which the parties agreed to refrain from taking legal action against each other while DCL rehabilitates the plant and negotiates a new PPA. The Standstill Agreement has now expired. See Note 25 to the consolidated financial statements.

(2)		In December 2009, EDEN signed a credit agreement amendment with its lenders and is no longer in default. See Note 15 to the consolidated financial statements.

(3)		In July 2009, Promigas completed the spin-off of Proenergía to the shareholders of Promigas with the same ownership structure and percentage that existed prior to the spin-off, and we obtained a 52.13% ownership in Proenergía. Through Proenergía, we own 27.45% of SIE, our retail fuel operations.

(4)		Some of the credit facilities included in this entry may have shorter maturity profiles.

(5)		Some of the credit facilities included in this entry may have shorter maturity profiles, unsecured collateral and no distribution restrictions.

C. Research and Development, Patents and Licenses, Etc.

Not applicable.

D. Trend Information

Our business has historically been, and we expect it to continue to be, affected by the following key trends:

Capital Markets. As the concern over the stability of the world-wide financial markets has begun to diminish, we are expecting that the debt markets will continue to gradually open over the near term. During 2009, AEI has been able to execute new bond placements and bank financings in many countries in which we operate and we are projecting both refinancing and new debt placements in our key markets over the next few years.

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Macroeconomic Developments in Emerging Markets. We generate nearly all of our revenue from the production and delivery of energy in emerging markets. Therefore, our operating results and financial condition are directly impacted by macroeconomic and fiscal developments, including fluctuations in currency exchange rates, in those markets. During the years leading up to the world-wide financial crisis, emerging markets had generally experienced significant macroeconomic and fiscal improvements. We expect our key markets will again experience macroeconomic improvements, evidenced by modest GDP growth, and higher energy demand beginning in 2010.

Foreign Currency Changes. In 2008, the local currencies in many emerging markets in which we operate depreciated or remained flat against the U.S. dollar, resulting in lower earnings and cash flows (measured in U.S. dollars) from some of our subsidiaries, particularly Elektro, which is located in Brazil and is our largest business. In 2008 the Brazilian real depreciated by 31.6% against the U.S. dollar, according to the European Central Bank. During 2009, the local currencies in emerging markets strengthened significantly. Based on information from the European Central Bank, the Brazilian real appreciated against the U.S. dollar by 25.5% in 2009.

Acquisitions and Future Greenfield Development. We have experienced growth through acquisitions in recent years. This growth has resulted in material year-over-year changes in our financial condition and changes from equity method accounting to consolidation for certain subsidiaries, which affect the yearly comparison of our financials. We intend to continue growing our business through organic growth and additional acquisitions as well as through greenfield development.

Regulatory Developments in Emerging Markets. In many of our markets, the regulatory frameworks have been and continue to be restructured to create conditions that will foster investment and growth in energy supply to meet expected future energy requirements. The development and timing of this process varies across our markets. In some markets, such as Brazil and Colombia, major regulatory changes were implemented in the 1990s or early 2000s, and, in those countries, the regulatory framework is now relatively settled. In other markets, such as Turkey and China, the regulatory process is less evolved, with major changes continuing to take place, and it is as yet unclear what the ultimate regulatory structure will be. However, in most of these markets, the common trend has been to establish conditions that foster and rely on the participation of the private sector in providing the needed infrastructure to support the current growth pattern of energy consumption. We believe that this trend will continue in most of the markets that we serve.

Commodity Prices. There have been substantial changes in commodities prices in the last few years. Most of our revenue depends directly or indirectly on fuel prices in the local markets we serve. In most cases, we are able to pass on the higher or lower fuel costs to our customers, which increases or decreases our revenue and costs of sales, but does not necessarily affect our net income.

E. Off-Balance Sheet Arrangements

In the normal course of business, we and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties. Such agreements include guarantees, letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish the subsidiary’s intended business purpose. As of December 31, 2009, AEI and certain of its subsidiaries had entered into letters of credit, bank guarantees, and performance bonds with balances of $379 million issued of which $11 million of the total facility balances were fully cash collateralized. Additionally, as of December 31, 2009, lines of credit of $368 million were outstanding, with an additional $558 million available.

See Note 25 to the consolidated financial statements for further information on letters of credit, litigation and other commitments and contingencies.

-96-

F. Tabular Disclosure of Contractual Obligations

A summary of contractual obligations, commitments and other liabilities as of December 31, 2009 is presented in the table below:


			Less Than						After
	Total		1 Year		1-3 Years		3-5 Years		5 Years
	Millions of dollars (U.S.)
Debt obligations(a)	$	3,718	$	613	$	1,047	$	1,193	$	865
Interest payments on long-term debt(b)		1,140		231		341		234		334
Pension obligations		268		16		38		46		168
Operating lease obligations(c)		24		8		9		5		2
Capital lease obligations(d)		71		12		18		29		12
Power commitments(e)		19,432		1,166		2,506		2,255		13,505
Fuel commitments(f)		4,912		1,722		944		590		1,656
Transportation commitments(g)		1,154		79		165		175		735
Equipment commitments(h)		146		9		5		29		103
Other commitments(i)		16		9		5		1		1

Total	$	30,881	$	3,865	$	5,078	$	4,557	$	17,381


(a)		Debt obligations include non-recourse debt and recourse debt presented in our consolidated financial statements. Non-recourse debt borrowings are not a direct obligation by us, and are primarily collateralized by the capital stock of the relevant business and in certain cases the physical assets of, and/or all significant agreements associated with, such businesses. These non-recourse financings include structured project financings, acquisition financings, working capital facilities and all other consolidated debt of the businesses. Recourse debt borrowings are our borrowings.

(b)		Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2009 and do not reflect anticipated future financing, new debt issuances, early redemptions, or certain interests on liabilities other than debt. Variable rate interest obligations are estimated based on rates as of December 31, 2009.

(c)		Operating lease obligations are the future obligations primarily related to land, office, office equipment and vehicles in which several of our businesses are the lessees.

(d)		Capital lease obligations are the future obligations primarily related to certain pipelines and equipment in which Promigas and Elektro are the lessees. The leases are all nonrecourse. As of December 31, 2009 and 2008, the net assets held under capital leases were $85 million and $42 million, respectively, and imputed interest for these obligations were $20 million and $14 million, respectively.

(e)		Represents take-or-pay and other commitments to purchase power of various quantities from third parties.

(f)		Represents take-or-pay and other commitments to purchase fuel of various quantities from third parties.

(g)		Represents a commitment to purchase gas transportation services from an unconsolidated affiliate and third parties.

(h)		Represents commitments of various duration for parts and maintenance services provided by third parties, which are expensed during the year of service.

(i)		Represents various other purchase commitments with third parties.

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Item 6. Directors, Senior Management and Employees

A. Directors and Senior Management

The following table sets forth our directors and executive officers and the positions held by them.


Name		Position

Ronald W. Haddock		Non-Executive Chairman of the Board of Directors
James A. Hughes		Chief Executive Officer and Director
Eduardo Pawluszek		EVP, Chief Financial Officer
Maureen J. Ryan		EVP, General Counsel and Chief Compliance Officer
Emilio Vicens		EVP, Commercial/Operations
Laura C. Fulton		EVP, Accounting
Andrew Parsons		EVP, Administration
Brian Zatarain		EVP, Risk
Brian Stanley		EVP, Operations^*
Robert Barnes		Director
Philippe A. Bodson		Director
Henri Philippe Reichstul		Director
Robert E. Wilhelm		Director
George P. Kay		Director
Wilfried E. Kaffenberger		Director
Julian Green		Director


*		Retired February 2010

Ronald W. Haddock is the non-executive chairman of our board of directors and has been a director since August 2003, first of PEI and then of AEI. Mr. Haddock was our chief executive officer from August 2003 to May 2006 and the executive chairman of our board of directors from May to September 2006. He also served as a director of Trakya, Elektro and Vengas. Mr. Haddock was president and chief executive officer of FINA from 1989 until his retirement in 2000. He joined FINA in 1986 as executive vice president and chief operating officer, and was elected to FINA’s board of directors in 1987. Prior to joining FINA, Mr. Haddock served in various positions at Exxon, including vice president and director of Exxon’s operations in the Far East, executive assistant to the chairman, vice president of Refining and general manager of Corporate Planning. He currently serves on the boards of directors of Alon U.S.A. Energy, Inc., Trinity Industries, Inc., Safety-Kleen, Adea International, Rubicon Offshore International and Petron Corporation, and he previously also served on the boards of directors of Southwest Securities, Inc. and Enron Corp. Mr. Haddock received a bachelor of science degree in mechanical engineering in 1963 from Purdue University.

James A. Hughes joined us in May 2007 as chief operating officer and became our Chief Executive Officer in October 2007. He has been a director of AEI since October 2007. Prior to joining us, Mr. Hughes was a principal of a privately-held company that focused on micro-cap investments in North American distressed manufacturing assets. Previously, he served as president and chief operating officer of PEI, from the date of its creation in 2002 until March 2004. Preceding that role, Mr. Hughes spent almost a decade with Enron Corp. in positions ranging from president and chief operating officer of Enron Global Assets to assistant general counsel of Enron International. Mr. Hughes began his career as a securities lawyer with Vinson & Elkins in Dallas, Texas, later moving to their Warsaw, Poland office where he specialized in international project development. He served on the board of Quicksilver Resources Inc., an exploration and production company, until May 2008. Mr. Hughes holds a bachelor of business administration degree from Southern Methodist University in Dallas, Texas and a juris doctor from the University of Texas School of Law in Austin, Texas. He is admitted to the practice of law in Texas.

Eduardo Pawluszek joined us in September 2009 as EVP, Chief Financial Officer. Before joining us, Mr. Pawluszek was the chief executive officer of our subsidiaries Emgasud from February to September 2009, and EDEN from September 2007 to January 2009. Previously, Mr. Pawluszek served as chief financial officer of TGS from 2005 to 2007 after working as a manager in the areas of finance and investor relations for TGS from 1999 to 2005. He worked for the Royal Bank of Canada from 1988 to 1999, focusing on business development with Argentine and Chilean corporate clients and corporate banking. Mr. Pawluszek received his undergraduate degree in public accountancy from the University of Buenos Aires and a master in finance and capital markets from the Escuela Superior de Economía y Administración de Empresas.

-98-

Maureen J. Ryan joined us in December 2006 and is currently EVP, General Counsel and Chief Compliance Officer for AEI. Prior to joining us, Ms. Ryan was counsel in the mergers and acquisitions department of the New York office of Clifford Chance US LLP, which she had joined in 1995. Her practice was primarily focused on domestic and cross-border private equity and venture capital transactions, including representing both financial sponsors and corporations in leveraged acquisitions, mergers, private stock and assets sales and divestiture, restructuring and strategic alliances. Ms. Ryan is a graduate of Harvard Law School, where she received her LLM degree in 1995 and Trinity College in Dublin, Ireland where she earned her LLB with first class honors in 1993.

Emilio A. Vicens joined us in April 2007 and is currently EVP, Commercial/Operations for AEI and has recently assumed responsibility for operations. Before joining us, Mr. Vicens spent six years with Union Fenosa Internacional as head of business development and asset management for the South East Asia region and, more recently, as head of business development for Union Fenosa Distribución in Central and South America. His energy career started at Enron Corp. where he worked for six years in various capacities in the areas of finance, structuring and business development. Throughout his career, Mr. Vicens has worked in both the regulated and unregulated side of the energy sector focusing on the emerging markets in Latin America and South East Asia. He earned his bachelor of arts with honors in banking and finance from Universidad Metropolitana in Caracas, Venezuela and his master of business administration from Harvard Business School.

Laura C. Fulton joined us in March 2008 and is currently EVP, Accounting for AEI. Prior to joining us, Ms. Fulton spent 12 years with Lyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and the Sarbanes-Oxley certification process, and as the assistant controller. Previously, she worked for Deloitte & Touche in its audit and assurance practice for 11 years. Ms. Fulton is a CPA and graduated cum laude from Texas A&M University with a bachelor of business administration in accounting. Ms. Fulton is a member of the American Institute of Certified Public Accountants and serves on the Accounting Department Advisory Board at Texas A&M University.

Andrew Parsons joined us in September 2004 and is currently EVP, Administration for AEI. Mr. Parsons is responsible for the company’s administrative functions, which include internal audit, Sarbanes-Oxley project management and special projects, human resources, information technology and communications. Mr. Parsons has been with AEI and PEI since 2004 working as the vice president of internal controls and prior to that as the vice president of information systems. Previously, he spent five years with Enron Corp. in several capacities, including serving as vice president, corporate systems and information technology compliance, and senior director of assurance services. Mr. Parsons also worked for eight years in Arthur Andersen’s business risk consulting and assurance practice. Mr. Parsons holds a bachelor of arts with honors from Carleton University and a master of business administration from the University of Houston.

Brian Zatarain joined us in January 2002 and is currently EVP, Risk for AEI. Previously, Mr. Zatarain was a senior director in the business development group responsible for the acquisition and financing commitments of various energy infrastructure opportunities and the development, financing and implementation of greenfield development projects. Previously, Mr. Zatarain held positions in the international business development and investment management groups at Enron Corp., primarily focused on acquisitions, greenfield development and asset management. Previously, Mr. Zatarain worked at Coastal Power for three years supporting the execution of its Latin American energy infrastructure acquisition and greenfield development strategy. Mr. Zatarain holds a bachelor of arts in economics from the University of Texas and a master of business administration from Duke University.

Brian Stanley joined us in January 2002 and was EVP, Operations for AEI with technical and operational responsibility for all of our assets worldwide until his retirement in February 2010. He served as Enron Corp.’s operations manager of the Teesside Power Station in the UK, assuming the position of plant manager in 1993. He held other positions within Enron Corp., including general manager of Enron Power Operations, responsible for all power plants in the United States and Central America, vice president of asset management of Enron Europe with responsibility for power generation facilities in Europe, and president and chief executive officer of Enron Engineering & Operational Services, responsible for global construction, engineering and operations of power generation and gas processing facilities. He has more than 45 years of experience in the energy industry, including Central Electricity Generating Board and PowerGen. Mr. Stanley holds an electrical engineering degree from Nottingham Regional College of Technology and is a Member of the Institution of Electrical Engineers (MIEE). Mr. Stanley retired from AEI in February 2010 and entered into a consulting agreement with us, pursuant to which he will provide consulting services on an as-requested basis. Mr. Stanley’s responsibilities have been assumed by Mr. Vicens.

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Robert Barnes has been a director since May 2006, first of PEI and then of AEI. Mr. Barnes was, in 1997, one of the founding members of Alchemy Partners LLP, a private equity advisory firm and was a full-time partner of Alchemy Partners until December 31, 2005. He is now engaged in certain Alchemy portfolio matters and is pursuing other personal interests, including venture capital activities. Mr. Barnes’ earlier career was largely spent in a financial management role in troubled companies after working with Coopers & Lybrand in London and Canada as a senior manager. He is currently a director of Guernsey Pub Company Ltd. and New Horizon Youth Centre, a charity. Mr. Barnes previously served on the boards of directors of Hungarian Telephone and Cable Company, a company listed on the American Stock Exchange, Blagden Group NV, ICM GmbH, GSH Oy and Panini srl. Mr. Barnes received a bachelor of science in chemical engineering, first class honors, from the University of Leeds and is a chartered accountant qualified in the UK and a Fellow of the Institute of Chartered Accountants in England and Wales.

Philippe A. Bodson has been a director since July 2003, first of PEI and then of AEI. Mr. Bodson has extensive experience in utility and industrial concerns with international activities, which includes having served as chief executive officer of Glaverbel from 1980 to 1989, Tractebel from 1989 to 1999 and Lernout & Hauspie (post-bankruptcy) in 2001. Mr. Bodson also has extensive board experience, having served as a director for Glaverbel, Tractebel, Electrabel, Société Générale, A.G., Société Générale de Banque, Compagnie Immobiliere de Belgique, Hermes Focus Asset Management Europe, Louis de Waele, British Telecom Belgium, Diamond Boart and Fortis, and he currently serves as the chairman of the board of HAMON, Exmar, BE Capital, Blue Sky, N.M.G.B and Floridienne, and as a director of Cobepa and Turenne. He was also a member of the Belgian Senate from 1999 to 2003 and has been a member of the advisory board of Credit Suisse since 2004. Mr. Bodson is also a member of the boards of directors of several charitable organizations or non-profit entities, including la Fondation de l’Entreprise, Contius, the Belgian chapter of American Field Service, the chairman of Free and Fair Post Initiative and an advisor to la Fondation Françoise Dolto. Mr. Bodson received a degree in civil engineering from the University of Liège in Belgium in 1967 and a master of business administration from INSEAD, Fontainebleau, France, in 1969.

Henri Philippe Reichstul has been a director since December 2003, first of PEI and then of AEI. He is currently the chief executive officer of Brenco, a Brazilian ethanol production company. Mr. Reichstul has also been chairman of G & R — Gestão Empresarial, a consulting firm, since 2002. Previously, he worked as an economist for the International Coffee Organization in London, the newspaper Gazeta Mercantil in São Paulo, the Economic Research Institute Foundation of the University of São Paulo (FIPE), and CED — Coordenação das Entidades Descentralizadas da Secretaria de Estado dos Negócios da Fazenda de São Paulo. Mr. Reichstul was also the secretary of SEST — Secretaria de Controle de Empresas Estatais, the office of the Secretariat of Planning, the office of the President of the Republic and executive secretary of the Inter-Ministry Council of CISE — Conselho Interministerial de Salários de Empresas Estatais. He has been a member of the boards of directors of TELEBRÁS, ELETROBRÁS, SIDERBRÁS, BNDES, BORLEM S.A. — Empreendimentos Industriais, CEF — Caixa Econômica Federal, LION S.A., and is currently a member of the board of directors of Repsol YPF, S.A., Peugeot Citroen PSA. In addition, Mr. Reichstul was the general secretary of planning under the Office of the President of the Republic, chairman of IPEA — Instituto de Planejamento Econômico e Social, executive vice president of Banco Inter American Express S.A., chief executive officer and president of Petrobrás — Petróleo Brasileiro S.A. from 1999 to 2001 and president of Globopar in 2002. He is also the vice chairman of the board of the Brazilian Foundation for Sustainable Development. Mr. Reichstul has a graduate degree in economics from the University of São Paulo and has studied post-graduate economics at the University of Oxford.

Robert E. Wilhelm has been a director since December 2003, first of PEI, and then of AEI. Mr. Wilhelm is currently an independent energy consultant and venture capital investor and was employed by Exxon Mobil Corporation (and predecessor companies) from 1963 until he retired in 2000. During his career with ExxonMobil, Mr. Wilhelm held a variety of operating assignments, primarily in the international petroleum business, including chief executive officer for Latin America and executive vice president for all international petroleum activities. Other operating assignments included positions as vice president of Esso Europe from 1980 to 1984, president of Esso InterAmerica from 1984 to 1986 and executive vice president of Exxon International from 1986 to 1990. From 1990 until his retirement in 2000, Mr. Wilhelm was senior vice president of ExxonMobil, with responsibility for finance, long-range planning, control, public affairs and the worldwide refining and marketing businesses and, beginning in 1992, was a member of ExxonMobil’s board of directors. He is a member of the Council on Foreign Relations and the Precourt Energy Efficiency Center at Stanford University, past vice chairman of the Council of the Americas and served on the advisory council of PricewaterhouseCoopers until the end of 2009. Mr. Wilhelm recently completed a ten-year term on the board of directors of Massachusetts Institute of Technology. He received a bachelor of science degree from Massachusetts Institute of Technology in 1962 and a master of business administration from Harvard Business School in 1964.

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George P. Kay has been a director of AEI since May 2008. Mr. Kay has been a vice president of GIC Special Investments Pte Ltd. since April 2006, where he is responsible for infrastructure investments in the UK, North America and South America. Mr. Kay is based in London and he currently also serves on the board of directors of Associated British Ports plc and is a member of its remuneration and nomination committee. Prior to joining GIC Special Investments Pte Ltd., Mr. Kay worked in principal finance for the Commonwealth Bank of Australia from September 2000 to April 2006, and previously worked for Westpac Banking Corporation as a senior credit analyst. He received his bachelor of commerce from University of Canterbury, New Zealand where he studied accounting and economics, and his master of applied finance from Macquarie University, Australia.

Wilfried E. Kaffenberger has been a director of AEI since August 2009. Mr. Kaffenberger is currently a director of NWS Holdings, a Hong Kong-based company which owns and operates infrastructure and service businesses in Hong Kong, Macao and China, and is a director of BAA Airports Limited, a London-based company which operates major airports in the United Kingdom. In 2008, he retired from the role of chief executive officer of AIG Asian Infrastructure Fund II, a $1.67 billion private equity investment fund organized in 1997. For the previous 11 years, Mr. Kaffenberger was a managing director of Emerging Markets Partnership, an asset management firm focused on equity investments in emerging markets. Prior to that, he was vice president, Investment Operations for the International Finance Corporation (IFC), an affiliate of the World Bank focused on investing in private companies in emerging markets, and he held various other positions during his 25 years at the IFC. He received a bachelor of degree from Princeton University in 1966 and a master of business administration from Harvard Business School in 1968.

Julian Green has been a director of AEI since September 2009. He was a founding shareholder of Ashmore in 1999 and director until 2004. Mr. Green was also a member of Ashmore’s Investment Committee, from its inception until 2009, and was the senior portfolio manager with daily responsibility for fixed income investment management. He joined Grindlays Bank plc in 1985 and in 1990, joined the ANZ Emerging Markets Group within Grindlays Bank as an originator/distributor. In 1992 he became an original member of the Investment Committee of the ANZ Emerging Markets Fund Management Group, which later became Ashmore through a management buyout. He received a BSc in Management Sciences from the London School of Economics in 1985. He is a member of the Development Committee of the London School of Economics and an associate of the Chartered Institute of Bankers.

International Management

The following table sets forth certain members of our international management team, their years of experience as of the date of this annual report and the positions held by them. The business address for such members is c/o AEI Services LLC, 700 Milam, Suite 700, Houston, TX 77002.


		Years of Experience
		in the Energy
Name	Position	Industry
Antonio Celia Martínez-Aparicio	CEO of Promigas		25
Carlos Marcio Ferreira	CEO of Elektro		6
Pablo Ferrero	EVP, Southern Cone		18
Roberto Figueroa	EVP, Central America/Caribbean		22
Jacek Glowacki	VP, AEI Europe		28
Colin Tam	CEO of AEI Asia		37

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B. Compensation

Compensation of Directors and Executive Officers

Our executive officers are paid a base salary and are paid an annual discretionary cash bonus, based on company and individual performance. They also receive an annual discretionary equity grant based on market competitive pay practices. Our directors receive an annual directors fee, which varies based on committee membership and chairman positions, and an annual equity grant. In 2009, we paid our directors an aggregate of $996,558 in cash, $171,500 in restricted stock and $336,796 in options, on a fair value basis. With respect to 2009, we paid our executive officers an aggregate of $4,607,043 prior to taxes in salaries and bonuses. In addition, for 2009 services, we issued grants of restricted shares and options to our executive officers in February 2010 with a fair value on the date of grant of $2,476,053 in aggregate.

Awards of performance shares were also issued to our executive officers in February 2010, with an aggregate fair value on the date of grant of $1,004,313. The equity ownership of our executive officers and directors is described in “— E. Share Ownership — Share Ownership of Executive Officers and Directors.” We are not required under Cayman Islands law to disclose, and we have not otherwise disclosed, the compensation of our directors and executive officers on an individual basis.

C. Board Practices

Duties of Directors

Under Cayman Islands law, our directors have a fiduciary duty to act honestly, in good faith and with a view to our best interests. Our directors also have a duty to exercise the skills they actually possess and such care and diligence that a reasonably prudent person would exercise in comparable circumstances. In fulfilling their duty of care to us, our directors must ensure compliance with our Amended and Restated Memorandum and Articles of Association. A shareholder has the right to seek damages for any direct personal loss suffered by him, and in certain limited circumstances on behalf of us for loss suffered by us, if a duty owed by our directors is breached.

The functions and powers of our board of directors include, among others:

	•		overall responsibility for the management of the business of our company;

	•		convening shareholders’ annual general meetings and reporting its work to shareholders at such meetings;

	•		issuing authorized but unissued shares and redeeming or purchasing outstanding shares of our company;

	•		declaring dividends and distributions;

	•		appointing officers and determining the term of office and compensation of officers;

	•		exercising the borrowing powers of our company and mortgaging the property of our company; and

	•		approving the transfer of shares of our company, including the registering of such shares in our share register.

Terms of Directors and Executive Officers

Our executive officers are appointed by and serve at the discretion of our board of directors. Our directors will serve one-year terms and hold office until such time as their successors are elected and qualified. Our Amended and Restated Memorandum and Articles of Association provide that a director will be removed from office automatically if such director (i) becomes bankrupt or makes any arrangement or composition with his creditors generally, or (ii) is found to be or becomes of unsound mind, or (iii) resigns his office by notice in writing to us, or (iv) ceases to be a director by virtue of, or becomes prohibited from being a director by reason of, an order made under any provisions of any law or enactment or the relevant code, rules and regulations applicable to the listing of our ordinary shares on any securities exchange or other system on which our ordinary shares may be listed or otherwise authorized for trading from time to time.

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Qualification

There is no shareholding qualification for directors.

Board Committees

Our board of directors has established an audit committee, a compensation committee and a nominating and corporate governance committee.

Audit Committee

The audit committee of our board of directors oversees and assists our board of directors in fulfilling its legal and fiduciary obligations with respect to matters involving the accounting, auditing, financial reporting, internal control and legal compliance functions of us and our subsidiaries. Such matters include (a) assisting the board’s oversight of (i) the integrity of our financial statements, (ii) our compliance with legal and regulatory requirements, (iii) our independent auditors’ qualifications and independence, and (iv) the performance of our independent auditors and our internal audit function, and (b) preparing (or causing the preparation of) any report required to be prepared by the audit committee pursuant to the rules of the SEC for inclusion in any annual proxy statement or our annual report on Form 20-F.

Our audit committee currently comprises Messrs. Wilhelm, Bodson, Kaffenberger and Barnes. The members of our audit committee are nominated by the nominating and corporate governance committee of our board of directors and are elected annually by majority vote of the board of directors for one-year terms. Mr. Wilhelm is the chairman of our audit committee and meets the criteria of an “audit committee financial expert” as set forth under Section 407(d)(5) of Regulation S-K. Our board of directors has determined that each of Messrs. Barnes, Bodson, Wilhelm and Kaffenberger is an “independent director” within the meaning of NYSE Manual Section 303A and meets the criteria for independence set forth in Section 10A(m)(3) and Rule 10A-3 of the Exchange Act of 1934, as amended, or the Exchange Act.

Our audit committee is responsible for, among other things:

	•		selecting, in its sole discretion, independent auditors to audit the books and accounts of us and our subsidiaries for each fiscal year, reviewing the performance of such independent auditors and making decisions regarding the replacement or termination of the independent auditors;

	•		annually reviewing a report prepared by the independent auditors describing such firm’s internal quality-control procedures, any material issues raised by the most recent internal quality control review of such firm and all relationships between the independent auditors and us, and present its conclusions with respect to such matters to our board;

	•		overseeing the independence of our independent auditors;

	•		establishing clear hiring policies for employees or former employees of the independent auditors;

	•		reviewing with management and the independent auditors our annual audited financial statements and periodic financial statements and any major related issues, critical accounting policies, including financial reporting issues that could have a material impact on our financial statements, and major issues regarding accounting principles and financial statements presentations;

	•		resolving disagreements between our independent auditors and our management regarding financial reporting;

	•		reviewing with the independent auditors any problems or difficulties encountered in the course of any audit work and management’s response;

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	•		reviewing the annual audit plan of our independent auditors and the annual working plan of our internal auditors;

	•		reviewing our internal audit function, the adequacy and effectiveness of our accounting and internal control policies and procedures, and management’s yearly report assessing the effectiveness of our internal control over financial reporting;

	•		discussing guidelines and policies governing the process by which our exposure to risk is assessed and managed, and steps taken to monitor and control such exposure;

	•		preparing the reports required under the rules of the SEC to be included in an annual proxy statement, as applicable;

	•		establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters; and

	•		periodically reviewing with our chief executive officer, chief financial officer, internal auditors and independent auditors all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect our ability to record, process, summarize, and report financial data and any changes in internal control over financial reporting that occurred during the most recent fiscal quarter and that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Compensation Committee

The compensation committee of our board of directors oversees our compensation and employee benefit plans and practices, including its executive compensation, incentive compensation and equity-based plans. The compensation committee is currently comprised of Messrs. Reichstul, Bodson and Kay. Each of Messrs. Reichstul, Bodson and Kay is a “non-employee director” within the meaning of Rule 16b-3 promulgated under the Exchange Act. The members of our compensation committee are nominated by the nominating and corporate governance committee of our board of directors and are elected annually for one-year terms by majority vote of the board of directors. Mr. Bodson is the chairman of our compensation committee. Our board of directors has determined that Messrs. Reichstul and Bodson qualify as “independent directors” under the listing standards set forth in NYSE Manual Section 303A.

Our compensation committee is responsible for, among other things:

	•		reviewing our executive compensation, incentive-based, equity-based, general compensation and other employee benefits plans and our goals and objectives with respect to such plans, and amend or recommend amending such plans or our goals and objectives with respect to such plans as appropriate;

	•		evaluating annually the performance of our executive officers in light of the goals and objectives of our executive compensation plans, and determining and approving the compensation level of such executive officers based on this evaluation, including the long-term incentive component of their compensation, if any; and

	•		evaluating annually the appropriate level of compensation for board and committee service by non-employee members of the board of directors.

Nominating and Corporate Governance Committee

The nominating and corporate governance committee of our board of directors recommends to our board of directors individuals who are qualified to serve as directors of AEI and on committees of our board, advises our board of directors with respect to corporate governance principles applicable to us as well as the board composition, procedures and committees and oversees the evaluation of our board of directors and our management. The nominating and corporate governance committee is currently comprised of Messrs. Haddock, Wilhelm and Bodson. The members of the nominating and corporate governance committee are elected annually to one-year terms by majority vote of our board of directors. Mr. Haddock is the chairman of our nominating and corporate governance committee. Our board of directors has determined that Messrs. Haddock, Wilhelm and Bodson qualify as “independent directors” under the listing standards set forth in NYSE Manual Section 303A.

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Our nominating and corporate governance committee is responsible for, among other things:

	•		establishing procedures for evaluating the suitability of potential director nominees and recommending to our board director nominees for election by shareholders or appointment by our board, as the case may be;

	•		reviewing the suitability for continued service as a director of each member of our board of directors upon the expiration of the director’s term or a significant change in such director’s status;

	•		reviewing annually with our board of directors the composition of the board as a whole and recommending measures necessary to ensure compliance with the applicable standards;

	•		reviewing and making recommendations with respect to the size of our board of directors and the frequency and structure of board meetings as proposed by the chairman of our board;

	•		making recommendations to our board regarding the size and composition of each standing committee of our board;

	•		making recommendations concerning any aspect of the procedures of our board of directors that the committee considers warranted;

	•		monitoring the functioning of the committees of our board and making recommendations for any changes that the committee may deem necessary;

	•		reviewing any actual or potential conflict of interest between us and any director having a personal interest in any matter before the board;

	•		developing and reviewing periodically the corporate governance principles adopted by our board to ensure compliance with applicable standards and recommending any desirable change to our board; and

	•		overseeing an annual self-assessment of the board of directors’ performance, as well as the performance of each board committee and overseeing the evaluation of our management, including our chief executive officer.

Corporate Governance

We have adopted a code of conduct that was approved by our board of directors, and that is applicable to all of our directors, officers and employees. Our code of business conduct is publicly available on our website. In addition, our board of directors has adopted a set of corporate governance guidelines.

Interested Transactions

A director may vote with respect to any contract or transaction in which he or she is interested, provided that the nature of the interest of any director in such contract or transaction is disclosed by him or her at or prior to its consideration and any vote in that matter.

Remuneration and Borrowing

The directors may determine remuneration to be paid to the directors. The compensation committee assists the directors in reviewing and approving the compensation structure for the directors. The directors may exercise all the powers of our company to borrow money and to mortgage or charge its undertaking, property and uncalled capital, and to issue debentures or other securities whether outright or as security for any debt obligations of our company or of any third party.

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Indemnification

We have entered into indemnification agreements with our directors and executive officers. With specified exceptions, these agreements provide for indemnification for related expenses including, among other things, attorneys’ fees, judgments, fines and settlement amounts incurred by any of these individuals in any action or proceeding.

There is no currently pending material litigation or proceeding involving any of our directors or officers for which indemnification is sought.

D. Employees

As of December 31, 2009, 2008 and 2007, we had approximately 15,430, 14,380 and 14,620 employees, respectively.

E. Share Ownership

Share Ownership of Directors and Executive Officers

As of the date of this annual report, our directors and executive officers, as a group, beneficially own 1,819,009 of our ordinary shares. In addition, our directors and executive officers hold 262,858 unvested shares. Our directors and executive officers, as a group, beneficially own vested options to acquire 180,105 of our ordinary shares, exercisable at prices ranging from $11.18 to $16.00 per share. In addition, our directors and executive officers hold 949,944 unvested options. The total number of outstanding shares as of the date of this annual report is 244,411,445.


	Ordinary Shares Held by Directors and Executive Officers
	Ordinary Shares
Name	Beneficially Owned		Total Options Owned		Grand Total Owned		Percent
Directors and Executive Officers
Ronald W. Haddock⁽¹⁾		1,553,013		2,792		1,555,805		*
James A. Hughes⁽²⁾		6,918		49,189		56,107		*
Robert Barnes⁽³⁾		457		2,492		2,949		*
Philippe A. Bodson⁽⁴⁾		36,134		2,492		38,626		*
George P. Kay		—		—		—		—
Henri Philippe Reichstul⁽⁵⁾		32,572		2,193		34,765		*
Robert E. Wilhelm⁽⁶⁾		37,466		2,792		40,258		*
Wilfried E. Kaffenberger⁽⁷⁾		—		—		—		—
Julian Green⁽⁷⁾		—		—		—		—
Eduardo Pawluszek⁽⁸⁾		658		4,748		5,406		*
Maureen J. Ryan⁽⁹⁾		6,380		42,888		49,268		*
Emilio Vicens⁽¹⁰⁾		2,281		15,346		17,627		*
Laura C. Fulton⁽¹¹⁾		849		6,677		7,526		*
Andrew Parsons⁽¹²⁾		42,472		15,898		58,370		*
Brian Zatarain⁽¹³⁾		18,927		11,846		30,773		*
Brian Stanley⁽¹⁴⁾		80,882		20,752		101,634		*
All Directors and Executive Officers as a Group		1,819,009		180,105		1,999,114		*


⁽¹⁾		1,553,013 shares are vested and 3,788 shares are unvested. 2,792 options are vested and 21,731 options are unvested. 1,130 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 1,058 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 604 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽²⁾		6,918 shares are vested and 100,654 shares are unvested. 49,189 options are vested and 325,291 options are unvested. 12,917 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 24,195 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 12,077 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽³⁾		457 shares are vested and 3,562 shares are unvested. 2,492 options are vested and 20,361 options are unvested. 1,008 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 945 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 539 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽⁴⁾		36,134 shares are vested and 3,562 shares are unvested. 2,492 options are vested and 20,361 options are unvested. 1,008 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 945 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 539 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

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⁽⁵⁾		32,572 shares are vested and 3,337 shares are unvested. 2,193 options are vested and 18,990 options are unvested. 887 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 831 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 475 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽⁶⁾		37,466 shares are vested and 3,788 shares are unvested. 2,792 options are vested and 21,731 options are unvested. 1,130 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 1,058 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 604 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽⁷⁾		1,696 shares are unvested. 8,940 options are unvested.

⁽⁸⁾		658 shares are vested and 24,287 shares are unvested. 4,748 options are vested and 55,548 options are unvested. 3,023 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 1,725 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽⁹⁾		6,380 shares are vested and 34,874 shares are unvested. 42,888 options are vested and 128,757 options are unvested. 31,431 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 7,258 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 4,199 options have an exercise price of 13.10/share and an expiration date of 2/5/2016.

⁽¹⁰⁾		2,281 shares are vested and 26,295 shares are unvested. 15,346 options are vested and 90,811 options are unvested. 6,458 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 6,048 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 2,840 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽¹¹⁾		849 shares are vested and 17,318 shares are unvested. 6,677 options are vested and 50,629 options are unvested. 4,620 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 2,057 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽¹²⁾		42,472 shares are vested and 21,245 shares are unvested. 15,898 options are vested and 67,899 options are unvested. 7,250 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 6,048 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 2,600 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽¹³⁾		18,927 shares are vested and 16,756 shares are unvested. 11,846 options are vested and 55,458 options are unvested. 5,374 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 4,233 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 2,239 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

⁽¹⁴⁾		1,669 shares vested in February 2010, and 6,929 shares are vesting upon cessation of employment for a total of 80,882 vested shares, 20,752 options are vested and 54,497 options are vesting upon cessation of employment. 12,315 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 5,625 options have an exercise price of $16.00/share and an expiration date of 2/22/2018. 2,812 options have an exercise price of $13.10/share and an expiration date of 2/5/2016.

*		Owns less than 1.00% based on the total number of outstanding shares of 244,113,499 as of December 31, 2009

Incentive Plans

AEI 2007 Incentive Plan

In 2007, we adopted the AEI 2007 Incentive Plan, or the 2007 Incentive Plan, that provides for the awards of options, share appreciation rights, restricted shares, restricted share units, performance shares or performance units, and discretionary annual incentives to certain of our directors, officers and key employees and advisors. Subject to certain adjustments that may be required from time to time to prevent dilution or enlargement of the rights of participants under the 2007 Incentive Plan, a maximum of 15,660,340 shares of ordinary shares are available for grants of all equity awards under the 2007 Incentive Plan. Unless the administration of the 2007 Incentive Plan has been expressly assumed by the board pursuant to a resolution of the board, the compensation committee has full authority and discretion to administer the 2007 Incentive Plan and to take any action that is necessary or advisable in connection with the administration of the 2007 Incentive Plan. The 2007 Incentive Plan may be amended from time to time by the compensation committee or the board. Neither the compensation committee nor the board will authorize the amendment of any outstanding option to reduce the option price without the further approval of our shareholders. Furthermore, no share option will be cancelled and replaced with share options having a lower price without further approval of the shareholders. The 2007 Incentive Plan will expire in 2017. All restricted stock and stock option awards under the 2007 Incentive Plan vest over four years on the following schedule: 10%, 15%, 25% and 50%.

Options

Share option grants may be made at the commencement of employment and, occasionally, following a significant change in job responsibilities or to meet other special retention or performance objectives. Periodic option grants will continue to be made at the discretion of the compensation committee to eligible participants and are generally made annually as part of the total compensation program. Share options granted by us have an exercise price equal to the market value of our ordinary shares on the day of grant and vest based on the required period or periods of continuous service of the participant as stipulated by the provisions of the 2007 Incentive Plan.

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Restricted Share Grants

Our compensation committee has and may in the future elect to make grants of restricted shares to our executive officers.

Performance Shares

For services in 2009 and as part of the total compensation program in 2010, in addition to stock options, share appreciation rights and restricted stock, performance share awards were granted to the executive officers as well as other key employees to further align total compensation with the creation of long-term, sustained shareholder value. Performance share awards, providing performance conditions are met, cliff vest after the end of a three-year performance period.

Other Awards

The compensation committee also has the authority to grant restricted share units, share appreciation rights, performance shares and performance units and discretionary annual incentives to participants under the 2007 Incentive Plan. The amount payable to a participant receiving a grant of restricted share units, performance units or a discretionary annual incentive under the 2007 Incentive Plan may be paid in cash, ordinary shares or in a combination thereof, as determined by the compensation committee. To date, no restricted share units or performance units under the 2007 Incentive Plan have been awarded to any of our executive officers, directors or employees. Due to tax or securities rules in certain foreign jurisdictions, share appreciation rights and restricted share units may be awarded in lieu of stock options and restricted shares, respectively.

Stock Ownership Plan

Our compensation committee is evaluating the possibility of adopting a stock ownership plan for executive officers, which would require a minimum ownership amount of our ordinary shares. No firm proposal has been put forward by the compensation committee to the board as yet and there is no assurance a stock ownership plan in any form will be adopted.

Employment Agreements

We have not entered into employment agreements with any of our executive officers.

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Item 7. Major Shareholders and Related Party Transactions

A. Major Shareholders

The following table sets forth information with respect to the beneficial ownership of our ordinary shares as of December 31, 2009, each person known to us to own beneficially more than 5% of our ordinary shares. None of the shareholders in the table below have voting rights different from any other shareholders. See “Item 10. Additional Information — B. Memorandum and Articles of Association — Voting Rights.”


	Ordinary Shares Held by 5%
	Shareholders
	Ordinary Shares
	Beneficially Owned
Greater than 5% Shareholders	Number		Percent
Ashmore Cayman SPC No. 3 Limited on behalf of and for the account of AEI Segregated Portfolio		20,865,705		8.55	%
Ashmore Global Special Situations Fund 2 Limited		13,169,905		5.39	%
Ashmore Global Special Situations Fund 3 Limited Partnership		23,013,134		9.43	%
Ashmore Global Special Situations Fund 4 Limited Partnership		10,977,303		4.50	%
Ashmore Global Special Situations Fund 5 Limited Partnership		1,000,000		0.41	%
Ashmore SICAV Emerging Markets Debt Fund		4,263,396		1.75	%
Ashmore Global Opportunities Limited		6,237,039		2.55	%
Asset Holder PCC Limited on behalf of the cell, Ashmore Emerging Markets Liquid Investment Portfolio		45,353,925		18.58	%
EMDCD Ltd.		5,091,645		2.09	%
Ashmore Emerging Markets Global Investment Portfolio Limited		1,435,248		0.59	%
Ashmore Growing Multi Strategy Fund Limited⁽¹⁾		1,005,938		0.41	%
Ashmore Emerging Markets Debt and Currency Fund		1,233,864		0.51	%

Total Ashmore Funds		133,647,102		54.75	%

Buckland Investment Pte Ltd.⁽²⁾		54,588,392		22.36	%

Sherbrooke, Ltd.⁽³⁾		13,931,097		5.71	%


⁽¹⁾		In February 2010, Ashmore Growing Multi Strategy Fund Limited transferred 100,000 ordinary shares to Ashmore SICAV Emerging Markets Debt Fund.

⁽²⁾		Buckland Investment Pte Ltd shares the power to vote and the power to dispose of the shares with each of GIC Special Investments Pte Ltd and the Government of Singapore Investment Corporation Pte Ltd., each of which is a Singapore private limited company. No individual has beneficial ownership over these shares. Voting and investment decisions relating to these shares are made by the GIC Special Investments Pte Ltd. investment committee, which is currently comprised of eight members: Teh Kok Peng, Ng Kin Sze, Ang Eng Seng, Kunna Chinniah, Tay Lim Hock, Eugene Wong, John Tang and Mayukh Mitter.

⁽³⁾		Eton Park Capital Management, L.P. is the investment manager for Sherbrooke, Ltd. Eric M. Mindich controls Eton Park Capital Management, L.P. as the managing member of its general partner, Eton Park Capital Management, L.L.C.

We have entered into a shareholders agreement with our shareholders which details certain rights and obligations. For a description of the agreement, see “Item 10. Additional Information — C. Material Contracts.”

B. Related Party Transactions

Ashmore Management Services Agreement

Effective May 20, 2006, we entered into a management services agreement with Ashmore for the provision of certain services, including operational, administrative and technical services. To date, Ashmore has provided services with respect to strategic and development activities and we expect they will continue to provide similar services in the future.

The management services agreement provides for successive one-year terms and is automatically renewed in May each year unless terminated. The management services agreement may be terminated by either party 30 days prior to the end of a term. During the term, we may terminate upon 90 days’ written notice generally or 14 days’ written notice for a particular subsidiary if there has been a sale or change of control of such subsidiary. In addition, we may terminate for non-performance by Ashmore. Ashmore may terminate if we fail to pay invoices within 60 days of the invoice date.

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Under the management services agreement, we must pay to Ashmore the actual costs of employees performing the services (including salary, bonus, benefits and long-term incentive grants) and reasonable and documented expenses, such as travel costs and the services of third-party professionals. The aggregate maximum amount of fees that may be paid under the agreement during each one-year term is $4.5 million. We have paid Ashmore $3.5 million and $4.5 million, respectively, under this agreement in each of the last two one-year terms. The majority of the amounts were for services provided with respect to strategic and business development activities.

PIK Notes

On May 24, 2007, we completed the redemption of our $527 million subordinated PIK Notes, plus $52 million in accrued interest and issued new subordinated PIK Notes in the aggregate principal amount of $300 million. Several of our shareholders hold some of the new subordinated PIK Notes.

On March 11, 2009, we amended the PIK Note Purchase Agreement in order to issue an option to all of our PIK note holders to exchange their PIK Notes for ordinary shares of AEI. The option period expired on March 12, 2010. Additionally, the amendment allows us to purchase the PIK Notes in the open market, subject to certain conditions. In March, August and October 2009, various Ashmore Funds exercised their option to convert their PIK Notes and related interest receivable in the amount of $196 million for 12,084,075 of our ordinary shares. For more information, see “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources —Parent Company Long-term Debt.”

Consulting Agreement

Brian Stanley, who retired as our VP, Operations in February 2010, entered into a consulting agreement with us, effective as of March 1, 2010, pursuant to which he will provide consulting services to us on an as-requested basis. The consulting agreement terminates on December 31, 2010 and continues thereafter on a month-by-month basis unless otherwise agreed by Mr. Stanley and us or terminated in accordance with the provisions of the agreement. As of the date of this annual report, no payouts have been made under this agreement.

C. Interests of Experts and Counsel

Not applicable.

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Item 8. Financial Information

A. Consolidated Statements and Other Financial Information

See “Item 3. Key Information — A. Selected Financial Data” and “Item 18. Financial Statements.”

8.A.7 Legal Proceedings

The information in Note 25 of the Notes to our Consolidated Financial Statements in Item 18 of this annual report is hereby incorporated by reference in response to this item.

8.A.8 Dividend Policy

We historically have not paid dividends. Any future determination to pay dividends would be at the discretion of, and require the approval of, our board of directors, and would depend on our financial condition, results of operations, future prospects, capital requirements, restrictions contained in future financing instruments and other factors our board of directors deems relevant.

Under Cayman Islands law, we may declare cash dividends or make other distributions only out of profits lawfully available for the purpose, or out of our share premium account, which is the same as additional paid-in capital, if we will thereafter have the ability to pay our debts in the ordinary course as they fall due. Cash dividends, if any, will be paid by us in U.S. dollars.

We are a holding company with no material assets other than the stock of our subsidiaries. All of our revenue-generating operations are conducted through our subsidiaries. Accordingly, almost all of our cash flow is generated by our subsidiaries. Our subsidiaries are separate and distinct legal entities and have no obligation to make any funds available to us, whether by dividends, fees, loans or other payments. Accordingly, our ability to pay dividends is dependent on the ability of our subsidiaries to distribute cash to us in the form of dividends, fees, principal, interest, loans or otherwise. Our subsidiaries may be obligated, pursuant to loan agreements, indentures or project financing arrangements, to satisfy certain obligations or other conditions before they may make distributions to us.

Our credit agreement prohibits us from paying dividends if an event of default has occurred under the agreement and if we cease to be in compliance with certain financial ratios as a result of making the dividend payment. Therefore, our ability to pay dividends on our ordinary shares will depend upon, among other things, our level of indebtedness at the time of the proposed dividend and whether we are in compliance with the covenants under our credit agreement. Our future dividend policy will also depend on the requirements of any future financing agreements to which we may be a party and other factors considered relevant by our board of directors.

B. Significant Changes

Not applicable.

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Item 10. Additional Information

A. Share Capital

Not required because this document is filed as an annual report.

B. Memorandum and Articles of Association

We incorporate by reference into this annual report the information called for by Item 10B set forth in our registration statement on Form 20-F (File No. 000-53606) originally filed with the SEC on March 27, 2009, as amended.

C. Material Contracts

The following Material Contracts are attached as exhibits to this annual report:

1. Amended and Restated Credit Agreement, dated as of June 6, 2008, among AEI, AEI Finance Holding LLC, various financial institutions as lenders, Credit Suisse, Cayman Islands Branch, as Revolving LC Issuer, Synthetic LC Issuer, and Administrative Agent, JP Morgan Chase Bank, N.A., as Collateral Agent, Credit Suisse Securities (USA) LLC and J.P. Morgan Securities, Inc. as Joint Lead Arrangers, Joint Bookrunners and Joint Syndication Agents and Credit Suisse Securities (USA) LLC as sole Structuring and Sole Documentation Agent. The credit facility consists of a $1 billion term loan facility that matures on March 30, 2014 and a $395 million revolving credit facility and a $105 million synthetic revolving credit facility that both mature on March 30, 2012. The material terms of this agreement are described in “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources.”

2. AEI 2007 Incentive Plan. The 2007 Incentive Plan, as amended and restated on December 14, 2009, which will expire in 2017, provides for the awards of options, share appreciation rights, restricted shares, restricted share units, performance shares or performance units, and discretionary annual incentives to certain directors, officers and key employees and advisors of AEI. The material terms of this agreement are described in “Item 6. Directors, Senior Management and Employees — E. Share Ownership.”

3. Concession Contract 187/98, dated August 27, 1998, between ANEEL and Elektro Eletricidade e Serviços S.A., as amended. Elektro holds a 30-year renewable concession from ANEEL covering 223 municipalities in the state of São Paulo. Elektro’s concession agreement, the first term of which expires in 2028, provides exclusive distribution rights within the concession area. The material terms of this agreement are described in “Item 4. Information on the Company — B. Business Overview — Power Distribution — Elektro Electricidade e Serviços S.A. (Elektro) — Concession and Contractual Agreements.”

4. Second Amended and Restated Shareholders Agreement. The shareholders agreement, dated May 9, 2008, among AEI and the shareholders of AEI identified therein, provides that at any general meeting of the shareholders involving the election of directors, each shareholder will (i) vote all shares that it is entitled to vote to elect a member of the board of directors in accordance with the provision that Buckland shall be entitled to appoint one director of AEI and Ashmore will be entitled to appoint the remainder of the directors and (ii) not vote to remove any director designated in accordance with the agreement except at the express written direction of the shareholder(s) that designated such director. The agreement also provides that any issuance of securities by AEI or sale of securities by a shareholder that is otherwise permitted under the agreement shall be subject to the condition that the transferee shall, upon consummation of such sale, if the transferee is not already a shareholder, execute an addendum to the agreement, agreeing to be bound by the terms of the agreement. Finally, under the terms of the agreement, Ashmore and Buckland each have rights of first refusal with respect to a proposed sale pursuant to which the transferee would acquire more than 10% of the outstanding shares of AEI. Pursuant to the Amendment to the Shareholders Agreement, dated as of October 29, 2009, the agreement will terminate upon consummation of an offering, involving not less than $200 million of gross proceeds (to AEI and/or its shareholders), upon the completion of which the shares will be listed on a stock exchange.

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5. Amended and Restated Registration Rights Agreement. The registration rights agreement provides the holders of our ordinary shares party to the agreement (our Investors) with certain rights to require us to register their shares for resale under the Securities Act of 1933, as amended, or the Securities Act. Pursuant to the registration rights agreement, if we receive, (i) at any time six months after the effective date of our initial public offering, a written request from Investors holding 10% or more of the ordinary shares subject to the agreement (referred to therein as Registrable Securities) or (ii) if a public offering has not previously occurred, at any time after May 25, 2009, a written request from holders of a majority of our outstanding ordinary shares not owned by the Ashmore Funds, we are required to file a registration statement under the Securities Act in order to register the resale of the amount of ordinary shares requested by such Investors (a Requested Registration). We may, in certain circumstances, defer such registrations and any underwriters will have the right, subject to certain limitations, to limit the number of shares included in such registrations. The Ashmore Funds have the right to require us to file two Requested Registrations and Investors other than the Ashmore Funds have the right to require us to file two Requested Registrations. In addition, if we propose to register any of our securities under the Securities Act, either for our own account or for the account of other security holders, Investors are entitled to notice of such registration and are entitled to certain “piggyback” registration rights allowing such holders to include their ordinary shares in such registration, subject to certain marketing and other limitations. Further, Investors may require us to register the resale of all or a portion of their shares on a registration statement on Form F-3 or Form S-3 once we are eligible to use Form F-3 or Form S-3, subject to certain conditions and limitations. In an underwritten offering, the managing underwriter, if any, has the right, subject to specified conditions, to limit the number of Registrable Securities Investors may include.

6. Form of Indemnification Agreement, dated as of January 1, 2010, by and between AEI and the officer or director of AEI party thereto. This agreement provides for indemnification for related expenses including, among other things, attorneys’ fees, judgments, fines and settlement amounts incurred by any of these individuals in any action or proceeding relating to actions by the individual in his or her official capacity as an officer or director of AEI.

D. Exchange Controls

Under Cayman Islands law, there are currently no restrictions on the export or import of capital, including foreign exchange controls or restrictions that affect the remittance of dividends, interest or other payments to nonresident holders of our shares.

E. Taxation

The following is a general summary of the material Cayman Islands and U.S. federal income tax consequences relevant to our ordinary shares. The discussion is based on laws and relevant interpretations thereof in effect as of the date hereof, all of which are subject to change or different interpretations, possibly with retroactive effect. The discussion does not address United States state or local tax laws, or tax laws of jurisdictions other than the Cayman Islands and the United States.

Cayman Islands Taxation

The Cayman Islands currently levy no taxes on individuals or corporations based upon profits, income, gains or appreciation and there is no taxation in the nature of inheritance tax or estate duty. Shareholders will not be subject to Cayman Islands taxation on payments of dividends or upon the repurchase by us of ordinary shares. In addition, shareholders will not be subject to withholding tax on payments of dividends or distributions, including upon a return of capital, nor will gains derived from the disposal of ordinary shares be subject to Cayman Islands income or corporation tax.

No Cayman Islands stamp duty will be payable by shareholders in respect of the issue or transfer of ordinary shares. However, an instrument transferring title to an ordinary share, if brought to or executed in the Cayman Islands, would be subject to Cayman Islands stamp duty. The Cayman Islands are not party to any double taxation treaties. There are no exchange control regulations or currency restrictions in the Cayman Islands.

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We have, pursuant to Section 6 of the Tax Concessions Law (1999 Revision) of the Cayman Islands, obtained an undertaking from the Governor in Cabinet that:

	•		no law which is enacted in the Cayman Islands imposing any tax to be levied on profits or income or gains or appreciation applies to us or our operations; and

	•		the aforesaid tax or any tax in the nature of estate duty or inheritance tax are not payable on our ordinary shares, debentures or other obligations.

The undertaking that we have obtained is for a period of 20 years from July 8, 2003.

United States Federal Income Taxation

The discussion of U.S. federal income tax matters set forth herein was not intended or written to be used, and cannot be used by any prospective taxpayer, for the purpose of avoiding tax-related penalties under U.S. federal, state or local tax law. Each taxpayer should seek advice based on its particular circumstances from an independent tax advisor.

The following is a summary of certain U.S. federal income tax considerations relevant to a U.S. Holder (as defined below) acquiring, holding and disposing of ordinary shares. This summary is based upon existing U.S. federal income tax law, which is subject to change, possibly with retroactive effect. This summary does not discuss all aspects of U.S. federal income taxation which may be important to particular investors in light of their individual investment circumstances, including investors subject to special tax rules, such as financial institutions, insurance companies, broker-dealers, tax-exempt organizations, partnerships, partners in partnerships that invest in ordinary shares, holders who are not U.S. Holders, holders who own (directly or through attribution) 10% or more of our ordinary shares, investors that will hold our ordinary shares as part of a straddle, hedge, conversion, constructive sale, or other integrated transaction for U.S. federal income tax purposes, or investors that have a functional currency other than the U.S. dollar, all of whom may be subject to tax rules that differ significantly from those summarized below. In addition, this summary does not discuss any non-U.S., state or local tax considerations. This summary assumes that investors will hold their ordinary shares as “capital assets” (generally, property held for investment) for U.S. federal income tax purposes. U.S. Holders are urged to consult their tax advisors regarding the U.S. federal, state, local and non-U.S. income and other tax considerations relevant to an investment in the ordinary shares.

For purposes of this summary, a “U.S. Holder” is a beneficial owner of ordinary shares that is for U.S. federal income tax purposes (i) an individual who is a citizen or resident of the United States, (ii) a corporation created in, or organized under the law of, the United States or any State or political subdivision thereof, (iii) an estate the income of which is includible in gross income for U.S. federal income tax purposes regardless of its source, or (iv) a trust the administration of which is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust.

Dividends

The U.S. dollar value of any distributions paid by us out of our earnings and profits, as determined under U.S. federal income tax principles, generally will be subject to tax as foreign source ordinary dividend income and will be includible in a U.S. Holder’s gross income upon receipt. Dividends received on our shares will not be eligible for the dividends received deduction generally allowed to corporations. Non-corporate investors who receive dividends on our shares will not be eligible for the 15% rate of federal income tax available for dividends that are paid by certain corporations in tax years beginning on or before December 31, 2010.

Sale or Other Disposition of Ordinary Shares

A U.S. Holder generally will recognize U.S. source capital gain or loss upon the sale or other disposition of ordinary shares in an amount equal to the difference between the amount realized upon the disposition and the U.S. Holder’s adjusted tax basis in such ordinary shares. A U.S. Holder’s adjusted basis in its ordinary shares will generally equal the U.S. dollar value of the amount paid for such shares. Any capital gain or loss will be long-term capital gain or loss if the ordinary shares have been held for more than one year. The deductibility of capital losses is subject to limitations.

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Passive Foreign Investment Company Rules

AEI was not a “passive foreign investment company,” or PFIC, (as defined in Section 1297 of the Code) for its most recently completed taxable year. Based on currently available information, we do not believe that AEI will be classified as a PFIC for U.S. federal income tax purposes. However, the determination of whether AEI is a PFIC will be made annually. Therefore, it is possible that AEI could become a PFIC in the current or any future year due to changes in the assets or income composition of our company and our subsidiaries. In general, a non-U.S. corporation is classified as a PFIC for any taxable year if at least (i) 75% of its gross income is classified as “passive income” or (ii) 50% of the average quarterly value of its assets produce or are held for the production of passive income. In making this determination, the non-U.S. corporation is treated as earning its proportionate share of any income and owning its proportionate share of any assets of any company in which it holds a 25% or greater interest, by value. For these purposes, cash is considered a passive asset and gross interest is considered as passive income. If AEI were considered a PFIC at any time that a U.S. Holder holds our ordinary shares, it will continue to be treated as a PFIC with respect to such U.S. Holder’s investment unless such U.S. Holder has made certain elections under the PFIC rules.

If AEI is considered a PFIC at any time that a U.S. Holder holds our ordinary shares, such U.S. Holder may be subject to materially adverse U.S. federal income tax consequences compared to an investment in a company that is not considered a PFIC, including being subject to greater amounts of U.S. tax and being subject to additional tax-form filing requirements. U.S. Holders should consult their own tax advisors about the application of the PFIC rules to them.

Backup withholding and information reporting requirements

U.S. federal backup withholding and information reporting requirements may apply to certain payments of dividends on, and proceeds from the sale, taxable exchange or redemption of ordinary shares held by U.S. Holders. A portion of any such payment may be withheld as a backup withholding against a U.S. Holder’s potential U.S. federal income tax liability if such U.S. Holder fails to establish that it is exempt from these rules, furnish a correct taxpayer identification number or otherwise fail to comply with such backup withholding and information reporting requirements. Corporate U.S. Holders are generally exempt from the backup withholding and information requirements, but may be required to comply with certification and identification requirements in order to establish their exemption. Any amounts withheld under the backup withholdings rules from a payment to a U.S. Holder will be credited against such U.S. Holder’s U.S. federal income tax liability, if any, or refunded if the amount withheld exceeds such tax liability, provided the required information is furnished to the Internal Revenue Service.

The above summary is not intended to constitute a complete analysis of all U.S. federal income tax consequences to a U.S. Holder of acquiring, holding, and disposing of ordinary shares. U.S. Holders should consult their own tax advisors with respect to the U.S. federal, state, local and non-U.S. consequences of acquiring, holding and disposing of ordinary shares.

F. Dividends and Paying Agents

Not required because this document is filed as an annual report.

G. Statement by Experts

Not required because this document is filed as an annual report.

H. Documents on Display

We filed with the SEC a registration statement on Form 20-F that was declared effective on March 31, 2009 and therefore are subject to the informational requirements of the Exchange Act. We are required to file and/or furnish reports and other information with the SEC, including annual reports on Form 20-F and reports on Form 6-K. You may inspect and copy reports and other information to be filed with the SEC at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of the materials may be obtained from the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549 at prescribed rates. The public may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC in the United States at 1-800-SEC-0330. In addition, the SEC maintains an internet website at http://www.sec.gov, from which you can electronically access these materials.

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Item 11. Quantitative and Qualitative Disclosures About Market Risk

Quantitative and Qualitative Analysis of Market Risk

Overview Regarding Market Risks

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

Interest Rate Risks

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable-rate debt and fixed-rate debt, as well as interest rate swap and option agreements both at the AEI level and at the subsidiary level. As of December 31, 2009, our floating rate debt at the AEI level consisted primarily of a $893 million term loan facility, $113 million of drawn revolving credit facility and a $105 million synthetic credit facility. Although all three facilities are based on floating rates, we have mitigated our interest rate exposure by entering into interest rate swaps. We are also exposed to interest rate fluctuations at some of our subsidiaries, the primary ones being Elektro, Promigas and Proenergía. In some of those subsidiaries, the interest rate fluctuations are partially hedged through their tariff adjustment mechanism. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we may hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Using sensitivity analysis and a hypothetical 1% increase in interest rates across all the consolidated debt facilities, without taking into consideration offsetting tariff adjustments or tax shield, the increase in annual interest expense on all of our variable-rate debt would reduce net income by $23 million.

Foreign Exchange Rate Risk

A significant portion of our operating income is exposed to foreign exchange fluctuations. We are primarily exposed to fluctuation in the exchange rate between the U.S. dollar and the Brazilian real and the Colombian peso. Our exposure to currency exchange rate fluctuations results from the translation exposure associated with the preparation of our consolidated financial statements, and from transaction exposure associated with generating revenues and incurring expenses in different currencies. Currency fluctuations may also affect the earnings of subsidiaries where we are unable to match external indebtedness with the functional currency of the business, and consequently may affect our consolidated earnings. Fluctuations in exchange rates and currency devaluations affect our cash flow as cash distributions received from those of our subsidiaries operating in local currencies might be different from forecasted distributions due to the effect of exchange rate movements. Further, the devaluation of local currency revenues against the U.S. dollar may impair the value of the investment in U.S. dollars. While our consolidated financial statements are reported in U.S. dollars, the financial statements of some of our subsidiaries are prepared using the local currency as the functional currency and translated into U.S. dollars by applying an appropriate exchange rate. Accordingly, changes in exchange rates relative to the U.S. dollar could have a material adverse effect on our earnings, assets and cash flows. Most countries in which we operate use local currencies, many of which have fluctuated significantly against the U.S. dollar in the past.

Based on historical results, a 10% devaluation of the Brazilian real and the Colombian peso in 2009 would result in an estimated net loss on the translation of local currency earnings of approximately $19 million and $5 million, respectively, to our consolidated statement of operations for the year ended December 31, 2009. We estimate that the consolidated balance sheet as of December 31, 2009 would be negatively impacted by approximately $96 million and $47 million, respectively, in currency translation through the cumulative translation adjustment in accumulated other comprehensive income as a result of a 10% devaluation of the Brazilian real and the Colombian peso as of December 31, 2009.

To manage the impact of currency fluctuation on cash flow from dividends of certain of our subsidiaries, we hedge part of our future dividends (especially those denominated in Brazilian real) from time to time. To ensure stability of our income, we document and record the hedges as net investment hedges prior to the declaration of the dividend and then document and redesignate them after dividends are declared.

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The notional and fair market values of positions which will mature in 2010, were as follows:


	As of December 31, 2009
	Notional Amount		Fair Value
	(In millions of U.S. Dollars)
Foreign Currency Forward Contracts
Designated as Net Investment Hedge
Sell Brazilian real, buy U.S. dollar	$	88	$	1
Foreign Currency Forward Contract
Not Designated as Hedge
Sell Argentine peso, buy U.S. dollar		3		—
Sell Brazilian real, buy U.S. dollar		10		—

Commodity Price Risk

Although most of the businesses operate under long-term contracts or retail sales concessions, a small minority of current and expected future revenues are derived from businesses without significant long-term sales or supply contracts. The results of operations of these businesses are subject to the volatility of electricity and fuel prices in competitive markets. To mitigate these risks, we may use a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy may involve the use of commodity forward contracts, futures, swaps or options. We may also enter into long-term supply contracts containing price escalators for the supply of fuel and electricity. In all other cases, our contracts allow us to either pass-through to our customers our full commodity costs or to escalate our prices to track applicable commodity price indices.

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Item 15. Controls and Procedures

Disclosure Controls and Procedures

Our management has evaluated, as of December 31, 2009, our disclosure controls and procedures. Such controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act are (i) recorded, processed, summarized and reported within the time periods specified in SEC rules and forms; and (ii) accumulated and communicated to our management, including our Chief Executive Officer and EVP, Chief Financial Officer as appropriate to allow timely decisions regarding required disclosure. Based on such evaluation, our Chief Executive Officer and EVP, Chief Financial Officer, concluded that, as of December 31, 2009, our disclosure controls and procedures were effective.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. Under the supervision and with the participation of our Chief Executive Officer and our EVP, Chief Financial Officer, our management evaluated the effectiveness of our internal control over financial reporting based upon the framework in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management has concluded that our internal control over financial reporting as at December 31, 2009 is effective.

This annual report does not contain an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Our report herein was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Item 16C. Principal Accountant Fees and Services

The following table presents an allocation of aggregated fees billed to us by our principal accounting firm, Deloitte & Touche LLP, or Deloitte, for the fiscal years ended December 31, 2009 and 2008, for professional services rendered.


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Audit fees^(a)	$	9.6	$	13.1
Audit-related fees^(b)		1.8		0.4
Tax Fees^(c)		0.5		0.2
Other fees^(d)		0.3		—


(a)		Includes fees for the audit of the Company’s annual financial statements, the review of quarterly financial statements, services in connection with statutory and regulatory filings or engagements, and comfort letters and consents for financings and filings made with the SEC.

(b)		Fees for the review of internal control procedures and due diligence work and consultation in connection with various business and financing transactions.

(c)		Our principal accounting firm does not provide tax consulting and advisory services to AEI or any of its affiliates.

(d)		Includes fees for non-audit services consisting of miscellaneous projects.

Approval of Fees — Our audit committee has procedures for pre-approving audit and non audit services to be provided. The procedures are designed to ensure the continued independence of the independent auditor. The use of the independent auditor to perform either audit or non audit services is prohibited unless specifically approved in advance by our audit committee. As a result of this approval process, our audit committee has established specific categories of services and authorization levels. All services outside of the specified categories and all amounts exceeding the authorization levels are reviewed by the chairman of our audit committee, who serves as the committee designee to review and approve audit and non audit related services during the year. A listing of the approved audit and non audit services is reviewed with the full audit committee no later than its next meeting. Our audit committee has approved 100% of the 2009 and 2008 services provided by Deloitte.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
AEI
c/o AEI Services LLC
Houston, TX

We have audited the accompanying consolidated balance sheets of AEI and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in Schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEI and subsidiaries financial position of AEI as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.



/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 31, 2010

F-2

AEI AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2009		2008
	(Millions of dollars (U.S.),
	except share and par value data)
ASSETS
Current assets:
Cash and cash equivalents	$	682	$	736
Restricted cash		77		83
Accounts and notes receivable:
Trade (net of allowance of $78 and $69, respectively)		932		863
Unconsolidated affiliates		16		11
Inventories		273		239
Prepaids and other current assets		401		384

Total current assets		2,381		2,316
Property, plant and equipment, net		4,200		3,524
Investments in and notes receivable from unconsolidated affiliates		1,177		907
Goodwill		663		614
Intangibles, net		489		393
Other assets		1,315		1,199
Total assets	$	10,225	$	8,953
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	608	$	572
Unconsolidated affiliates		31		30
Current portion of long-term debt, including related party		613		547
Accrued and other liabilities		862		594

Total current liabilities		2,114		1,743
Long-term debt, including related party		3,105		3,415
Deferred income taxes		168		199
Other liabilities		1,393		1,331
Commitments and contingencies
Equity:
Common stock, $0.002 par value, 5,000,000,000 shares authorized; 244,113,499 and 224,624,481 shares issued and outstanding		—		—
Additional paid-in capital		1,966		1,754
Retained earnings		577		280
Accumulated other comprehensive income (loss)		289		(204	)

Total shareholders’ equity attributable to AEI		2,832		1,830
Equity attributable to noncontrolling interests		613		435

Total equity		3,445		2,265

Total liabilities and equity	$	10,225	$	8,953

See notes to consolidated financial statements.

F-3

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Years Ended
	December 31,
	2009			2008			2007
	(Millions of dollars (U.S.),
	except per share data)

Revenues	$	8,185		$	9,211		$	3,216

Costs of sales		6,238			7,347			1,796

Operating expenses:
Operations, maintenance, and general and administrative expenses		863			894			630
Depreciation and amortization		272			268			217
Taxes other than income		45			43			43
Other charges		123			56			50
(Gain) loss on disposition of assets		20			(93	)		(21	)

Total operating expenses		1,323			1,168			919

Equity income from unconsolidated affiliates		107			117			76

Operating income		731			813			577

Other income (expense):
Interest income		74			88			110
Interest expense		(327	)		(378	)		(306	)
Foreign currency transaction gain (loss), net		9			(56	)		19
Gain (loss) on early retirement of debt		10			—			(33	)
Other income (expense), net		70			9			(22	)

Total other expense		(164	)		(337	)		(232	)

Income before income taxes		567			476			345
Provision for income taxes		279			194			193

Income from continuing operations		288			282			152
Income from discontinued operations		—			—			3
Gain from disposal of discontinued operations		—			—			41

Net income		288			282			196
Less: Net income (loss) attributable to noncontrolling interests		(9	)		124			65

Net income attributable to AEI	$	297		$	158		$	131


Basic and diluted earnings per share:
Income from continuing operations attributable to AEI	$	1.27		$	0.73		$	0.42
Discontinued operations attributable to AEI		—			—			0.21

Net income attributable to AEI	$	1.27		$	0.73		$	0.63


Amounts attributable to AEI:
Income from continuing operations	$	297		$	158		$	87

Discontinued operations		—			—			44

Net income	$	297		$	158		$	131

See notes to consolidated financial statements.

F-4

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Years Ended
	December 31,
	2009			2008			2007
	(Millions of dollars (U.S.))
Cash flows from operating activities:
Net income	$	288		$	282		$	196
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		272			268			217
Other charges		123			56			50
Deferred revenues		58			55			120
Deferred income taxes		69			11			106
Equity earnings from unconsolidated affiliates		(107	)		(117	)		(76	)
Distributions from unconsolidated affiliates		53			67			28
Foreign currency transaction (gain) loss, net		(9	)		56			(19	)
(Gain) loss on disposition of assets		20			(93	)		(21	)
Gain from disposal of discontinued operations		—			—			(41	)
(Gain) loss on early retirement of debt		(10	)		—			33
Changes in operating assets and liabilities, net of translation, acquisitions dispositions and non-cash items:
Trade receivables		(48	)		(85	)		(59	)
Accounts payable, trade		1			24			77
Inventories		68			(15	)		(7	)
Prepaids and other current assets		1			4			(5	)
Regulatory assets and liabilities		32			(32	)		102
Other		10			27			(15	)

Net cash provided by operating activities		821			508			686

Cash flows from investing activities:
Proceeds from sale of investments		60			99			162
Capital expenditures		(441	)		(372	)		(249	)
Cash paid for acquisitions, exclusive of cash and cash equivalents acquired		(171	)		(253	)		(1,111	)
Cash and cash equivalents acquired		18			60			21
Decrease in restricted cash		265			199			283
Increase in restricted cash		(256	)		(121	)		(222	)
Contributions to unconsolidated subsidiaries		(9	)		—			—
Other		(25	)		(26	)		(35	)

Net cash used in investing activities		(559	)		(414	)		(1,151	)

Cash flows from financing activities:
Issuance of debt		1,692			1,367			2,418
Repayment of debt		(1,883	)		(1,226	)		(2,205	)
Payment of debt issuance costs		—			—			(18	)
Proceeds from issuance of common shares		—			200			—
Dividends paid to noncontrolling interests		(71	)		(167	)		(101	)
Purchase of subsidiary shares from noncontrolling interests		(90	)		—			—
Other		(18	)		(1	)		(6	)

Net cash (used in) provided by financing activities		(370	)		173			88

Effect of exchange rate changes on cash		54			(47	)		63

Increase (decrease) in cash and cash equivalents		(54	)		220			(314	)
Cash and cash equivalents, beginning of period		736			516			830

Cash and cash equivalents, end of period	$	682		$	736		$	516


Cash payments for income taxes, net of refunds	$	174		$	173		$	172

Cash payments for interest, net of amounts capitalized	$	278		$	264		$	246

Non-cash exchange of related party debt for common shares	$	196		$	—		$	—

Non-cash payments for acquisitions	$	75		$	24		$	—

See notes to consolidated financial statements.

F-5

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY


	AEI
									Accumulated
			Additional			Retained			Other
	Common		Paid-In			Earnings			Comprehensive			Noncontrolling
	Stock		Capital			(Deficit)			Income (Loss)			Interests			Total Equity
						(Millions of dollars (U.S.))

Balance, January 1, 2007	$	—	$	1,433		$	(9	)	$	17		$	357		$	1,798

Comprehensive income:
Net income		—		—			131			—			65			196
Foreign currency translation		—		—			—			210			2			212
Amortization of actuarial and investment loss, net of income tax of $8		—		—			—			16			—			16
Changes in fair value of derivatives, net of settlements, net of income tax of $0		—		—			—			(25	)		(2	)		(27	)
Change in fair value of available-for-sale- securities, net of income tax of $0		—		—			—			(3	)		—			(3	)

Total comprehensive income		—		—			131			198			65			394
Contribution of invested capital		—		79			—			—			—			79
Compensation under stock incentive plan		—		9			—			—			—			9
Dividends		—		—			—			—			(91	)		(91	)
Changes in ownership		—		—			—			—			(40	)		(40	)
Other		—		—			—			—			(3	)		(3	)

Balance, December 31, 2007	$	—	$	1,521		$	122		$	215		$	288		$	2,146

Comprehensive income:
Net income		—		—			158			—			124			282
Foreign currency translation		—		—			—			(343	)		(43	)		(386	)
Amortization of actuarial and investment loss, net of income tax of $16		—		—			—			32			—			32
Changes in fair value of derivatives, net of settlements, net of income tax of $2		—		—			—			(43	)		—			(43	)
Change in fair value of available-for-sale- securities, net of income tax of $0		—		—			—			(62	)		—			(62	)
Other		—		—			—			(3	)		—			(3	)

Total comprehensive income		—		—			158			(419	)		81			(180	)
Issuance of new shares		—		223			—			—						223
Compensation under stock incentive plan		—		7			—			—						7
Dividends		—		—			—			—			(161	)		(161	)
Changes in ownership		—		—			—			—			229			229
Other		—		3			—			—			(2	)		1

Balance, December 31, 2008	$	—	$	1,754		$	280		$	(204	)	$	435		$	2,265

Comprehensive income:
Net income		—		—			297			—			(9	)		288
Foreign currency translation		—		—			—			396			27			423
Amortization of actuarial and investment gain, net of income tax of ($2)		—		—			—			(4	)		—			(4	)
Changes in fair value of derivatives, net of settlements, net of income tax of $0		—		—			—			32			—			32
Change in fair value of available-for-sale- securities, net of income tax of $0		—		—			—			69			—			69

Total comprehensive income		—		—			297			493			18			808
Issuance of new shares		—		279			—			—			—			279
Compensation under stock incentive plan		—		5			—			—			—			5
Dividends		—		—			—			—			(54	)		(54	)
Changes in ownership		—		(100	)		—			—			218			118
Other		—		—			—			—			(4	)		(4	)
Gain on PIK note exchanges		—		28			—			—			—			28

Balance, December 31, 2009	$	—	$	1,966		$	577		$	289		$	613		$	3,445

See notes to consolidated financial statements.

F-6

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE COMPANY AND OPERATIONS

AEI (the “Parent Company”), a Cayman Islands exempted company, was formed on June 24, 2003. The Parent Company, which is a holding company, owns and operates its businesses through a number of holding companies, management services companies (collectively, “Holding Companies”), and operating companies (collectively, the “Company”). AEI, through its investments, is involved principally in power distribution, power generation, natural gas transportation and services, natural gas distribution, and retail fuel businesses entirely outside of the United States of America. The Parent Company’s controlling shareholders are investment funds (the “Ashmore Funds”), which have directly or indirectly appointed Ashmore Investment Management Limited (“Ashmore”) as their investment manager.

The operating companies of AEI as of December 31, 2009 include direct and indirect investments in the international businesses described below and are collectively referred to as the “Operating Companies”:


	Ownership	Accounting	Location of
Company Name	Interest (%)	Method	Operations	Segment
Accroven SRL (“Accroven”)	49.25	Equity Method	Venezuela	Natural gas transportation and services
Beijing MacroLink Gas Co. Ltd (“BMG”)(a)(b)	70.00	Consolidated	China	Natural gas distribution
Gas Natural de Lima y Callao S.A. (“Calidda”)(b)	80.85	Consolidated	Peru	Natural gas distribution
Chilquinta Energia S.A. (“Chilquinta”)(b)(c)	50.00	Equity Method	Chile	Power distribution
Consorcio Eólico Amayo S.A. (“Amayo”)(d)(e)	13.42	Equity Method	Nicaragua	Power generation
DHA Cogen Limited (“DCL”)(b)	60.23	Consolidated	Pakistan	Power generation
Distribuidora de Electricidad Del Sur, S.A. de C.V. (“Delsur”)(b)	86.41	Consolidated	El Salvador	Power distribution
Empresa Distribuidora de Energia Norte, S.A. (“EDEN”)(b)	90.00	Consolidated	Argentina	Power distribution
Elektra Noreste S.A. (“Elektra”)	51.00	Consolidated	Panama	Power distribution
Elektrocieplownia Nowa Sarzyna Sp. z.o.o. (“ENS”)	100.00	Consolidated	Poland	Power generation
Elektro — Eletricidade e Serviços S.A. (“Elektro”)	99.68	Consolidated	Brazil	Power distribution
Emgasud S.A. (“Emgasud”)(a)(d)(f)	42.73	Equity Method	Argentina	Power generation
Empresa Distribuidora Electrica Regional S.A. (“EMDERSA”)(d)(g)	77.10	Consolidated	Argentina	Power distribution
Empresa Energetica Corinto Ltd. (“Corinto”)(b)(e)	57.67	Consolidated	Nicaragua	Power generation
EPE — Empresa Produtora de Energia Ltda. (“EPE”)(d)(l)	100.00	Consolidated	Brazil	Power generation
Fenix Power Peru S.A. (“Fenix”)(a)	86.05	Consolidated	Peru	Power generation
Gas Transboliviano S.A. (“GTB”)(d)(m)	34.65	Equity Method	Bolivia	Natural gas transportation and services
GasOcidente do Mato Grosso Ltda. (“GOM”)(d)(l)	100.00	Consolidated	Brazil	Natural gas transportation and services
GasOriente Boliviano Ltda. (“GOB”)(d)(l)	100.00	Consolidated	Bolivia	Natural gas transportation and services
Generadora San Felipe Limited Partnership (“Generadora San Felipe”)(b)(i)	100.00	Consolidated	Dominican Republic	Power generation
Jaguar Energy Guatemala LLC (“Jaguar”)(a)	100.00	Consolidated	Guatemala	Power generation
Jamaica Private Power Company (“JPPC”)(b)	84.42	Consolidated	Jamaica	Power generation
Luoyang Yuneng Sunshine Cogeneration Company Limited (“Luoyang”)(a)	50.00	Consolidated	China	Power generation
Operadora San Felipe Limited Partnership (“Operadora San Felipe”)(b)(i)	100.00	Consolidated	Dominican Republic	Power generation
Peruvian Opportunity CompanySAC (“POC”)(b)(j)	50.00	Equity Method	Peru	Power distribution
Promigas S.A. E.S.P. (“Promigas”)	52.13	Consolidated	Colombia	Natural gas transportation and services and Natural gas distribution

F-7


	Ownership		Location of
Company Name	Interest (%)	Accounting Method	Operations	Segment
Puerto Quetzal Power LLC (“PQP”)(b)	100.00	Consolidated	Guatemala	Power generation
ProEnergía Internacional S.A. (“Proenergía”)(a)(k)	52.13	Consolidated	Colombia	Retail Fuel
Transportadora de Gas del Sur S.A. (“TGS”)(d)	7.96	Cost Method	Argentina	Natural gas transportation and services
Tipitapa Power Company Ltd (“Tipitapa”)(a)(e)	57.67	Consolidated	Nicaragua	Power generation
Tongda Energy Private Limited (“Tongda”)(b)	100.00	Consolidated	China	Natural gas distribution
Trakya Elektrik Uretim ve Ticaret A.S. (“Trakya”)(d)	90.00	Consolidated	Turkey	Power generation
Transborder Gas Services Ltd. (“TBS”)(d)(l)	100.00	Consolidated	Brazil, Bolivia	Natural gas transportation and services
Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. TBG (“TBG”)(d)(m)	8.27	Cost Method	Brazil	Natural gas transportation and services
Transredes-Trasporte de Hidrocarburos S.A. (“Transredes”)(h)	1.28	Cost Method	Bolivia	Natural gas transportation and services


(a)		The Company’s initial or additional interest was acquired during 2008 (see Note 3).

(b)		The Company’s initial or additional interest was acquired during 2007 (see Note 3) .

(c)		The Company holds a 50% interest in a related service company of Chilquinta, Tecnored S.A. (“Tecnored”).

(d)		The Company’s initial or additional interest was acquired during 2009 (see Note 3).

(e)		During the first quarter of 2009, as part of the Nicaragua Energy Holdings (“NEH”) transaction, AEI’s ownership in Corinto increased from 50% to 57.67% and AEI’s ownership in Tipitapa decreased from 100% to 57.67% (see Note 3). In addition, AEI currently owns, through its 57.67% interest in NEH, a 13.42% equity interest in Amayo.

(f)		In June 2009, the Company increased its ownership interest in Emgasud S.A. from 31.89% to 37%. In October and December of 2009, the Company further increased its ownership to 42.73% (see Note 3).

(g)		In May 2009, the Company made an initial investment in EMDERSA consisting of cash and stock for a 19.91% ownership. In August, September and October of 2009, the Company acquired additional ownership interests of EMDERSA totaling 57.2%, which increased its ownership interest to 77.10%. The Company began to consolidate EMDERSA on September 24, 2009 (see Note 3).

(h)		In May 2008, the Company’s ownership in Transredes, held through a 50% ownership in the holding company TR Holdings Ltda. (“TR Holdings”), decreased from 25% to 0% and the Company maintains a 1.28% direct ownership interest in Transredes, which is accounted for using the cost method (see Note 3).

(i)		The Company comprises an integrated part of the operation referred to collectively as “San Felipe”.

(j)		POC holds the interest in the operations referred to as “Luz del Sur”.

(k)		In July 2009, Promigas completed the spin-off of Proenergía to the shareholders of Promigas with the same ownership structure and percentage that existed prior to the spin-off, and the Company obtained a 52.13% ownership in Proenergía. Through Proenergía, the Company owns 27.45% of SIE (Sociedad de Inversiones en Energía), our retail fuel operations.

(l)		The four companies EPE, GOM, GOB and TBS comprise the integrated project “Cuiabá”. In December 2009, the Company acquired the 50% interests of these companies that it previously did not own. As a result, we currently own 100% of each of EPE, GOM, GOB and TBS (see Note 3).

(m)		In May 2008, the Company’s indirect ownership in GTB through Transredes decreased from 12.75% to 0%. The Company’s direct and indirect ownership in GTB was 17.65% from May 2008 through December 2009. In December 2009, the Company acquired an additional 17% of GTB and 4% of TBG. As a result, we currently own 34.65% of GTB and 8.27% of TBG (see Note 3).

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation — The consolidated financial statements include the accounts of all wholly-owned companies, majority-owned subsidiaries and controlled affiliates. Investments in entities where the Company holds an ownership interest of at least 20%, and which it neither controls nor is the primary beneficiary but in which it exercises significant influence, are accounted for under the equity method of accounting. Other investments in which the Company owns less than a 20% interest, unless the Company can clearly exercise significant influence over operating and financing policies, are recorded at cost. The consolidated financial statements are presented in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).

Acquisition Accounting — Assets acquired and liabilities assumed in business combinations are recorded on the Company’s consolidated balance sheet in accordance with the purchase method of accounting which requires that the cost of the acquisition be allocated to assets acquired and liabilities assumed based on their estimated fair value at the date of acquisition. The Company consolidates assets and liabilities from acquisitions as of the purchase date and includes earnings from acquisitions in the consolidated statement of operations from the purchase date. Accordingly, the information included in the accompanying consolidated financial statements reflects the fair value of certain of those assets and liabilities on a preliminary basis.

F-8

Discontinued Operations — As a result of the sale of our interests in Vengas S.A., or Vengas, in November 2007 (see Note 3) the Company reported discontinued operations for the year ended December 31, 2007. The presentation of the results of operations through the date of sale are reported in income from discontinued operations, net of tax in the consolidated statements of operations.

Cash and Cash Equivalents — Cash and cash equivalents consist of all highly liquid investments that are readily convertible to cash and have a maturity of three months or less at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.

Restricted Cash — Restricted cash includes cash and cash equivalents that are restricted as to withdrawal or usage. Restrictions primarily consist of restrictions imposed by the financing agreements, such as security deposits kept as collateral, debt service reserves, maintenance reserves, and restrictions imposed by long-term power purchase agreements (“PPAs”) or other contracts. Restrictions on cash and cash equivalents extending for a period greater than one year have been classified as non-current in other assets. Changes in restricted cash in the consolidated statements of cash flows are presented on a gross basis in “cash flows from investing activities”. The company has revised the prior years presentation of changes in restricted cash to present all years on a gross basis, as previous amounts were shown net.

Allowance for Doubtful Accounts — A provision for losses on accounts, notes and lease receivables is established based on management’s estimates of amounts that it believes are unlikely to be collected. The Company estimates the allowance based on aging of specific accounts, economic trends and conditions affecting its customers, significant events, and historical experience.

Inventories — Inventories are stated at the lower of cost or net realizable value. Materials and spare parts inventory is primarily determined using the weighted average cost method. Fuel inventory is determined using either the weighted average cost or the first-in, first-out methods.

Regulatory Assets and Liabilities — As the Company has certain operations (Elektro, Elektra and certain subsidiaries of Promigas) that are subject to the provisions of Accounting Standards Codification (“ASC”) 980, “Regulated Operations”, assets and liabilities that result from the regulated rate making process are recorded that would not be recorded under U.S. GAAP for non-regulated entities. The Company capitalizes incurred allowable costs as regulatory assets if it is probable that future revenue, at least equal to the costs incurred, will be billed and collected through approved rates. If future recovery of costs is not considered probable, the incurred cost is recognized as an expense. Regulatory liabilities are recorded for amounts expected to be passed to the customer as refunds or reductions on future billings.

Property, Plant, and Equipment — Property, plant, and equipment are recorded at cost. Interest costs on borrowings incurred during the construction or upgrade of qualifying assets are capitalized and are included in the cost of the underlying asset. Expenditures for significant additions and improvements that extend the useful life of the assets are capitalized. Expenditures for maintenance costs and repairs are charged to expense as incurred.

Depreciation is expensed over the estimated useful lives of the related assets using the straight-line method. The ranges of estimated useful lives for significant categories of property, plant, and equipment are as follows:


Machinery and equipment		10-50 years
Pipelines		25-50 years
Power generation equipment		18-40 years
Buildings		20-50 years
Vehicles		4-12 years
Furniture and fixtures		5-10 years
Other		3-20 years

Upon retirement or sale, the Company removes the cost of the asset and the related accumulated depreciation from the accounts and reflects any resulting gain or loss in the consolidated statement of operations.

Long-Lived Asset Impairment — The Company evaluates long-lived assets, including amortizable intangibles and investments in unconsolidated affiliates, for impairment when circumstances indicate that the carrying amount of such assets may not be recoverable. These circumstances may include regulatory or political actions, changes in litigation, the relative pricing of electricity, anticipated demand, and cost and availability of fuel. When it is probable that the undiscounted cash flows will not be sufficient to recover the carrying amounts of those assets, the asset is written down to its estimated fair value based on market values, appraisals or discounted cash flows. Indefinite-lived intangibles are tested at least annually for impairment.

F-9

Investments in Unconsolidated Affiliates — Dividends received from those companies that the Company accounts for at cost are included in other income (expense), net. Dividends received in excess of the Company’s proportionate share of accumulated earnings on equity investments are applied as a reduction of the cost of the investments and as investing cash flows in the consolidated statement of cash flows. When it is probable that the discounted cash flows will not be sufficient to recover the carrying amounts of investments in unconsolidated affiliates, the investment is written down to its estimated fair value based on market values, appraisals or discounted cash flows.

Marketable Securities — Investment in debt securities consist of debt securities classified as available-for-sale, which are stated at estimated fair value. Unrealized gains and losses, net of tax, are reported as a separate component of accumulated other comprehensive income (loss) in shareholders’ equity until realized. At each period end, in order to evaluate the impairment for securities whose market value is less than its costs, the Company applies a systematic methodology which considers the severity and duration of any impairment as well as any qualitative factors that may indicate the likelihood that such impairment is other-than-temporary. Held-to-maturity securities are those investments that the Company has the ability and intent to hold until maturity. Held-to-maturity securities are recorded at cost, adjusted for the amortization of premiums and discounts, which approximates market value.

Goodwill — Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The amount of goodwill results from significant strategic and financial benefit to the Company including: a) the establishment of business platforms in emerging markets, b) broadened distribution networks, c) improved operational efficiencies for distribution businesses, d) achieving economies of scale through utilization of common back office resources and e) utilization of the Company’s operational strengths and the combination of regional financial, operational and accounting expertise to realize cost savings. Goodwill is not subject to amortization, but is tested at least annually as of August 31 for impairment, or at other dates if circumstances arise that would more likely than not reduce the fair value of a reporting unit below its carrying value.

Intangible Assets — The Company’s intangible assets, excluding goodwill, are primarily made up of acquired PPAs, concession and land use rights, continuing customer relationships and trademarks. As PPAs have a definite lives, the intangible assets are amortized based on the unit method over the term of the agreement. Intangible assets associated with acquired PPAs represent the present value at the date of acquisition of the total estimated net earnings to be realized over the life of the PPAs. Amounts amortized each year are representative of the discounted projected net earnings for the respective year. The weighted-average remaining life of all PPAs is 7 years. Customer relationships, trademarks and amortizable concession and land use rights are amortized over the life of the contracts.

Asset Retirement Obligations — The Company records liabilities for the fair value of the retirement and removal costs of long-lived assets in the period in which it is incurred, adjusted for the passage of time and revisions to previous estimates, if the fair value of the liability can be reasonably estimated. The Company’s asset retirement obligations were not material at either December 31, 2009 or 2008.

Deferred Financing Costs — Financing costs are deferred and amortized over the financing period using the effective interest rate method.

Revenue Recognition — The Company’s consolidated revenues are attributable to sales and other revenues associated with the transmission and distribution of power and natural gas; sales from the generation of power; and the wholesale and retail sale of gasoline and compressed natural gas (“CNG”). Power distribution sales to final customers are recognized when power is provided. Revenues that have been earned but not yet billed are accrued based upon the estimated amount of energy delivered during the unbilled period at the approved or contractual billing rates for each category of customer. Unbilled revenues were $206 million and $130 million as of December 31, 2009 and 2008, respectively. Revenues received from other power distribution companies for use of the Company’s basic transmission and distribution network are recognized in the month that the network services are provided. Revenues from the sale of power are usually recognized in the period in which the sale occurs. The Company determined, however, that certain PPAs should be considered leases and recognizes these revenues ratably over the term of the PPA based on a levelized rate of return considering the terms of the agreement. Gas transmission and distribution revenues are usually recognized in the period the service is provided. Revenues from sales of gasoline and CNG are recognized when gases are delivered. Taxes collected from customers and remitted to governmental authorities are excluded from revenues.

F-10

Deferred Revenue — Revenues from certain power generation contracts with decreasing scheduled rates are recognized based on the lesser of (1) the amount billable under the contract or (2) an amount determined by the kilowatt-hours made available during the period multiplied by the estimated average revenue per kilowatt-hour over the term of the contract. The cumulative difference between the amount billed and the amount recognized as revenue is reflected as deferred revenue on the consolidated balance sheet.

Natural gas distribution network connection fees related to gas sales agreements are received from new customers in advance and are recognized over the shorter of the estimated life of the customer relationship or the life of the concession agreement, as applicable. The cumulative difference between the up-front connection fees received and the amount recognized in revenue is reflected as deferred revenue on the consolidated balance sheet.

Earnings Per Share — Basic earnings per share are calculated by dividing net earnings available to common shares by average common shares outstanding during the period. Diluted earnings per share is calculated similarly, except that it includes the effect of potentially dilutive securities, including the effect of outstanding options and securities issuable under the Company’s stock-based incentive plans and the conversion of payment in kind (“PIK”) notes. Potentially dilutive securities are excluded from calculating diluted earnings per share if their inclusion is anti-dilutive.

Income Taxes — Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. 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.

Derivatives — The Company may enter into various derivative transactions in order to hedge its exposure to commodity, foreign currency, and interest rate risk. The Company reflects all derivatives as either assets or liabilities on the consolidated balance sheet at their fair value. All changes in the fair value of the derivatives are recognized in income unless specific hedge criteria are met. Changes in the fair value of derivatives that are highly effective and qualify as cash flow hedges are reflected in accumulated other comprehensive income (loss) and recognized in income when the hedged transaction occurs or no longer is probable of occurring. Changes in the fair value of hedges of a net investment in a foreign operation are reflected as cumulative translation adjustments in accumulated other comprehensive income (loss).

The Company’s policy is to formally document all relationships between hedging instruments and hedged items, as well as the Company’s risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on a quarterly basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Any unrealized gain or loss attributable to hedge ineffectiveness is reclassified to earnings in the current period. Hedge accounting is discontinued prospectively when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in accumulated other comprehensive income (loss) related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.

Pension Benefits — Employees in the United States and in some of the foreign locations are covered by various retirement plans provided by AEI or the respective Operating Companies. The types of plans include defined contribution and savings plans, and defined benefit plans. Expenses attributable to the defined contribution and savings plans are recognized as incurred. Expenses related to the defined benefit plans are determined based on a number of factors, including benefits earned, salaries, actuarial assumptions, the passage of time, and expected returns on plan assets. In certain countries, including Brazil, Turkey, Panama, El Salvador and Colombia, local labor laws require the Operating Companies to pay severance indemnities to employees when their employment is terminated. In Argentina, the Operating Companies are required to pay certain benefits to employees upon retirement. The Company accrues these benefits based on historical experience and valuations performed by third parties or the Company.

F-11

Stock-Based Compensation — The Company has a long-term equity incentive compensation plan. The fair value of awards granted under the Company’s long-term equity incentive compensation plan is determined as of the date of the share grant, and compensation expense is recognized over the required vesting period.

Environmental Matters — The Company is subject to a broad range of environmental, health, and safety laws and regulations. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law. Established accruals are adjusted periodically due to new assessments and remediation efforts, or as additional technical and legal information become available.

Foreign Currency — The Company translates the financial statements of its international subsidiaries from their respective functional currencies into the U.S. dollar. An entity’s functional currency is the currency of the primary economic environment in which it operates and is generally the currency in which the business generates and expends cash. Subsidiaries whose functional currency is other than the U.S. dollar translate their assets and liabilities into U.S. dollars at the exchange rates in effect as of the balance sheet date. The revenues and expenses of such subsidiaries are translated into U.S. dollars at the average exchange rates for the year. Translation adjustments are included in accumulated other comprehensive income (loss), a separate component of shareholders’ equity. Foreign exchange gains and losses included in net income result from foreign exchange fluctuations on transactions denominated in a currency other than the subsidiary’s functional currency.

The Company has determined that the functional currency for some subsidiaries is the U.S. dollar due to their operating, financing, and other contractual arrangements. The Operating Companies that are considered to have their local currency as the functional currency are EDEN and EMDERSA in Argentina; BMG, Tongda and Luoyang in China; Elektro in Brazil; DCL in Pakistan; ENS in Poland; Chilquinta in Chile; Luz del Sur in Peru; certain operating subsidiaries and affiliates of Proenergía in Colombia and Chile; and certain operating companies of Promigas in Colombia.

Intercompany notes between subsidiaries that have different functional currencies result in the recognition of foreign currency exchange gains and losses unless the Company does not plan to settle or is unable to anticipate settlement in the foreseeable future. All intercompany balances eliminate upon consolidation.

Revision to Cash Flows — Subsequent to the issuance of the Company’s 2008 and 2007 consolidated financial statements, the Company’s management determined that short-term borrowings in the consolidated statements of cash flows should have been presented on a gross rather than on a net basis. In the “cash flows from financing activities” section of the consolidated statements of cash flows for the years ended December 31, 2008 and 2007, the Company presented gross borrowings in issuance and repayment of debt borrowings. The correction to present changes in short-term borrowings on a gross basis was not material to the Company’s consolidated financial statements and had no impact on previously reported net income, changes in shareholders’ equity, financial position or net cash flows from financing activities.

Use of Estimates — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting periods. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to unbilled revenues, useful lives and carrying values of long-lived assets, assumptions used to test goodwill, intangible assets and equity and cost method investments for impairment, collectability and valuation allowances for receivables, primary beneficiary determination for the Company’s investments in variable interest entities, determination of functional currency, allocation of purchase price, the recoverability of deferred regulatory assets, the outcome of pending litigation, the resolution of uncertainties, provision for income taxes, and fair value calculations of derivative instruments.

F-12

Accounting Standards Adopted in 2009

In June 2009, the Financial Accounting Standards Board (“FASB”) issued ASC 105, “Generally Accepted Accounting Principles”. ASC 105 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with U.S. GAAP. ASC 105 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company adopted this Statement for the interim period ending September 30, 2009 and incorporated the new codification in its consolidated financial statements. While the adoption of ASC 105 did not have an impact on AEI’s consolidated financial statements, ASC 105 changed the reference to authoritative and non-authoritative accounting literature within the notes to the consolidated financial statements.

In September 2006, the FASB issued ASC 820, “Fair Value Measurements and Disclosures”. ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Certain requirements of ASC 820 became effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of ASC 820 was deferred until fiscal years beginning after November 15, 2008. The Company adopted the sections of ASC 820 which are effective for fiscal years beginning after November 15, 2007 in 2008 and there was no impact on the Company’s consolidated statements of operations. The Company adopted the remaining requirements of ASC 820 on January 1, 2009.

In December 2007, the FASB issued ASC 805, “Business Combinations”, which must be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. ASC 805 establishes principles and requirements on how an acquirer recognizes and measures in its financial statements identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree, goodwill or gain from a bargain purchase and accounting for transaction costs. Additionally, ASC 805 determines what information must be disclosed to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The Company adopted ASC 805 on January 1, 2009 and is applying the provisions to business combinations entered into subsequent to that date.

In December 2007, the FASB issued an update on ASC 810, “Consolidations” (ASC 810-10-65-1), which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This update is effective for fiscal years beginning after December 15, 2008. The Company adopted this update on January 1, 2009 and has incorporated the changes in its financial statement presentation for all periods presented.

In November 2008, the FASB issued an update on ASC 323, “Investments—Equity Method and Joint Ventures”, which establishes that the accounting application of the equity method is affected by the accounting for business combinations and the accounting for consolidated subsidiaries, which were affected by the issuance of ASC 805 and ASC 810. ASC 323 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years, consistent with the effective dates of ASC 805 and ASC 810-10-65-1. The Company adopted ASC 323 on January 1, 2009 and is applying the provisions to acquisitions of equity method investments.

Although past transactions would have been accounted for differently under ASC 805 and ASC 323, application of these statements in 2009 did not affect historical amounts.

In March 2008, the FASB issued an update on ASC 815, “Derivatives and Hedging” (ASC 815-10-65-1), which requires enhanced disclosures about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. This update is effective for financial statements issued for fiscal years beginning after November 15, 2008. The Company adopted this update on January 1, 2009 and has incorporated the disclosure changes in its financial statements.

In December 2008, the FASB issued an update on ASC 715, “Compensation — Retirement Benefits” (ASC 715-20-65-2), which requires enhanced disclosures on plan assets of defined benefit pension plan and other postretirement plans. This update is effective for fiscal years ending after December 15, 2009. Upon initial application, the provisions of this update are not required for earlier periods that are presented for comparative purposes. The Company has incorporated the additional disclosure requirements in its financial statements for the year ended December 31, 2009.

F-13

In April 2009, the FASB issued an update on ASC 825, “Financial Instruments”, which requires disclosures about fair value of financial instruments in interim reporting periods that were previously only required to be disclosed in annual financial statements. This update (ASC 825-10-65-1) is effective for interim and annual periods ending after June 15, 2009. The Company incorporated the additional disclosure requirements in its financial statements for the quarter ended June 30, 2009.

In April 2009, the FASB issued an update on ASC 820, “Fair Value Measurements and Disclosures” (ASC 820-10-65-4), which provides additional guidance on estimating fair value in accordance with ASC 820 when the volume and level of activity for an asset or liability have significantly decreased in relation to normal market activity for the asset or liability. This update also provides guidance on identifying circumstances that indicate a transaction is not orderly. This update is effective for interim and annual periods ending after June 15, 2009. The Company adopted this update for the quarter ended June 30, 2009 and is applying the guidance to fair value measurements and disclosures.

In April 2009, the FASB issued an update on ASC 320, “Investments—Debt and Equity Securities”. This update (ASC 320-10-65-1) provides other-than-temporary impairment guidance for debt securities to make it more operational and to improve the presentation and disclosure of other-than-temporary impairments in debt and equity securities in the financial statements. This update does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. This update is effective for interim and annual periods ending after June 15, 2009. The Company adopted this update for the quarter ended June 30, 2009 and is applying the guidance to the investments in debt and equity securities.

In May 2009, the FASB issued ASC 855, “Subsequent Events”. ASC 855 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions of ASC 855 are effective for interim and annual periods ending after June 15, 2009. The Company adopted ASC 855 as of June 30, 2009.

In August 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-05, “Measuring Liabilities at Fair Value”, on ASC 820-10, “Fair Value Measurements and Disclosures”. This update provides clarifications on how to measure the fair value of liabilities, which reduces potential ambiguity in financial reporting when measuring the fair value of liabilities and improves consistency in the application of fair value measurement. This update is effective for the first reporting period (including interim periods) beginning after issuance. The Company adopted this update in the fourth quarter of 2009 and is applying the guidance to fair value measurements and disclosures.

In January 2010, the FASB issued an update on ASC 810, “Consolidation”. This update (ASC 810-10) addresses implementation issues related to the changes in ownership provisions. It clarifies the scope of the decrease in ownership provisions, provides related implementation guidance and requires expanded disclosures about the deconsolidation of a subsidiary or deconsolidation of a group of assets within the scope of Subtopic 810-10. The provisions of this update are effective beginning in the first interim or annual reporting period ending on or after December 15, 2009. The Company adopted this update in the fourth quarter of 2009 and is applying this guidance and associated disclosure requirements for transactions with decreases in ownership.

Recent Accounting Standards — to be Adopted

In October 2009, the FASB issued ASU 2009-13, “Revenue Recognition — Multiple-Deliverable Revenue Arrangements”, on ASC 605, “Revenue Recognition”. This update addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services (deliverables) separately rather than as a combined unit. Subtopic 605-25, Revenue Recognition — Multiple-Element Arrangements, establishes the accounting and reporting guidance for arrangements under which the vendor will perform multiple revenue- generating activities. Specifically, this update addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. In addition, this update expands the disclosures related to a vendor’s multiple-deliverable revenue arrangements. This update will be effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. The Company will adopt this update as of January 1, 2011 and has not determined the impact, if any, on its consolidated financial statements.

F-14

In December 2009, the FASB issued a further update on ASC 810, “Consolidation”. This update (ASC 810-10) amends certain requirements associated with the consolidation of variable interest entities (“VIE”) to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This standard will increase the use of qualitative considerations in identifying which entity in the VIE has a controlling financial interest that enables them to direct the activities that most significantly impact the entity’s economic performance. The provisions of this update are effective for interim and annual reporting periods beginning November 15, 2009, or January 1, 2010 for AEI. Based on the initial evaluation performed by the Company in accordance with this update, the Company determined that there were no entities qualifying as VIEs.

In January 2010, the FASB issued ASU 2010-06 “Improving Disclosures About Fair Value Measurements” on ASC 820, “Fair Value Measurements and Disclosures”. This update adds new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. The provisions of this update are effective for the interim or annual reporting period beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward activity in level 3 fair value measurements. Those disclosures are effective for interim and annual reporting periods beginning after December 15, 2010. The Company will incorporate the additional disclosure requirements in its financial statements beginning with the quarter ended March 31, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward activity in level 3 fair value measurements, which will be incorporated in its financial statements beginning with the quarter ended March 31, 2011.

3. ACQUISITIONS AND DISPOSALS

Acquisitions

2009 Acquisitions

Nicaragua Energy Holdings — On January 1, 2009, AEI contributed its 50% interest in its subsidiary Corinto and its 100% interest in its subsidiary Tipitapa to Nicaragua Energy Holdings (“NEH”). Centrans Energy Services Inc. (“Centrans”) also contributed its 50% interest in Corinto and 49% of its 45% interest in Consorcio Eólico Amayo, S.A. (“Amayo”) to NEH. In November 2009, NEH acquired an additional 1.2% indirect interest in Amayo. Amayo is a 40 megawatt (“MW”) wind generation greenfield development project located in Rivas Province, Nicaragua. As a result, AEI owns 57.67% and Centrans owns 42.33% of NEH. Centrans was given a call option that may be exercised at any time prior to December 8, 2013 to increase its interest in NEH up to 50.00%. The Company accounted for the exchange of ownership interests in Corinto and Tipitapa as an equity transaction and the interests were contributed to NEH at the carrying value. AEI consolidated NEH, which consolidates Corinto and Tipitapa and accounts for Amayo under the equity method, from January 1, 2009.

EMDERSA — On May 29, 2009, AEI acquired from a third party a 19.91% interest in EMDERSA, an Argentine holding company that controls or owns an equity interest in three power distribution companies. AEI paid $29 million consisting of $7 million in cash and a contribution of 1,497,760 ordinary shares of AEI in exchange for the 19.91% ownership interest of EMDERSA. On August 27, 2009, AEI paid $7 million in cash to acquire an additional 4.5% ownership interest in EMDERSA. The Company accounted for EMDERSA as an equity method investment from May 29, 2009 to September 23, 2009. On September 24, 2009, AEI acquired an additional 25.61% ownership interest in EMDERSA for $41 million consisting of $21 million in cash and $20 million in promissory notes. Pursuant to the terms of the notes, $14 million in promissory notes were later exchanged for 903,253 ordinary shares of AEI and the remaining $6 million in promissory notes were repaid in cash in December 2009. Together these transactions increased AEI’s ownership interest in EMDERSA from 19.91% to 50.02%. The Company began to consolidate EMDERSA from September 24, 2009. On October 13, 2009, AEI acquired an additional 27.08% ownership interest in EMDERSA for $43 million, consisting of $37 million in cash and a $6 million promissory note, which was later exchanged, pursuant to the terms of the note, for 407,641 ordinary shares of AEI. This transaction increased AEI’s ownership interest in EMDERSA to 77.10%. The Company recorded a total of $3 million of goodwill and $78 million of intangibles, primarily concession rights, as a result of the acquisitions of ownership interests in EMDERSA. The Company is in the process of finalizing its purchase price allocation with regard to its tax basis balance sheet. In connection with these acquisitions, the Company was required under Argentine law to make a tender offer for the remaining outstanding shares of EMDERSA and has initiated this process. The Company expects this tender offer to close in the second half of 2010, subject to receipt of local regulatory and antitrust approvals.

F-15

Emgasud — AEI initially acquired a 28% interest in Emgasud on November 28, 2008 for $38 million. This transaction was effected through a capital contribution of $15 million to Emgasud and the acquisition of certain noncontrolling shareholder equity positions in exchange for 1,699,643 AEI ordinary shares. On December 23, 2008, AEI made a second capital contribution to Emgasud of $10 million in cash and increased its equity in Emgasud to 31.89%. On June 17, 2009, AEI paid $15 million in cash to acquire additional shares of Emgasud, which increased AEI’s ownership interest in Emgasud from 31.89% to 37%. In August 2009, the Company purchased a $15 million senior unsecured convertible note due in July 2012 from Emgasud. The note accrues interest at an interest rate of 19%. The proceeds of this note were used primarily to complete the development of the Energía Distribuida power generation project and related investments and for working capital and other operating expenses. Emgasud has not made an interest payment on this intercompany note due to liquidity issues. Should such liquidity issues continue, there could be a material adverse effect on the operations of Emgasud with a corresponding negative impact to the Company. In October and December 2009, the Company acquired through two transactions an additional 5.73% of ownership interests in Emgasud for a total of $20 million in cash which increased AEI’s ownership interest in Emgasud to 42.73%. The agreement with Emgasud provides for the acquisition by AEI or its affiliates of a total interest in Emgasud of up to 61.41%. The primary business of Emgasud is the ownership, operation and development of several gas power generation plants.

Trakya — On August 27, 2009, AEI paid cash to acquire an additional 31% ownership interest in Trakya, which increased AEI’s ownership interest in Trakya from 59% to 90%. As the Company already controlled and consolidated Trakya prior to its additional investment, it accounted for the ownership increase as an equity transaction and the interests were contributed to Trakya at their carrying value.

TGS — On September 25, 2009, AEI acquired from a third party 12,160,608 American Depository Receipts (“ADRs”) (equivalent to 60,803,040 Class B shares) representing a 7.65% ownership interest of Transportadora de Gas del Sur S.A. (“TGS”), an Argentine natural gas transportation company, in exchange for 1,976,099 ordinary shares of AEI. The Company currently owns 7.96% of TGS and accounts for this investment under the cost method. The Company also holds matured debt securities of an Argentine holding company, Compañía de Inversiones de Energía S.A. (“CIESA”), which holds controlling interests in TGS (see Notes 13 and 19).

GTB, TBG and Cuiabá — On December 18, 2009, AEI paid cash of $100 million to acquire the 50% interest in each of the Cuiabá entities that it did not previously own, an additional 4% interest in TBG, an additional 17% interest in GTB and associated Cuiabá shareholders’ loans with principal and interest totaling $130 million from a third party. Additionally, we acquired notes receivable from GTB and TGB from the same third party. As a result, the Company currently owns 100% of each of the Cuiabá entities, 8.27% of TBG and 34.65% of GTB. As the Company had previously consolidated the Cuiaba entities, the Company accounted for the acquisitions of the additional ownership interests in each the Cuiabá entities and its acquisition of shareholders’ loans as equity transactions. The Company continues to account for the investment in TBG as a cost method investment and GTB began to be accounted for under the equity method as of December 18, 2009.

2008 Acquisitions

SIE — On January 2, 2008, Promigas contributed its ownership interests in its wholly owned subsidiary, Gas Natural Comprimido (“Gazel”), to SIE in exchange for additional shares of SIE. As a result of the transaction, Promigas’ ownership in SIE increased from 37.19% as of December 31, 2007 to 54% with SIE owning 100% of Gazel. The transaction was accounted for as a simultaneous common control merger in accordance with EITF 90-13, Accounting for Simultaneous Common Control Mergers. A gain of $68 million, net of tax of $0 million, net income of noncontrolling interest of $55 million, and incremental goodwill in the amount of $188 million were recorded on this transaction. SIE’s balances and results of operations have been consolidated with those of the Company prospectively from January 2, 2008.

F-16

A summary of the fair values of assets acquired and liabilities assumed as of the date of acquisition is as follows:


	SIE
	Millions of dollars (U.S.)
Current assets	$	86
Property, plant, and equipment, net		51
Goodwill		188
Intangibles		78
Other noncurrent assets		11

Assets acquired		414

Current liabilities		87
Long-term debt		66
Other long-term liabilities		17

Liabilities assumed		170

Noncontrolling interests		114

Net assets acquired	$	130

The $78 million of acquired intangible assets has been allocated to continuing customer relationships, trademarks and land use rights. The continuing customer relationships and the land use rights are being amortized based on the benefits expected to be realized considering the related expected cash flows. Trademarks have an indefinite life and will not be amortized, but will be evaluated annually for any impairment. The weighted average amortization period is estimated as 26 years for continuing customer relationships and 11 years for land use rights.

Unaudited Pro Forma Results of Operations — The following table reflects the consolidated pro forma results of operations of the Company as if the SIE acquisition and all 2007 acquisitions and disposals had occurred as of January 1, 2007.


	For the Year Ended
	December 31, 2007
	Millions of dollars (U.S.)
Revenues	$	7,475
Cost of sales		5,676
Operations, maintenance, and general and administrative expenses		1,110
Operating income		821
Income before income taxes		462
Net income — noncontrolling interests		145
Income from continuing operations attributable to AEI		90
Basic earnings per share attributable to AEI	$	0.43

BMG — On January 30, 2008, the Company completed its acquisition of a 70% interest in BMG and its subsidiaries for $58 million in cash and recorded $5 million of goodwill as a result of this acquisition. A portion of the interest purchased was funded in December 2007 (a 10.23% interest accounted for under the cost method in 2007). As a result of the January 2008 transaction, BMG was consolidated from January 30, 2008 forward. BMG builds city gas pipelines and sells and distributes piped gas in the People’s Republic of China.

Luoyang — On February 5, 2008, the Company acquired for $14 million in cash a 48% interest in Luoyang located in the Henan Province, People’s Republic of China. Luoyang owns and operates a power plant consisting of two coal-fired circulating fluidized-bed boilers and two 135 MW steam turbines. As part of the transaction, the Company’s representation on Luoyang’s board of directors is four of the total seven members, which along with other rights, allows the Company to exercise control over Luoyang’s daily operations. On June 6, 2008, the Company acquired an additional 2% of Luoyang for $5 million in cash, increasing its total ownership to 50%. The Company recorded a total of $11 million of goodwill as a result of the acquisitions of ownership interests in Luoyang.

Jaguar — On May 5, 2008, a subsidiary of the Company was awarded a contract to supply 200 MW to local distribution companies as part of a competitive public bid process in Guatemala for which a subsidiary of the Company will build, own and operate a nominal 300 MW solid fuel-fired generating facility. A subsidiary of the Company also executed PPAs to sell capacity and energy for a 15 year term. The Company anticipates commencing construction in the first half of 2010 and commercial operations in 2013. The plant will be located 80 kilometers south of Guatemala City in the Department of Escuintla, Guatemala.

F-17

Tipitapa — The Company acquired 100% of Tipitapa on June 11, 2008 for $18 million in cash. The excess of $4 million of fair value of the net assets of Tipitapa over the purchase price was applied as a reduction to the fixed assets. Tipitapa, a power generation company with operations in Nicaragua, provides 51 MW of generation capacity and associated energy through a long-term PPA with two Nicaraguan distribution companies, both majority owned by a third party.

Fenix — On June 26, 2008, AEI acquired an 85% interest in Fenix Power Peru S.A. referred to as “Fenix”, a Peruvian company in the advanced stages of developing a nominal 530 MW combined-cycle (natural gas-fired) power generation facility in Chilca, Peru. The interest was acquired for $100 million in cash paid at the closing. AEI is obligated to pay, if certain conditions are met, an additional $20 million to the previous shareholders with $8 million due at the commencement of construction and the remainder at full commencement of commercial operations. Subject to securing financing and completion of other project milestones, the Company anticipates issuing notice to commence construction in the first half of 2010 and expects to complete construction in the second half of 2012.

DCL — On July 18, 2008, the Company acquired for $19 million in cash a 48.18% interest in DCL located in Karachi, Pakistan. DCL owns and operates a 94 MW combined-cycle gas power plant and a 3 million gallons per day water desalination facility. On April 17, 2008, the plant commenced commercial operations dispatching 80 MW of power. Due to continuing vibration levels since startup, the plant was shut down for repairs in September 2008. These repairs were completed and the plant returned to commercial operation in October 2009 but shortly after the commencement of operations, a surge caused by an imbalance in the Pakistani grid caused additional damage to the plant. Following additional repairs, the plant has been fully operational since February 2010. On July 30, 2008, the Company acquired an additional 4.81% ownership interest in DCL for $4 million in cash, increasing its total ownership to 52.99%. As part of the transactions, the Company is able to appoint five of the eight members on DCL’s board of directors, which allows the Company to exercise control over DCL’s daily operations. The Company recorded a total of $5 million of goodwill as a result of the acquisitions of ownership interests in DCL. Through December 31, 2008, the Company executed additional share subscription agreements for approximately $6 million in cash that have resulted in an increase in the Company’s ownership to 59.94%. In 2009, the Company increased its ownership to 60.23% through additional share subscriptions for less than $1 million in cash. In the fourth quarter of 2009, the Company recorded an impairment charge and write-down of the goodwill, see Note 4 and 25 for further information.

Promigas — During the year ended December 31, 2008, Promigas acquired additional ownership interests in consolidated subsidiaries for $36 million in cash and recorded $14 million of goodwill as a result of the purchases.

2007 Acquisitions

Generadora San Felipe and Operadora San Felipe — On February 22, 2007, the Company acquired an additional 15% interest in Generadora San Felipe and an additional 50% interest in Operadora San Felipe for $14 million in cash and recorded $5 million of goodwill as a result of the purchases. The plant is located on the Dominican Republic’s north coast in the city of Puerto Plata.

DelSur — On May 24, 2007, AEI acquired 100% of the equity of Electricidad de CentroAmerica S.A. de C.V., the parent of DelSur, for $181 million resulting in an indirect 86.4% equity ownership in Delsur and $53 million of incremental non-deductible goodwill. The purchase price was financed by $100 million of third party debt and $81 million of cash. Delsur is an electrical distribution company in El Salvador and serves the south-central region of the country.

EDEN — On June 26, 2007, AEI acquired 100% of AESEBA, S.A. (“AESEBA”) for $75 million with part of the acquisition price representing the conversion of AESEBA debt to equity plus $17 million in cash. AESEBA holds 90% of the equity of EDEN, the electrical distribution company in the northern Buenos Aires Province in Argentina. The closing of the transaction remains subject to obtaining the approval of the Argentine anti-trust authorities. In the event such approval is not obtained, the shares of AESEBA would be re-transferred to a trust (or, in the event such transfer was not permitted, to the seller) to be held pending their sale by AEI. All proceeds of any such sale would be paid directly to AEI.

F-18

Cálidda — On June 28, 2007, AEI and Promigas acquired 100% of the equity ownership of Cálidda for $56 million in cash. AEI and Promigas own Cálidda through a 60/40 equity ownership split. Cálidda is a Peruvian natural gas distribution company that owns the concession to operate in the Lima and Callao Provinces.

Tongda — On August 14, 2007, AEI acquired 100% of the equity of Tongda for $45 million in cash and recorded $9 million of non-deductible goodwill. Tongda is incorporated in Singapore and constructs urban gas pipelines, sells and distributes gas, and operates auto-filling stations in mainland China. As of December 31, 2009, Tongda held controlling interests in thirteen urban gas companies.

Corinto — In August and September 2007, AEI acquired 100% of Globeleq Holdings (Corinto) Limited, which held a 30% direct interest in Corinto, for $14 million in cash by exercising its right of first refusal under an existing agreement. Subsequently, AEI sold 50% of Globeleq Holdings (Corinto) Limited along with 15% (half of the interest acquired through the right of first refusal exercise) of the newly acquired indirect interest in Corinto for $7 million and began consolidating the accounts of Corinto based on the voting power controlled by AEI. Upon closing of the transactions, AEI increased its indirect ownership in Corinto from 35% to 50% and its representation on Corinto’s board of directors from two to four members out of the total seven members. (see Nicaragua Energy Holdings earlier in this note).

PQP — On September 14, 2007, AEI acquired additional equity interests in PQP resulting in AEI owning 100% of PQP. The total purchase price of $57 million was paid in cash and $28 million in non-deductible goodwill was recorded as a result of the purchase. Through its branch in Guatemala, PQP owns three barge-mounted, diesel-fired generation facilities located on the Pacific coast at Puerto Quetzal.

JPPC — On October 30, 2007, AEI purchased an indirect 84.4% interest in JPPC for $26 million in cash. JPPC owns a base-load diesel-fired generating facility located on the east side of Kingston, Jamaica. The acquisition cost was $11 million less than the fair value of JPPC net assets at the date of acquisition. The excess of fair value over cost was recorded as a reduction of property, plant and equipment.

Chilquinta and POC — On December 14, 2007, AEI completed the acquisition of a 50% indirect interest in Chilquinta and a 50% indirect interest in POC, which holds the interests in the operations referred to as “Luz del Sur”, from a common owner for $685 million in cash. The acquisition included, among other associated companies, service companies, including Tecnored, that provide management of technical projects and services, construction work, maintenance and other services to the utilities. AEI accounts for these investments under the equity method.

Dispositions

Transredes — On May 1, 2008, the Bolivian government issued Supreme decree No. 29541 (“Expropriation Decree”) pursuant to which it stated that the state-run oil and gas company, Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), would acquire 263,429 shares of Transredes from TR Holdings at a price of $48 per share. On June 2, 2008, the Bolivian government issued Supreme Decree No. 29586 pursuant to which it stated that it would nationalize 100% of the shares held by TR Holdings in Transredes at the price per share set forth in the May 1, 2008 Supreme Decree, subject to deductions for categories of contingencies specified in the decree. In October 2008, the Company reached a settlement with YPFB, recognized by the Bolivian government, pursuant to which YPFB agreed to pay to the Company $120 million in two equal installments of $60 million. The payments were received in October 2008 and March 2009, respectively. The Company accounted for its investment in Transredes under the equity method and recognized a gain of $57 million for the year ended 2008. The gain is presented in the (Gain) loss on disposition of assets line of the consolidated statement of operations.

BLM — On March 14, 2007, the Company sold its indirect interest, which included the Company’s interest in all outstanding legal claims, in BLM. The Company recognized a gain of $21 million in the first quarter of 2007 as a result of the sale of BLM. Due to the continuing cash flows between BLM and the Company, the gain is presented in (gain) loss on disposition of assets and not as part of gain from disposal of discontinued operations in the consolidated statements of operations.

Discontinued Operations — Vengas — On November 15, 2007, the Company completed the sale, through a holding company, of 98.16% of Vengas (constituting its entire interest in Vengas) for $73 million in cash. The Company recorded a gain of $41 million in the fourth quarter of 2007 for which no taxes were recorded due to certain exemptions under the holding company’s tax status. Vengas was previously presented as part of the retail fuel segment.

F-19

Summarized financial information related to Vengas’ operations is as follows:


	For the Year Ended
	December 31, 2007
	Millions of dollars (U.S.)
Revenues	$	64
Income from discontinued operations before taxes		3
Provision for income tax		—
Income from discontinued operations		3
Gain on sale of discontinued operations		41

Unaudited Pro Forma Results of Operations

The following table reflects the consolidated pro forma results of operations of the Company as if the 2007 acquisitions and disposals described above had occurred as of January 1, 2007.


	For the Year Ended
	December 31, 2007
	Millions of dollars (U.S.)
Revenues	$	3,452
Cost of sales		1,946
Operations and maintenance expense		974
Operating income		664
Other expense		319
Income from continuing operations before income taxes		286
Income from continuing operations		85
Basic earnings per share	$	0.41

Pending Transactions

Luz del Sur — On September 8, 2009, the Company signed agreements with certain shareholders of Luz del Sur pursuant to which the Company agreed to acquire an additional 13.65% in Luz del Sur in exchange for 7,225,958 ordinary shares of AEI. The closing of this transaction is subject to certain conditions, including the listing of AEI shares on an approved exchange, including the NYSE. Under a shareholder agreement with our joint venture partner, the partner has the right to participate pro rata in this acquisition. Our partner has exercised this right. Therefore, the Company will only acquire an additional 6.83% of Luz del Sur if the transaction is completed.

Accroven — On September 11, 2009, the Company signed a non-binding Letter of Intent with Petróleos de Venezuela Gas, S.A. (PDVSA Gas), pursuant to which the Company agreed to transfer its interest in Accroven to PDVSA Gas. The term of this Letter of Intent has expired but negotiations continue and closing of this transaction is expected in the first half of 2010, subject to the negotiation of definitive documentation and the receipt of third party consents.

NBT Baicheng — On September 23, 2009, the Company signed an agreement to acquire a 49% ownership interest in NBT Baicheng New Energy Development Co., Ltd., (“NBT Baicheng”) a company that owns a 50 MW wind farm under construction in the Jilin Province of China, for a purchase price of approximately $15 million. The closing of this acquisition is subject to certain conditions, including NBT Baicheng having obtained certain local government permits and having reached certain milestones with respect to obtaining financing. Upon consummation of this transaction, expected in the second quarter of 2010, AEI will control the board, will appoint key management personnel and expects to consolidate NBT Baicheng.

4. OTHER CHARGES

DCL — In the fourth quarter of 2009, the Company recorded an impairment charge totaling $25 million, including a $5 million impairment of goodwill, related to its investment in DCL. The charge is reflected in the line item “Other charges” within the Operating expenses section of the consolidated statements of operations. The impairment charge to goodwill and the plant and the related fair values of the reporting unit and the plant were determined based on unobservable inputs (Level 3) using a discounted cash flow approach considering estimated future revenues and

F-20

expenses. The DCL plant entered commercial operations in April 2008 and has experienced a shut down due to a defect in the gas turbine that was not disclosed at the time the interest in DCL was acquired. Due to the shut down, DCL was unable to generate revenues and cash inflows to pay vendors which delayed the repairs. In June 2009, DCL entered into loan agreements to finance repairs to the plant. These repairs were completed and the plant returned to commercial operation in October 2009. However, a surge caused by an imbalance in the Pakistani power grid resulted in additional damage to the plant shortly following the restart of operations. The repairs have been completed and the plant resumed commercial operation in February 2010 (see Note 25).

SES — The Company has a 3.65% interest in SES, an energy and technology company that builds, owns and operates coal gasification plants in China and the U.S. Due to a severe decline in the publicly-traded equity value of SES in the fourth quarter of 2008, the Company recorded a $12 million impairment of its initial $16 million cost method investment in 2008. The Company recorded a further impairment of $2 million in the fourth quarter of 2009 marking the investment down to its current market value. There were no other circumstances requiring impairment analysis for other cost method investments.

Cuiabá — On October 1, 2007, EPE received a notice from Furnas Centrais Electricas. S.A. (‘Furnas”), purporting to terminate the existing PPA as a result of the lack of gas supply from Bolivia. EPE initiated an arbitration proceeding in Brazil on the basis that there was no contractual basis for Furnas to terminate the PPA. EPE determined that it was probable that it would be unable to collect all minimum lease payment amounts due according to the contractual terms of the lease. Accordingly, during the fourth quarter of 2007, the Company recorded a charge totaling $50 million against its lease investment receivable associated with the EPE PPA. At that time, an impairment analysis of the integrated Cuiaba project was performed and it was determined that there was no impairment.

In 2008, EPE amended its initial pleadings and requested the termination of the PPA based on Furnas’ failure to make capacity payments. The Company determined at that time that additional minimum lease payment amounts due according to the existing contractual terms may be uncollectible. Accordingly, in the third quarter of 2008, the Company recorded an additional charge totaling $44 million related to its then existing lease investment receivable at EPE. Lease accounting was subsequently terminated and the plant was recorded at fair value as of December 31, 2008. Subsequently, on October 20, 2009, the arbitrators confirmed that the PPA was terminated due to the occurrence of a force majeure event (see Note 25).

The arbitrator’s fourth quarter 2009 ruling that the PPA was legally terminated due to force majeure included a request that the Company submit its assessment of damages and losses. Additionally, the Company received an offer to purchase the noncontrolling interest in the integrated Cuiaba Project which was below the carrying value. As a result, the Company again performed an impairment test of the integrated Cuiaba project. In determining the fair value, the Company utilized unobservable inputs (Level 3) considering various discounted cash flows based on estimated future revenues and expenses and expected transaction values through the sale of the project. This test resulted in a charge of $96 million reducing the carrying value of Cuiaba to its estimated fair value.

The above charges of $96 million, $44 million, and $50 million for the years ended December 31, 2009, 2008 and 2007, respectively, are included in Other charges within the Operating expense section of the consolidated statement of operations.

5. (GAIN) LOSS ON DISPOSITION OF ASSETS

(Gain) loss on disposition of assets consists of the following:


	For the Years Ended December 31,
	2009		2008			2007
	Millions of dollars (U.S.)
Gain on exchange for additional shares of SIE (see Note 3)	$	—	$	(68	)	$	—
Gain on nationalization of Transredes (see Note 3)		—		(57	)		—
Loss on sale of operating equipment		20		18			10
Loss on sale of available-for-sale securities (see Note 13)		—		14			—
Gain on sale of BLM (see Note 3)		—		—			(21	)
Gain on sale of shares of Promigas		—		—			(10	)

	$	20	$	(93	)	$	(21	)

F-21

During 2008, $5 million of cumulative translation adjustments previously recorded in accumulated other comprehensive income (loss) was recognized in (Gain) loss on disposition of assets as a result of the nationalization of Transredes and the exchange for additional shares of SIE noted above.

In December 2007, a subsidiary of the Company sold 1,009,006 shares of Promigas reducing its ownership from 52.88% to 52.12%. The Company received $19 million in cash proceeds and recognized a $10 million gain.

6. OTHER INCOME (EXPENSE), NET

Other income (expense), net, consists of the following:


	For the Year Ended December 31,
	2009		2008			2007
	Millions of dollars (U.S.)
Dividend income	$	5	$	3		$	3
Gain (loss) on derivatives		—		(2	)		(13	)
Elektro — social contributions accrual reversal		49		—			—
Other		16		8			(12	)

	$	70	$	9		$	(22	)

Elektro — Elektro has three separate ongoing lawsuits against the Brazilian Federal Tax Authority in each of the Brazilian federal, superior and supreme courts relating to the calculation of the social contribution on revenue and the contribution to the social integration program. Elektro had previously accrued approximately $49 million and made a judicial deposit of approximately $24 million (based on the exchange rate as of December 31, 2009) related to this issue. In May 2009, a newly enacted Brazilian law revoked a previous law which resulted in a change to the method by which such contributions should be calculated. Due to the revocation and pursuant to a technical notice issued by IBRACON (the local Brazilian accounting standards board) in the second quarter of 2009, Elektro reversed the provision associated with the social contributions accruals made prior to 2004, which was previously recorded as Other income (expense), net. The impact of this reversal resulted in $49 million ($32 million net of tax) in income which is reflected as Other income (expense), net in the consolidated statements of operations. The $24 million judicial deposit made by Elektro remains as restricted cash and will not be released until the final decision by the Supreme Court on the appeal is made.

The Company recognized $(2) million and $1 million gain (loss) in 2008 and 2007, respectively, for the ineffective portion of interest rate swaps that qualified for hedge accounting treatment (see Note 19). The Company also recognized ($14) million loss related to foreign currency derivative transactions in 2007.

7. CASH AND CASH EQUIVALENTS

Cash and cash equivalents include the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Parent Company	$	7	$	284
Consolidated Holding and Service Companies		97		35
Consolidated Operating Companies		578		417

Total cash and cash equivalents	$	682	$	736

Cash remittances from the consolidated Holding Companies, Service Companies, and Operating Companies to the Parent Company are made through payment of dividends, capital reductions, advances against future dividends, or repayment of shareholder loans. The ability and timing for many of these companies to make cash remittances is subject to their operational and financial performance, compliance with their respective shareholder and financing agreements, and with governmental, regulatory, and statutory requirements.

Cash and cash equivalents held by the consolidated Holding Companies, Service Companies, and Operating Companies that are denominated in currencies other than the U.S. dollar are as follows (translated to U.S. dollars at period-end exchange rates):

F-22


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Brazilian real	$	193	$	111
Colombian peso		160		96
Chinese renminbi		37		15
Chilean peso		17		14
Argentine peso		13		7
Other		11		17

Total foreign currency cash and cash equivalents	$	431	$	260

Restricted cash consists of the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Current restricted cash:
Restricted due to long-term PPAs	$	51	$	—
Collateral and debt reserves for financing agreements (see Note 14)		20		63
Collateral for contracts		1		5
Other		5		15

Total current restricted cash		77		83

Noncurrent restricted cash (included in other assets, see Note 13):
Amounts in escrow accounts related to taxes		31		24
Collateral and debt reserves for financing agreements		3		8
Restricted due to long-term PPAs		18		5
Collateral for contracts		7		11
Other		5		1

Total noncurrent restricted cash		64		49

Total restricted cash	$	141	$	132

Current restricted cash “restricted due to long-term PPAs” relates primarily to amounts which EPE has received from Furnas as energy capacity payments. An arbitrators’ ruling in October 2008 permitted EPE to access a compensation account subject to the final ruling, at which time EPE may be required to refund any amounts received. EPE received the amounts in 2009 upon presenting the required guarantees, and has used approximately $19 million (based on the exchange rate as of December 31, 2009) in the fourth quarter of 2009 to fund existing operations and repay certain debt obligations to related parties. Repayment of the funds received and used, if required, has been guaranteed by subsidiaries of AEI.

In October 2009, a subsequent arbitrators’ ruling revoked EPE’s future access to the compensation account but deferred a decision as to whether amounts previously received must be repaid until a final ruling in the case (see Note 25).

8. INVENTORIES

Inventories consist of the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Materials and spare parts	$	87	$	141
Fuel		186		98

Total inventories	$	273	$	239

F-23

9. PREPAIDS AND OTHER CURRENT ASSETS

Prepaids and other current assets consist of the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Prepayments	$	35	$	29
Regulatory assets		97		25
Deferred income taxes		47		71
Receivable from YPFB (see Note 3)		—		60
Taxes other than income		36		36
Government subsidy — Delsur		15		20
Net investments in direct financing leases (see Notes 3 and 13)		—		10
Current marketable securities		23		7
Other		148		126

Total	$	401	$	384

In October 2008, the Company reached a settlement with Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), the Bolivian state-owned energy company, related to its investment in Transredes pursuant to which YPFB agreed to pay the Company $120 million in two installments. The first payment of $60 million was received in October 2008 and the second payment of $60 million was received in March 2009.

As a result of additional analysis of contracts as part of the purchase price allocation for DCL, the PPA was determined to be an operating lease versus a financing lease. Accordingly, the lease receivable balance was reclassified to property, plant and equipment during the first quarter of 2009. Subsequently, in the second quarter, the PPA was terminated (see Note 25).

10. PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant, and equipment, net consist of the following:


	December 31,
	2009			2008
	Millions of dollars (U.S.)

Machinery and equipment	$	2,562		$	1,888
Pipelines		785			777
Power generation equipment		899			862
Land and buildings		487			378
Vehicles		46			29
Furniture and fixtures		37			31
Other		86			106
Construction-in-process		304			209

Total		5,206			4,280
Less accumulated depreciation and amortization		(1,006	)		(756	)

Total property, plant and equipment, net	$	4,200		$	3,524

Elektro has property, plant, and equipment that, at the end of its 30-year renewable Concession Agreement in 2028, if not renewed, reverts back to the Brazilian federal government. Elektro may seek an extension of the Concession Agreement for an equal term of 30 years by submitting a written request to the Brazilian regulator accompanied by proof of compliance with various fiscal and social obligations required by law. The property, plant, and equipment, net, subject to the Concession Agreement provision was $1.44 billion and $1.08 billion at December 31, 2009 and 2008, respectively.

Trakya has property, plant, and equipment under an operating lease with the Turkish Ministry of Energy and National Resources (“Ministry”), that, at the end of the initial term of its Energy Sales Agreement in 2019, if not extended, will be transferred to the Ministry. The property, plant, and equipment, net, was $120 million and $132 million at December 31, 2009 and 2008, respectively.

Promigas has property, plant, and equipment for which, as part of their concession agreements, the government has the option to purchase upon conclusion of the contract in 2026 or its extended term, if any, at a price to be determined between the parties or by independent appraisers. The property, plant, and equipment balance, net, was $567 million and $849 million at December 31, 2009 and 2008, respectively.

F-24

Property, plant, and equipment of several Operating Companies is pledged as collateral for their respective long-term financings (see Note 15).

Depreciation and amortization expense is summarized as follows:


	For the Years Ended December 31,
	2009		2008		2007
	Millions of dollars (U.S.)
Depreciation and amortization of property, plant and equipment, including those recorded under capital leases	$	249	$	223	$	184
Amortization of intangible assets, net		23		45		33

Total	$	272	$	268	$	217

The Company capitalized interest of $15 million, $12 million and $5 million for each of the years ended December 31, 2009, 2008 and 2007, respectively.

11. INVESTMENTS IN AND NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES

The Company’s investments in and notes receivable from unconsolidated affiliates consist of the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Equity method:
Accroven (see Note 3)	$	41	$	24
Amayo (see Note 3)		9		—
BMG’s equity method investments		1		1
Chilquinta		371		266
EEC Holdings		7		7
Emgasud (see Note 3)		82		49
GTB (see Note 3)		66		15
POC		376		341
Promigas’ equity method investments		34		41
Proenergía’s equity method investments		17		—
Subic		10		9
Tecnored		31		21

Total investments — equity method		1,045		774
Total investments — cost method (see Notes 3 and 4)		80		13

Total investments in unconsolidated affiliates		1,125		787

Notes receivable from unconsolidated affiliates:
Chilquinta		—		98
GTB (see Notes 3 and 19)		23		14
Emgasud (see Notes 3 and 19)		15		—
TBG (see Notes 3 and 19)		14		8

Total notes receivable from unconsolidated affiliates		52		120

Total investments in and notes receivable from unconsolidated affiliates	$	1,177	$	907

The investment in Subic is with the holding company “AEI Investments, Inc.” In February 2009, the 15-year build-operate-transfer agreement (“BOT”) between Subic and the National Power Corporation of the Philippines (“NPC”) expired on schedule and the plant was turned over to the NPC without additional compensation. The Company’s remaining investment balance in Subic will be realized from the expected return of invested capital to shareholders upon final dissolution of the holding companies.

In November 2009, Chilquinta repaid its outstanding debt with the Company.

As of December 31, 2009, the Company’s share of the underlying net assets of its investments in POC, Chilquinta, Tecnored, Emgasud and Amayo was less than the carrying amount of the investments. The basis differential of $229 million represents primarily indefinite-lived intangible concession rights and goodwill.

Except for the $229 million of goodwill and intangibles noted above, the Company’s share of the underlying net assets of its remaining equity investments exceeded the purchase price of those investments. The net credit excess of $32 million as of December 31, 2009 is being amortized into income on the straight-line basis over the estimated useful lives of the underlying assets.

F-25

Equity income from unconsolidated affiliates is as follows:


	For the Years Ended December 31,
	2009		2008		2007
	Millions of dollars (U.S.)
Accroven	$	18	$	16	$	12
Chilquinta		23		32		1
POC		38		32		1
Promigas’ equity income from investments in unconsolidated affiliates		14		14		29
TR Holdings and GTB		9		8		23
Other		5		15		10

Total	$	107	$	117	$	76

As a result of the nationalization of Transredes (see Note 3), the Company’s accounting for its investment in Transredes and GTB changed from the equity method to the cost method in May 2008. As a result of the acquisition of additional interests in GTB in December 2009, the Company’s accounting for its investment in GTB changed from the cost method back to the equity method (see Note 3). Accordingly, the Company retroactively adjusted the equity earnings and investment in GTB to reflect the investment as if it had been recorded as an equity method investment for the entire period.

In September 2009, AEI acquired from a third party a 7.65% ownership interest in TGS. In December 2009, the Company acquired an additional 4% interest in TBG. The Company accounts for both of these investments under the cost method (see Note 3).

Dividends received from unconsolidated affiliates amounted to $53 million, $67 million and $32 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Summarized financial data for investments accounted for under the equity method as of December 31, 2009 is as follows:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Combined Balance Sheet data
Current assets	$	909	$	662
Noncurrent assets		3,126		2,126
Current liabilities		552		470
Noncurrent liabilities		1,569		968


	For the Years Ended December 31,
	2009		2008		2007
	Millions of dollars (U.S.)
Combined Income Statement data
Revenues	$	1,709	$	1,616	$	4,486
Cost of sales		915		940		3,522
Net income		229		227		266

12. GOODWILL AND INTANGIBLES

The Company’s changes in the carrying amount of goodwill are as follows:


	December 31,
	2009			2008
	Millions of dollars (U.S.)
Balance at January 1	$	614		$	402
Acquisitions:
New acquisitions (see Note 3)		3			225
Acquired goodwill from consolidation of new acquisitions		—			35
Impairment of goodwill		(5	)		—
Translation adjustments and other		51			(48	)

Balance at December 31	$	663		$	614

F-26

The Company’s carrying amounts of intangibles are as follows:


	December 31, 2009						December 31, 2008
	Cost		Accum. Amort.		Net		Cost		Accum. Amort.		Net
	Millions of dollars (U.S.)
Amortizable intangibles:
Customer relationships	$	178	$	33	$	145	$	171	$	20	$	151
Concession and land use rights		233		15		218		152		8		144
PPAs and contracts		63		51		12		64		43		21
Software costs		58		32		26		42		21		21
Other		5		5		—		4		4		—

Total amortizable intangibles	$	537	$	136		401	$	433	$	96		337

Nonamortizable intangibles:
Concession and land use rights						61						31
Proenergía trademarks						27						25

Total nonamortizable intangibles						88						56

Total intangibles					$	489					$	393

Goodwill — AEI evaluates goodwill and non-amortizable intangibles for impairment each year as of August 31 at the reporting unit level which, in most cases, is one level below the operating segment. There was no goodwill or non-amortizable intangibles impairment recognized in 2009 and 2008 as a result of the Company’s annual evaluation. Generally, each operating company business constitutes a reporting unit. The Company also tests for impairment if certain events occur that more likely than not reduce the fair value of the reporting unit below its carrying value. In the fourth quarter of 2009, an impairment analysis was performed as a result of the DCL plant shutdown and the Company recorded a charge totaling $25 million, including a $5 million impairment of goodwill, related to its investment in DCL (see Note 4). The Company had no goodwill impairment losses prior to this charge.

Intangibles — The Company’s amortizable intangible assets include concession rights and land use rights held mainly by certain power distribution and natural gas distribution businesses, continuing customer relationships of Delsur and Proenergía, and the value of certain favorable long-term PPAs held by several power generation businesses. The amortization of the PPAs may result in income or expense due to the difference between contract rates and projected market rates that are subject to change over the contract’s life. As of December 31, 2009 and 2008, the Company also had intangible liabilities of $52 million and $57 million, respectively, which represent unfavorable PPAs held by four of the power generation businesses (see Note 17).

On December 31, 2007, ENS voluntarily terminated its 20-year PPA, with such termination becoming effective as of April 1, 2008. The voluntary termination allows ENS to participate in the compensation system provided by Polish law (see Note 25). An intangible asset in the amount of $6 million associated with the long-term PPA was written off and included in amortization expense in 2007.

The following table summarizes the estimated amortization expense for the next five years and thereafter for intangible assets as of December 31, 2009:


	Millions of dollars (U.S.)
2010	$	36
2011		35
2012		31
2013		26
2014		23
Thereafter		250

Total	$	401

F-27

13. OTHER ASSETS

Other assets consist of the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Long-term receivables from customers:
Corporation Dominicana de Empresas Electricias Estatales (“CDEEE”) (see Note 25)	$	200	$	169
Promigas customers		141		128
Other		23		9

		364		306
Net investments in direct financing leases		—		63
Regulatory assets		34		49
Deferred income taxes		223		265
Investments in debt securities		239		192
Restricted cash (Note 7)		64		49
Deferred financing costs, net		22		22
Other miscellaneous investments		54		7
Other deferred charges		215		160
Other noncurrent assets		100		86

Total	$	1,315	$	1,199

Long-Term Receivables from Customers — San Felipe’s power purchase contract with its off-taker, CDEEE, includes a provision whereby CDEEE shall pay directly or reimburse San Felipe for any type of tax and associated interest or surcharges incurred by San Felipe in the Dominican Republic. The Company has reflected in other liabilities $200 million ($169 million in 2008) of accrued income, withholding taxes inclusive of associated penalties and interest, and an offsetting long-term receivable from CDEEE for the reimbursement of these tax items.

Promigas, through its subsidiaries in the local natural gas distribution sector, has unsecured long-term receivables with customers for household connections installation services and other notes receivables, with interest rates at an average of 28.8% annually, collected in Colombian pesos through monthly installments payable over a period of one to six years. The interest rate applied each year is the maximum legal rate allowed by the Superintendent of Finance, the Colombian regulatory body.

Net investment in direct financing lease — The Company acquired DCL in July 2008 and determined that the PPA of DCL should be accounted for as a direct financing lease. During the first quarter of 2009, the PPA of DCL was determined to be an operating lease versus a financing lease. Accordingly, the lease receivable balance was reclassified to property, plant and equipment. Subsequently in the second quarter of 2009, the PPA was terminated (see Note 25).

The components of the net investments in direct financing leases for DCL as of December 31, 2008:


	December 31, 2008
	Millions of dollars (U.S.)
Total minimum lease payments to be received	$	440
Less amounts representing executory costs		(180	)

Total minimum lease receivables		260
Less allowance for uncollectibles		(9	)
Less unearned income		(178	)
Less estimated residual value of leased properties		—

Net investments in direct financing leases		73
Current portion		10

Long-term portion	$	63

F-28

Investments in debt securities — The following table reflects activity related to investments in debt securities:


	For the Years Ended December 31,
	2009		2008			2007
	Millions of dollars (U.S.)
Available-for-sale debt securities:
Matured debt securities:
Fair value at beginning of period	$	168	$	282		$	268
Purchases of additional securities in exchange for AEI common stock		—		—			82
Purchases of additional securities for cash		—		—			5
Sale of existing securities		—		(38	)		—
Conversion to equity securities		—		—			(74	)
Realized loss on sale of securities		—		(14	)		—
Unrealized net gain (loss) affecting other comprehensive income		69		(62	)		1

Fair value at end of period		237		168			282

Corporate debt securities:
Fair value at beginning of period		—		—			24
Unrealized net loss affecting other comprehensive income		—		—			(24	)

Fair value at end of period		—		—			—

Total available-for-sale securities, end of period		237		168			282

Held-to-maturity debt securities:
Participation in commercial bank loan portfolio		—		22			22
Promissory notes		2		2			2

Total held-to-maturity securities		2		24			24

Total	$	239	$	192		$	306

In May 2008, the Company sold its interests in debt securities of Gas Argentino S.A. (“GASA”) that were recorded in the Company’s balance sheet as available-for-sale securities for $38 million in cash. The Company realized a loss of $14 million on the sale of these available-for-sale securities. The Company’s available-for-sale securities as of December 31, 2009 consist primarily of matured debt securities of CIESA, which holds controlling interests in TGS. No sales of available-for-sale securities occurred during 2009. Sales of available-for-sale securities in the future could result in significant realized gains or losses (see Note 19).

In September 2009, Promigas received a payment of $22 million upon maturity of its held-to-maturity debt securities. No gain or loss was recognized from this transaction.

14. ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Employee-related liabilities	$	70	$	48
Income taxes payable		25		—
Deferred income taxes		44		10
Other taxes		148		120
Interest		37		42
Customer deposits		68		64
Dividends payable to noncontrolling interests		16		17
Regulatory liabilities		65		35
Tax and legal contingencies		6		19
Cost Increase Protocol payable — Trakya		34		37
Compensation account under long-term PPA (see Note 7)		75		—
Deferred revenues		75		32
Other accrued expenses		54		47
Other		145		123

Total	$	862	$	594

Cost Increase Protocol payable — During the third quarter of 2008, Trakya reached a settlement with the Turkish government with respect to a tariff adjustment under Trakya’s Cost Increase Protocol and agreed to pay approximately $63 million over a two-year period commencing in September 2008, with such payments to be made by reduction of invoices to the Turkish state-run off-taker of Trakya’s energy supply. Over the two-year period, interest accrues on the unpaid balance at six-month LIBOR plus 3%.

F-29

15. LONG TERM DEBT

Long-term debt consists of the following:


	Variable or	Interest	Final	December 31,
	Fixed Rate	Rate (%)	Maturity	2009			2008
	Millions of dollars (U.S.), except interest rates
Debt held by Parent Company:
Senior credit facility, U.S. dollar	Variable	3.3	2014	$	893		$	936
Revolving credit facility, U.S. dollar	Variable	3.2	2012		113			390
Synthetic revolving credit facility, U.S. dollar	Variable	3.2	2012		105			105
PIK note, U.S. dollar	Fixed	10.0	2018		179			352
Debt held by consolidated subsidiaries:
Cálidda, U.S. dollar	Variable	4.2	2015		27			87
Cuiabá, U.S. dollar notes	Fixed	5.9	2015 — 2016		—			97
DCL, Pakistan rupee	Variable	10.6 — 15.8	2010 — 2019		78			77
Delsur, U.S. dollar	Variable	6.5	2015		65			73
EDEN, U.S. dollar	Variable	3.3	2013		4			37
Elektra, U.S. dollar senior notes	Fixed	7.6	2021		99			99
Elektra, U.S. dollar debentures	Variable	2.8	2018		20			20
Elektra, U.S. dollar revolving credit facility	Variable	4.3 — 5.5	2010		—			25
Elektro, Brazilian real debentures	Variable	9.9 — 10.3	2011		379			238
Elektro, Brazilian real note	Variable	4.3 — 14.7	2010 — 2021		237			132
EMDERSA, U.S. dollar debentures	Fixed	10.8	2010		46			—
EMDERSA, Argentine peso notes	Fixed	13.7 — 25.8	2010		16			—
ENS, Polish zloty loans	Variable	5.3	2010 — 2018		62			67
Luoyang, Chinese renminbi	Variable	5.9 — 9.9	2010 — 2016		119			133
PQP, U.S. dollar notes	Variable	2.2 — 3.2	2012 — 2015		71			88
Proenergía, Colombian peso notes	Variable	4.0 — 9.8	2010 — 2016		543			—
Proenergía, Chilean peso notes	Variable	0.7	2019		19			—
Proenergía, U.S. dollar notes	Variable	2.9 — 6.0	2010 — 2012		18			—
Promigas, Colombian peso debentures	Variable	7.1 — 13.7	2011 — 2019		397			116
Promigas, Colombian peso notes	Variable	8.3 — 9.6	2010 — 2024		72			534
Promigas, U.S. dollar notes	Variable	3.0 — 3.9	2010 — 2012		24			291
Trakya, U.S. dollar notes	Variable	4.4	2014		80			—
Others, U.S. dollar notes and Chinese renminbi	Fixed and Variable	5.3 — 8.5	2010 — 2016		52			65

					3,718			3,962
Less current maturities					(613	)		(547	)

Total				$	3,105		$	3,415

Interest rates reflected in the above table are as of December 31, 2009. The three-month U.S. dollar London Interbank Offered Rate (“LIBOR”) as of December 31, 2009 was 0.25%.

Long-term debt includes related party amounts of $386 million and $603 million as of December 31, 2009 and 2008, respectively, from shareholders associated with both the Company’s senior credit facility and PIK notes. Long-term debt also includes related party amounts of $97 million as of December 31, 2008 from loans provided to Cuiabá by the previous other shareholder in the project. In December 2009, the Company acquired the remaining 50% of equity interest in Cuiabá from the other shareholder in the project and, in conjunction with this acquisition, acquired the loans provided to Cuiabá by the other shareholder (see Note 3).

Aggregate maturities of the principal amounts of all long-term debt obligations of AEI and its consolidated subsidiaries for the next five years and in total thereafter are as follows:


	Millions of dollars (U.S.)
2010	$	613
2011		597
2012		450
2013		236
2014		957

Thereafter		865

Total	$	3,718

F-30

The long-term debt held by the Operating Companies is nonrecourse and is not a direct obligation of the Parent Company. However, certain Holding Companies provide payment guarantees and other credit support for the long-term debt of some of the Operating Companies (see Note 25). Many of the financings are secured by the assets and a pledge of ownership of shares of the respective Operating Companies. The terms of the long-term debt include certain financial and nonfinancial covenants that are limited to each of the individual Operating Companies. These covenants include, but are not limited to, achievement of certain financial ratios, limitations on the payment of dividends unless certain ratios are met, minimum working capital requirements, and maintenance of reserves for debt service and for major maintenance. All consolidated subsidiaries, except for DCL as mentioned below, were in compliance with their respective debt covenants as of December 31, 2009.

Senior Credit Facility — As of March 30, 2007, AEI refinanced its $1 billion credit facility originally dated May 23, 2006 with various financial institutions, raising funds under a new $1.5 billion credit facility, which consists of a $1 billion term loan, a $105 million synthetic revolver, and a $395 million revolver. The purpose of the credit facility was to refinance the existing senior and bridge loan on better terms and pricing and to provide for a revolver facility that provides the Company with additional liquidity. The refinancing was treated as an early extinguishment of debt and the difference between the reacquisition price and the net carrying amount plus any previously capitalized costs and reacquisition costs was recognized as a loss on early retirement of debt in the amount of $26 million. The refinanced term loan amortizes 30% of the principal over seven years in equal quarterly principal payments, and the remaining outstanding principal to be repaid at the end of the seventh year. The synthetic revolver and the revolver have no mandatory amortization, and amounts borrowed may be repaid and reborrowed. The synthetic revolver and the revolver each have a term of five years with the primary difference in the two revolver facilities being the undrawn commitment fee of 3% from the synthetic revolver and 0.5% for the revolver. At AEI’s election, the term loan accrues interest at LIBOR plus 3% or the rate most recently established by the designated administrative agent under the loan agreement as its base rate for dollars loaned in the United States plus 1.75%. The credit facility is secured by the pledge of shares in current and future direct project holding companies and all loans provided by AEI to its subsidiaries.

The senior credit facility contains a number of financial covenants which restrict the activities of the Company. The more significant financial covenants include certain interest coverage ratios on a stand-alone basis and leverage ratios (net debt to earnings before interest, taxes, depreciation and amortization, as defined “EBITDA”) on a consolidated basis. The Company was in compliance with these debt covenants as of December 31, 2009. The senior credit facility does not require reserves for debt service. For further information regarding hedging activity related to this debt instrument, see Note 19.

PIK Notes — In May 2007, AEI issued new Subordinated PIK Notes in the aggregate principal amount of $300 million and redeemed its $527 million Subordinate PIK notes issued in September 2006, plus $52 million in accrued interest. A loss on early retirement of debt of $7 million was recorded. The cash proceeds from the original PIK notes issued were used to pay a portion of the purchase price in the Prisma Energy International Inc.(“PEI”) acquisition and for general corporate purposes.

On March 11, 2009 the Company, upon amendment of the PIK Note Purchase Agreement, issued an option for up to one year to the PIK note holders to exchange their PIK notes for ordinary shares of AEI. The option period expired on March 12, 2010. Additionally, the amendment allowed the Company to purchase, upon the Holders election, the PIK notes in the open market for cash, subject to certain conditions. In March, August and October 2009, various funds that are managed by Ashmore Investment Management Limited (“Ashmore”) exercised their option to convert their PIK notes and related interest receivable in the amount of $196 million for 12,084,075 ordinary shares of AEI. Funds that are managed by Ashmore also own a majority of AEI’s shares. The Company recorded an equity transaction for the issuances of such shares and the early retirement of the related debt. As the PIK Notes exchanged were held by funds having the same investment advisor as our majority shareholders, the Company recorded a $28 million increase in paid-in-capital representing the difference between the carrying value of the acquired PIK notes and the estimated fair value of the Company’s ordinary shares at the date of issuance.

F-31

The existing Subordinated PIK Notes bear interest at 10%, and mature on May 25, 2018. Interest is payable semiannually in arrears (on May 25 and November 25 of each year) and is automatically added to the then outstanding principal amount of each note on each interest payment date.

Events of default under the PIK Note Purchase Agreement are limited and include among other customary items: (1) an AEI failure to timely repay PIK note principal, interest, and any applicable redemption premium; (2) an AEI failure to make payments or perform other obligations with respect to other AEI Parent Company indebtedness having a principal amount in excess of $50 million or the acceleration of any such indebtedness; and (3) AEI becoming insolvent, filing for bankruptcy protection, or having a court appoint a trustee with respect to a substantial portion of its property or enter an order in respect of AEI for bankruptcy protection.

The notes are expressly subordinate to AEI’s existing senior credit facilities. The noteholders agree not to accelerate the payment of the note obligations or exercise other remedies available to them with respect to the notes until satisfaction of all obligations under AEI’s existing senior credit facilities.

AEI may, upon notice to the noteholders, redeem the notes prior to maturity by paying the then outstanding principal amount of the note, plus a redemption premium, together with any accrued but unpaid and uncapitalized interest. The redemption premium is as follows: up to May 24, 2010 — at 106% of the face amount of the note, May 24, 2011 and thereafter — at 108% of the face amount of the note.

Cálidda — The $27 million senior loan bears interest at LIBOR plus 3.9%. Principal is due in quarterly installments beginning April 2007 through April 2015. The loan is guaranteed by a mortgage on Cálidda’s fixed assets related to its gas distribution concession. Cálidda and its external lenders signed a trust contract that established the transfer to the lenders of the rights to the collection and flow of funds received by Cálidda related to its gas distribution concession. This mortgage and trust contract established a first and preferred mortgage on Cálidda’s gas distribution concession and related assets, in favor of the lenders.

In March 2009, Cálidda repaid its subordinated loan of $47 million with funds provided through a loan with its shareholders, AEI and Promigas. The letter of credit, associated with the previous subordinated loan, was allowed to expire at repayment, which released $29 million of cash collateral.

DCL — DCL obtained a 5.15 billion Pakistan rupees ($66 million) long-term bank loan in 2005 to finance construction and equipment costs of the power generation facility. The loan bears interest at the Karachi Interbank Offered Rate (“KIBOR”) base interest rate on lending and is payable quarterly. Principal payments are due quarterly with maturity in 2019. The outstanding balance of this facility as of December 31, 2009 is 4.65 billion Pakistan rupees ($56 million). The loan is secured by DCL’s fixed and current assets.

DCL also has short-term bank loans of 1.43 billion Pakistan rupees ($17 million) for general working capital purposes and a proposed Phase II expansion. The loans bear interest at the KIBOR base interest rate on lending plus 3% to 4%. Interest is payable quarterly and the loans are secured by current assets.

For further information regarding notification of default from DCL’s lenders, see Note 25.

Delsur — Delsur entered into a $75 million senior secured term loan in August 2008 in order to refinance the $100 million bridge loan used to finance the Delsur acquisition. The remaining bridge loan principal balance was primarily repaid with cash received from capital contributions made by the Company. The loan bears interest at LIBOR (with a 3% floor) plus a variable margin of 3.5% to 4%. The loan matures in 2015 and is secured by a debt service reserve account and the fixed assets of Delsur, with interest and principal payable quarterly. Financial covenants include maintenance of certain leverage ratios, debt service coverage ratios and interest service coverage ratios. For further information regarding hedging activity related to this debt instrument, see Note 19.

EDEN — The financing consists of an unsecured loan agreement maturing in 2013. Principal and interest are payable on a quarterly basis. The loan bears interest at LIBOR plus 2.8% in 2009 and LIBOR plus 3.3% for the remaining four years. During the second and third quarters of 2009, AEI purchased from third parties $31 million of the $37 million of outstanding debt held by its consolidated subsidiary EDEN. A gain of $10 million was recognized and is included in “Gain on early retirement of debt” in the consolidated statements of operations.

F-32

In order to complete the acquisition of AESEBA, which owned 90% of the equity of EDEN (see Note 3), a waiver from third party lenders of the debt mentioned above was required due to the following covenants: change in control, change in the operator and cross default. The transfer of shares from the previous owner to the Company was completed in June 2007, constituting a breach of the existing credit agreement for this debt causing EDEN to be in default. In December 2009, EDEN signed a credit agreement amendment with its lenders and is no longer in default.

Elektra — Elektra has notes payable under a senior debt agreement totaling $100 million, with a $1 million unamortized discount at December 31, 2009. The notes have a fixed interest rate of 7.6%, payable semiannually, and mature in 2021. Principal payment is due upon maturity. The notes maintain a senior credit position and are unsecured.

On October 20, 2008, in a public offering, Elektra issued a $20 million aggregate principal amount of unsecured and unsubordinated corporate bonds due October 20, 2018. The bonds rank pari passu in right of payment with all other unsecured and unsubordinated obligations. The bonds bear interest at LIBOR plus 2.4% per annum, payable on a quarterly basis. Principal is due upon maturity. The proceeds from the offering of the bonds are used to fund current and future capital expenditures and for general corporate purposes. The bonds are subject to additional terms and conditions which are customary for this transaction. Loan covenants include maintenance of debt coverage ratios and other provisions.

Elektra maintains revolving credit lines for an aggregate amount of $100 million to finance working capital and energy purchases from suppliers. The lines of credit are unsecured and have a variable interest rate of LIBOR plus 1.5% to 2.5%, payable on a monthly basis. Floor rates of 5.5% and 5.8% exist for two of the revolving agreements. These facilities mature within one year from the date of issuance. In addition, certain of Elektra’s credit facilities require that it meet and maintain certain financial covenants, including debt coverage ratios and interest coverage ratios.

Elektro — The debt consists of public debentures issued in the amount of approximately 750 million Brazilian reais which were issued in three series that mature in equal installments. The first matured in 2009, and the remaining will mature in 2010 and 2011. The debentures accrue interest at floating rates indexed to the Brazil market general price index (IGP-M) for the first series, and to the Brazil Interbank interest rate (“CDI”) plus 1.7% per year for the second and third series. Interest is payable annually for the first series and semiannually for the second and third series. The principal of the debentures are unsecured. Interest payments are secured through a pledge of funds held in a reserve account, which had a balance of $1 million and $2 million at December 31, 2009 and 2008, respectively. A balance of 360 million Brazilian reais ($207 million) remains outstanding for these public debentures as of December 31, 2009.

On April 24, 2009, Elektro issued unsecured commercial paper totaling 120 million Brazilian reais (approximately $69 million) that matured in October 2009 and accrued interest at CDI plus 2%. On July 1, 2009, Elektro issued non-convertible debentures in the amount of 300 million Brazilian reais (approximately $172 million) which will mature in September 2011. The debentures pay an annual interest rate of CDI plus 1.4%. Proceeds from the new issuance were used to repay the unsecured commercial paper issued in April 2009 and debentures that matured in September 2009.

Elektro has also been provided with financing by BNDES — Banco Nacional de Desenvolvimento Econômico e Social (The Brazilian Development Bank), by Eletrobrás, the Brazilian state-owned electric company and by FINEP, the Brazilian Agency to finance research and development projects. These financings were provided for various capital expenditure and regulatory programs. These loans have maturities from 2010 through 2020 and accrue interest based on the Global Reversion Reserve fund rate (“RGR”) plus 5% per year or on the Brazil long-term interest rate, Taxa de Juros de Longo Prazo (“TJLP”), plus spreads from 0.9% to 6%. As of December 31, 2009, the total principal balances of these financings were 411 million Brazilian reais ($237 million). These financings are secured either by a pledge of collections flow or by bank letter of guarantee.

F-33

A summary of the relevant interest rates and indices for Brazil is as follows:


	December 31, 2009
CDI		8.6	%
IGP-M		(0.3	)%
RGR		0.0	%
TJLP		6.0	%

EMDERSA — EMDERSA’s electrical distribution subsidiaries issued $75 million in U.S. dollar-denominated debentures in 2006 accruing interest at 10.75% payable semi-annually. The remaining principal balance of $46 million is due in 2010. Financial covenants of these bonds require certain debt coverage ratios and interest coverage ratios.

ENS — On April 1, 2008, ENS amended and converted its $77 million U.S. dollar-denominated loan into an equivalent Polish zloty (“PLN”) loan concurrent with the change from its U.S. dollar linked 20 year PPA guaranteed by the Polish government to a market based PLN denominated medium-term PPA and Polish government stranded costs compensation program approved by the EU. In addition, ENS has amended its existing credit facility to extend the tenor by 3.5 years (including a 15-month grace period) and reduce the margin on interest rate to 1.1% — 1.4%. The loan is secured by all of ENS’s assets and a pledge of shares. The loan balance as of December 31, 2009 was 165 million Polish zloty ($57 million). Principal and interest payments are due quarterly. The loan requires reserves for maintenance and stranded-cost final correction. Together with the refinancing, a new 40 million Polish zloty ($14 million), three-year revolving working capital facility was also established. For further information regarding hedging activity related to this debt instrument, see Note 19. Given that the future revenues and credit facilities of ENS will be in Polish zloty, ENS changed its functional currency from U.S. dollars to Polish zloty as of April 1, 2008.

Luoyang — Luoyang obtained a 751 million Chinese renminbi ($121 million) long-term bank loan in 2004 to finance construction and equipment costs of a power generation facility. The loan bears interest at The People’s Bank of China’s (“PBOC”) base interest rate on lending and is payable quarterly. Principal payments are due semiannually with maturity in 2016. The outstanding balance of this facility as of December 31, 2009 is 575 million Chinese renminbi ($93 million). The loan is secured by an assignment of rights to the collection of the electricity and steam revenue of Luoyang. The loan agreement contains covenants which include certain restrictions on the disposal of fixed assets, changes in shareholding structure and providing guarantees to a third party. In November 2008, Luoyang signed a supplementary agreement with the China Development Bank to restructure the loan. Under this supplementary agreement, the timing of the principal payments remains unchanged but the payment amounts have been restructured. At the same time, all shareholders of Luoyang have signed a share pledge agreement with the China Development Bank. This share pledge agreement contains covenants which require pre-approval by the China Development Bank for dividend distributions.

Luoyang also has short-term bank loans of 159 million Chinese renminbi ($26 million) for general working capital purposes. The loans bear interest at 1.1 to 1.5 times the PBOC rate and 6.1% to 13.0% per annum. Interest is payable monthly or quarterly and principal payments are due in 2010. The loans are secured by fixed assets and the land use rights of Luoyang.

PQP — The financing for PQP includes notes payable and a revolving line of credit with a syndicate of commercial banks. The notes have variable interest rates of LIBOR plus 2.8%, with principal payable semiannually and interest payable quarterly and mature in 2015. The notes have reserve requirements for debt service, which are revised quarterly on the debt service dates. The revolving line of credit is part of the same credit agreement as the notes, bearing a rate of 0.5% for unused portions, 1.7% for letters of credit issuance, and LIBOR plus 2.0% for outstanding amounts. The revolving credit line matures in 2012 and is renewable for one year periods through 2015. Both credit facilities are secured by all of PQP’s assets, including major power purchase and fuel supply contracts and PQP’s power barges.

Proenergía — In July 2009, Proenergía was established as a wholly-owned subsidiary of Promigas to own the retail fuel operations. In August 2009, Promigas completed the spin-off of Proenergía to the shareholders of Promigas with the same ownership structure and percentage that existed prior to the spin-off. As a result, all debt related to the retail fuel operations ($584 million as of December 31, 2008) that was previously consolidated through Promigas is now consolidated through Proenergía. Financing consists of various promissory notes with local commercial banks and a term loan with other financial institutions. The majority of the promissory notes are denominated in Colombian pesos and bears various interest rates between 4.0% and 9.8% with maturities between 2010 and 2016. Interest payments are due either quarterly or semiannually.

F-34

The notes denominated in U.S. dollars were created by a credit agreement entered into by a subsidiary of Promigas in December 2007 for an amount of up to $250 million. The first draw in December 2007 for an amount of $189 million and the second draw in January 2008 for the remaining $61 million contained terms of a maturity of 5 years and with payments delayed for the first 30 months of the term. During the second and third quarters of 2009, Promigas and, subsequent to the spin-off, Proenergía repaid all of the U.S. dollar-denominated notes totaling $250 million. The payment was primarily refinanced in Colombian peso denominated notes. These new notes have a weighted average annual interest rate of 9.8% and mature between 2011 and 2014. The new notes are primarily unsecured.

Promigas — Promigas’ long-term debt financing consists primarily of Colombian peso debentures, Colombian peso notes, and U.S. dollar notes with local and international commercial banks.

The debentures were issued from 2001 to 2004 and accrue interest at the Colombian Consumer Price Index (“CCPI”) plus 7.4% to 7.5%. Interest is payable quarterly, semi-annually and annually. The debentures mature in 2011 (160 billion Colombian pesos or $78 million) and 2012 (100 billion Colombian pesos or $49 million).

The peso notes bear interest at rates ranging from 8.3% to 9.6%. The maturities of these notes vary from one to three years, with some principal payments due semiannually, while other loans were contracted under a bullet payment structure. Interest payments are due either monthly or quarterly. No assets are pledged as collateral under these loan facilities.

Promigas’ U.S. dollar notes have interest rates ranging from LIBOR to LIBOR plus 2.5%, maturities in 2012, interest payments due either quarterly or semiannually, and no collateral requirements.

In July and August 2009, Promigas issued bonds totaling 550 billion Colombian pesos (approximately U.S. $271 million) on the Colombian Stock Exchange. These bonds have a weighted average annual interest rate of 8.3% and mature between 2014 and 2024.

Trakya — The financing, obtained in the fourth quarter of 2009, consists of an $80 million unsecured loan agreement maturing in 2014. After a one year grace period, principal is paid in 9 semi-annual installments. Interest is payable on a semiannual basis. The loan bears interest at six month LIBOR plus 4%.

16. INCOME TAXES

AEI is a Cayman Islands company, which is not subject to income tax in the Cayman Islands. The Company operates through various subsidiaries in a number of countries throughout the world. Income taxes have been provided based upon the tax laws and rates of the countries in which operations are conducted and income is earned. Variations arise when income earned and taxed in a particular country or countries fluctuates from year to year.

The Company is subject to changes in tax laws, treaties, and regulations in and between the countries in which it operates. A change in these tax laws, treaties, or regulations could result in a higher or lower effective tax rate on the Company’s worldwide earnings.

Income Tax Provision — The provision for income taxes on income from continuing operations are comprised of the following:


	For the Years Ended December 31,
	2009		2008			2007
	Millions of dollars (U.S.)
Current:
Cayman Islands	$	—	$	—		$	—
Foreign		210		205			106

Total current		210		205			106

Deferred:
Cayman Islands		—		—			—
Foreign		69		(11	)		87

Total deferred		69		(11	)		87

Provision for income taxes	$	279	$	194		$	193

F-35

Effective Tax Rate Reconciliation — The Company’s effective tax rates for 2009, 2008 and 2007 were 49.2%, 40.8% and 56.0%, respectively. Excluding other charges, which reduce income before income taxes but have no corresponding tax benefit, the effective tax rates for 2009, 2008 and 2007 were 40.4%, 36.5% and 48.9%, respectively. A reconciliation of the Company’s income tax rate to its effective tax rate as a percentage of income before income taxes is as follows:


	December 31,
	2009			2008			2007
Statutory tax rate — Cayman Islands		0.0	%		0.0	%		0.0	%
Foreign tax rate differential		39.0	%		36.4	%		42.0	%
Change in valuation allowance		10.2	%		4.4	%		14.0	%

Effective tax rate		49.2	%		40.8	%		56.0	%

The foreign tax rate differential takes into account net losses of $92 million, $200 million and $218 million in 2009, 2008 and 2007, respectively, which do not generate a tax benefit by virtue of the 0% statutory tax rate in the Cayman Islands.

The Company provides for uncertain tax positions pursuant to ASC 740-10-25-6. Uncertain tax positions have been classified as non-current income tax liabilities unless expected to be paid in one year. The Company recognizes interest and penalties related to unrecognized tax benefits within the income tax expense line in the accompanying consolidated statement of operations. Accrued interest and penalties are included within the related tax liability line in the consolidated balance sheet. The Company believes it complies with applicable tax law and intends to defend its positions through appropriate administrative and judicial processes. The Company believes it has adequately provided for the outcome related to these matters.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits for the following years:


	For the Years Ended December 31,
	2009			2008			2007
	Millions of dollars (U.S.)
Unrecognized tax benefit, January 1	$	61		$	50		$	51
Gross increases, tax positions in prior period		1			4			5
Gross decreases, tax positions in prior period		(2	)		—			(12	)
Gross increases, tax positions in current period		24			12			16
Settlements		(8	)		—			(1	)
Lapse of statute of limitations		(6	)		(5	)		(9	)

Unrecognized tax benefit, December 31	$	70		$	61		$	50

Included in the balance of unrecognized tax benefits at December 31, 2009, are $55 million of tax benefits that, if recognized, would affect the effective tax rate.

Related to the unrecognized tax benefits noted above, the Company accrued penalties of $10 million and interest of $1 million during 2009 and in total, as of December 31, 2009, has recognized a liability for penalties of $71 million and interest of $36 million.

The Company does not believe that there will be a significant change in the amount of the unrecognized tax benefits within the next 12 months.

We have provided for taxes for the anticipated repatriation of earnings of our foreign subsidiaries. There is no intention to repatriate any undistributed earnings of our foreign subsidiaries above the amount for which taxes have already been provided.

F-36

The Company is subject to taxation in various countries around the world. Certain income tax returns of the Company’s non-U.S. subsidiaries remain open to examination by the respective taxing authorities as follows:


Jurisdiction		Years
Argentina		2005-present
Bolivia		2006-present
Brazil		2005-present
Colombia		2007-present
Dominican Republic		1998-June 2001 and 2005-present
Panama		2007-present
Philippines		2006-present
Poland		2005-present
Turkey		2005-present

Any net operating losses that were generated in prior years and utilized in these years may also be subject to adjustment by the taxing authorities.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as operating loss and tax credit carryforwards. The tax effects of the Company’s temporary differences and carryforwards are as follows:


	December 31,
	2009			2008
	Millions of dollars (U.S.)
Deferred tax assets:
Inventory	$	1		$	7
Goodwill		3			23
Accrued expenses		72			133
Operating losses and tax credit carryforwards		248			216
Reserves		165			101
Foreign currency and other		—			5
Valuation allowance		(251	)		(193	)

Total deferred tax assets		238			292
Deferred tax liabilities:
Fixed assets	$	(122	)	$	(158	)
Foreign currency, lease obligation and other		(58	)		(7	)

Total deferred tax liabilities		(180	)		(165	)

Total deferred tax assets (liabilities)	$	58		$	127

The Company has net operating loss carryforwards in several jurisdictions that expire between 2010 and 2019. The tax effected amount of these net operating loss carryforwards was $69 million at December 31, 2009 and $85 million at December 31, 2008. The Company also has net operating loss carryforwards in jurisdictions in which the net operating losses never expire. The tax effected amount of these net operating loss carryforwards were $169 million at December 31, 2009 and $125 million at December 31, 2008. The Company has tax credit carryforwards in several jurisdictions that expire between 2012 and 2019. Expiration of the Company’s net operating losses and tax credits for the next five years and in total thereafter, is as follows:


	Carryforward
	NOL		Tax Credit
	Millions of dollars (U.S.)
2010	$	8	$	—
2011		11		—
2012		24		2
2013		16		—
2014		5		1
Thereafter		5		6

Total	$	69	$	9

The Company records a valuation allowance when it is more likely than not that some portion or all of deferred tax assets will not be realized. The ultimate realization of deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. The balance of the valuation allowance increased by $58 million during 2009 to $251 million at December 31, 2009.

F-37

17. OTHER LIABILITIES

Other liabilities consist of the following:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Deferred revenue	$	523	$	437
Special obligations		261		192
Uncertain tax positions (see Note 16)		177		156
Notes payable to unconsolidated affiliates		8		109
Tax and legal contingencies (see Note 25)		39		68
Unfavorable PPAs (see Note 12)		52		57
Taxes payable — San Felipe (see Note 25)		72		66
Capital lease obligations		44		48
Cost Increase Protocol payable — Trakya (see Note 14)		—		25
Interest		—		22
Pension and other postretirement benefits (see Note 24)		14		14
Regulatory liabilities		84		25
Other		119		112

Total	$	1,393	$	1,331

Special obligations — These obligations represent consumers’ contributions to the cost of expanding Elektro’s electric power supply system. The assets acquired using the funds provided by consumers or the assets provided to the Company by consumers under the regulations of special obligations, are depreciated beginning in August 2007 based on the average assets’ useful lives as established by ANEEL — Agência Nacional de Energia Elétrica (“ANEEL”), the regulator of the Brazilian electricity sector.

Capital lease obligations — Summarized below are the future obligations relating to capital leases for certain pipelines, equipment and office furniture in which Promigas, Proenergía, Elektro and the Parent Company are the lessees. The related capital leases are recorded as obligations in the amount of $51 million ($57 million in 2008), with rates from 10% to 14%. As of December 31, 2009 and 2008, the gross assets under capital leases were $101 million and $57 million and accumulated amortization amounted to $16 million and $15 million, respectively. The leases are all nonrecourse to AEI.

Aggregate maturities of the principal amounts of all capital lease obligations of AEI and its consolidated subsidiaries, for the next five years and in total thereafter, are as follows.


	Millions of dollars
	(U.S.)
2010	$	12
2011		9
2012		9
2013		14
2014		15
Thereafter		12

Future minimum lease payments		71
Less amount representing interest		20

Total	$	51

18. LEASE ARRANGEMENTS

The Company determined that the PPAs entered into by Trakya, San Felipe, JPPC and Tipitapa are operating leases.

Future minimum lease revenues associated with operating leases to be received for the next five years and in total thereafter are as follows:


	Millions of dollars
	(U.S.)
2010	$	170
2011		158
2012		164
2013		163
2014		157
Thereafter		522

Total	$	1,334

F-38

The company also entered into various operating leases for land, offices, office equipment and vehicles as lessee. Future minimum lease payments associated with all operating leases to be paid for the next five years and in total thereafter are as follows:


	Millions of dollars
	(U.S.)
2010	$	8
2011		5
2012		4
2013		4
2014		1
Thereafter		2

Total	$	24

19. FAIR VALUE OF FINANCIAL INSTRUMENTS

There are three levels in the fair value hierarchy to prioritize inputs used to measure fair value giving the highest priority to quoted prices in active markets, and the lowest priority to unobservable inputs, defined as follows:

Level 1 — Inputs that employ the use of quoted market prices (unadjusted) of identical assets or liabilities in active markets. A quoted price in an active market is considered to be the most reliable measure of fair value.

Level 2 — Inputs to the valuation methodology other than quoted prices included in Level 1 that are observable for the asset or liability. These observable inputs include directly-observable inputs and those not directly-observable, but are derived principally from, or corroborated by, observable market data through correlation or other means.

Level 3 — Inputs that are used to measure fair value when other observable inputs are not available. They should be based on the best information available, which may include internally developed methodologies that rely on significant management judgment and/or estimates.

The following table represents AEI’s assets and liabilities that are measured at fair value on a recurring basis:


			Fair Value Measurement at Reporting Date Using
			Final Quoted Prices
			in Active Markets		Significant Other		Significant
	December 31,		for Identical		Observable Inputs		Unobservable Inputs
Assets	2009		Assets (Level 1)		(Level 2)		(Level 3)
	Millions of dollars (U.S.)

Available-for-sale securities	$	237	$	—	$	237	$	—
Derivatives		12		—		12		—

Total assets	$	249	$	—	$	249	$	—

Derivatives	$	42	$	—	$	42	$	—

Total liabilities	$	42	$	—	$	42	$	—

Available-for-Sale Securities

The Company’s available-for-sale securities currently consist primarily of matured debt securities of an Argentine holding company, CIESA (see Note 3), which holds controlling interests in TGS, a publicly traded Argentine gas transportation company. The matured debt securities were convertible upon governmental approval into equity interests in the holding company pursuant to a debt restructuring agreement, entered into in 2005. On January 8, 2009, the Company terminated the agreement by providing written notification of its desire to terminate to the signators of the agreement pursuant to the terms of the restructuring agreement. These securities were originally contributed to the Company or acquired from March 2006 through January 2007. The aggregate cost of the CIESA debt securities from various contribution and acquisition dates totals $245 million. The securities represent approximately 92% of the total debt of CIESA and 100% of its matured securities.

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The approximate fair market value of the securities at December 31, 2009 and December 31, 2008 was $237 million and $168 million, respectively. The values consider the termination of the debt restructuring agreement and the underlying equity value of TGS, based on CIESA’s ownership of 55% of TGS. The valuation decreased below the original cost beginning in the fourth quarter of 2007 due to the decline in the stock price of TGS, which trades on both the Argentine and New York stock exchanges. The decrease in the valuation from its cost as of December 31, 2009 has resulted in $8 million of unrealized losses, or 3% lower than original cost, in the Company’s other accumulated comprehensive income account.

At each period end, including as of December 31, 2009 and 2008, in order to evaluate any impairment in its debt securities, the Company applies a systematic methodology considering its ability and intent to hold the security, its expected recovery of the amortized cost and any qualitative factors that may indicate the likelihood that such impairment is other-than-temporary. The Company also evaluated the near-term prospects of the successful receipt of the required governmental and regulatory approvals, considered the historical and current operating results of TGS, and considered collection of the value of the securities in a bankruptcy or a negotiated resolution. The debt securities, which represent a claim against the assets of CIESA (consisting primarily of the 55% interest in TGS), could still ultimately be exchanged for CIESA or TGS equity. The Company believes that the ultimate outcome of the debt will be conversion into an asset with a value at least equal to the original cost of the securities, whether through bankruptcy or a negotiated resolution.

Considering the Company’s intent regarding the conversion to equity of CIESA through one of various alternatives to gain an indirect ownership interest in TGS, and the Company’s ability to hold these securities for a reasonable period of time sufficient for a forecasted recovery of cost, the Company does not consider those investments to be other-than-temporarily impaired as of December 31, 2009 and 2008. For further information regarding CIESA debt securities, see Note 25.

We currently hold an option to acquire, indirectly, an approximate 10% equity interest in CIESA. We acquired the option on September 3, 2009 in conjunction with the acquisition of certain other assets in exchange for a combination of cash and ordinary shares of AEI. If we choose to exercise this option, closing of the transaction will be subject to regulatory approvals in Argentina.

Derivatives

Objectives for Using Derivatives — The Company is exposed to certain risk relating to its ongoing business operations. The primary risks managed by using derivative instruments are interest rate risk, foreign currency risk and commodity price risk. These risks are managed through the use of derivative instruments including interest rate swaps, foreign currency contracts and commodity contracts.

Accounting for Derivatives Impact on Financial Statements — The Company reflects all derivatives as either assets or liabilities on the consolidated balance sheet at their fair value. The fair value of AEI’s derivative portfolio is determined using observable inputs including LIBOR rate curves, commodity price forward curves and forward foreign exchange curves. All changes in the fair value of the derivatives are recognized in income unless specific hedge criteria are met. Changes in the fair value of derivatives that are highly effective and qualify as cash flow hedges are reflected in accumulated other comprehensive income (loss) and recognized in income when the hedged transaction occurs or no longer is probable of occurring. Any ineffectiveness is recognized in income. Changes in the fair value of hedges of a net investment in a foreign operation are reflected as cumulative translation adjustments in accumulated other comprehensive income (loss).

Interest Rate Swaps — As of December 31, 2009, the Company had $3.37 billion in variable rate debt and $352 million in fixed rate debt. The Parent and certain operating companies have entered into various interest rates swap agreements to limit their interest rate risk exposures to variable-rate debt. The Company has designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the swaps are deferred in other comprehensive income until interest expense on the related debt is recognized in earnings. Maturities on this interest rate swap range from 2010 to 2018. The total notional value of interest rate swaps that have been designated and qualify for the Company’s cash flow hedging program as of December 31, 2009 was approximately $1.00 billion. As of December 31, 2009, deferred net loss on the interest rate swaps of $31 million recorded in accumulated other comprehensive income (loss) is expected to be reclassified into interest expenses during the next twelve months.

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Foreign currency contracts — The Company uses hedge transactions classified as net investment hedges to protect its net investment in various operating companies against adverse changes in the exchange rate between the U.S. dollar and the local currency. Since the derivative’s underlying exchange rate is expected to move in tandem with the exchange rate between the functional currency (the local currency) of the hedged investment and AEI’s reporting currency (U.S. dollar), no material ineffectiveness is anticipated. The total notional value of foreign currency contracts that have been designated and qualify for the Company’s net investment hedging program as of December 31, 2009 was approximately $88 million.

The Company also entered into certain derivative contracts with a notional amount of $13 million as of December 31, 2009 which were not designated as hedging instruments or were de-designated from the original hedging relationship. These contracts were designed to economically mitigate foreign exchange risk associated with the local currency-based dividends received from certain operating companies and the scheduled payments on EMDERSA’s U.S. dollar-denominated debt.

Commodity derivatives — While generally our contracts are structured to minimize our exposure to fluctuations in commodity fuel prices, some of our operating companies entered into various commodity derivative contracts for a period ranging from 16 months to 31 months to protect margins for a portion of future revenues and cost of sales. The Company has designated the commodity derivatives as cash flow hedges. The total notional amount of those commodity derivatives that have been designated and qualify for the Company’s cash flow hedging program as of December 31, 2009 was approximately 85,000 barrels of fuel oil and 28,600 MMBTU of natural gas. As of December 31, 2009, deferred net gain on the commodity derivative contracts of less than $1 million recorded in accumulated other comprehensive income (loss) is expected to be reclassified into cost of sales during the next twelve months.

The balance sheet classification of the assets and liabilities related to derivative financial instruments is summarized below as of December 31, 2009 and 2008 (in millions of dollars (U.S.)):


	Derivative Assets			Derivative Liabilities
As of December 31, 2009	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Derivatives designated as hedging instruments
Interest rate swaps	Prepaids and other current assets	$	—	Accrued and other current liabilities	$	7
Foreign currency contracts	Prepaids and other current assets		—	Accrued and other current liabilities		1
Commodity contracts	Prepaids and other current assets		1	Accrued and other current liabilities		—
Interest rate swaps	Other assets		11	Other liabilities		34

Total Derivatives designated as hedging instruments		$	12		$	42


	Derivative Assets			Derivative Liabilities
As of December 31, 2008	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Derivatives designated as hedging instruments
Interest rate swaps	Prepaids and other current assets	$	—	Accrued and other current liabilities	$	1
Foreign currency contracts	Prepaids and other current assets		1	Accrued and other current liabilities		—
Interest rate swaps	Other assets		—	Other liabilities		63

Total Derivatives designated as hedging instruments		$	1		$	64

F-41

The following table summarizes the effect of all cash flow hedges on the consolidated statements of operations (in millions of dollars (U.S.)):


	Gain (Loss)			Gain (Loss) Reclassified from			Gain (Loss) Recognized in
	Recognized			AOCI into Interest Expense			Other Income (Expense)
	in OCI			(Effective Portion)			(Ineffective Portion)
Interest Rate Swaps:
For the Years Ended December 31,
2009	$	2		$	(30	)	$	—
2008		(54	)		(9	)		(2	)
2007		(23	)		4			1
Commodity Contracts:
For the Years Ended December 31,
2009	$	—		$	(1	)	$	—

The following table summarizes the effect of all net investment hedges on the consolidated statements of operations (in millions of dollars (U.S.)):


				Gain (Loss) Reclassified from
	Gain (Loss)			AOCI into Foreign Currency		Gain (Loss) Recognized in
	Recognized			Transaction Gain (Loss)		Other Income (Expense)
	in OCI			(Effective Portion)		(Ineffective Portion)
Foreign Currency Contracts:
For the Years Ended December 31,
2009	$	(20	)	$	—	$	—
2008		(5	)		—		—
2007		—			—		—

The following table summarizes the effect of other derivative instruments the Company entered into that do not qualify for hedging treatment (in millions of dollars (U.S.)):


	Gain (Loss) Recognized in
	Foreign Currency
	Transaction Gain(Loss)
Foreign Currency Contracts:
For the Years Ended December 31,
2009	$	(10	)
2008		6
2007		(14	)

Financial Instruments

The fair value of current financial assets and current financial liabilities approximates their carrying value because of the short-term maturity of these financial instruments. The fair value of long-term debt and long-term receivables with variable interest rates also approximates their carrying value. For fixed-rate long-term debt and long-term receivables, fair value has been determined using discounted cash flow analyses using available market information. The fair value of derivatives is the estimated net amount that the Company would receive or pay to terminate the agreements as of the balance sheet date. The fair value of cost method investments has not been estimated as there have been no identified events or changes in circumstances that may have a significant adverse effect on the fair value.

The fair value estimates are made at a specific point in time, based on market conditions and information about the financial instruments. These estimates are subjective in nature and are not necessarily indicative of the amounts the Company could realize in a current market exchange. Changes in assumptions could significantly affect the estimates.

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The following table summarizes the estimated fair values of the Company’s long-term investments, debt, and derivative financial instruments:


	December 31,
	2009				2008
	Carrying Value		Fair Value		Carrying Value		Fair Value
			Millions of dollars (U.S.)
Assets:
Notes receivable from unconsolidated subsidiaries	$	52	$	47	$	120	$	123
Investment in debt securities, including available-for-sale securities		239		239		192		192
Derivatives		12		12		1		1
Liabilities:
Derivatives		42		42		64		64
Long-term debt, including current maturities		3,718		3,659		3,962		3,753

Customer Concentration

The Operating Companies that rely upon one or a limited number of customers are subjected to concentrations of credit risk with respect to accounts receivable. In several instances, the obligations of the sole customers are supported by guarantees and other forms of financial support by the respective foreign governments, or government-owned or controlled agencies or companies. As of December 31, 2009, no single customer accounts for over 10% of accounts receivable. As of December 31, 2008, one customer accounted for 18% of accounts receivable.

20. PER SHARE DATA

Basic and diluted earnings per share attributable to AEI were as follows:


	For the Years Ended December 31,
	2009		2008		2007
Basic earnings per share attributable to AEI:
Income from continuing operations attributable to AEI (millions of U.S. dollars)	$	297	$	158	$	87
Average number of common shares outstanding (millions)		234		218		209
Income from continuing operations per share attributable to AEI	$	1.27	$	0.73	$	0.42
Effect of dilutive securities:
Stock options (millions of options)		—		—		—
Restricted stock (millions of shares)		—		—		1
Convertible PIK notes (millions of shares)		—		—		—
Dilutive earnings (loss) per share attributable to AEI	$	1.27	$	0.73	$	0.42

The Company issues restricted stock grants to directors and employees which are included in the calculation of basic earnings per share. At December 31, 2009, 2008 and 2007, 4,740,085, 3,187,830 and 2,373,729 stock options and restricted shares issued to employees, respectively, were excluded from the calculation of diluted earnings per share because either the exercise price of those options exceeded the average fair value of the Company’s stock during the related period or the future compensation expense of those restricted shares exceeded the implied cost of the Company issuing those shares. At December 31, 2009, $181 million of PIK note principal and accrued unpaid interest, convertible into 10,505,761 shares of AEI (see Note 15), was excluded from the calculation of diluted earnings per share because the conversion would be anti-dilutive.

On April 1, 2008, the Company entered into a subscription agreement with Buckland Investment Pte Ltd., or Buckland, an investment holding vehicle managed by GIC Special Investments Pte Ltd (“GIC”). GIC is the private equity investment arm of Government of Singapore Investment Corporation (Ventures) Pte Ltd., a global investment management company established in 1981 to manage Singapore’s foreign reserves. On May 9, 2008, the Company sold GIC 12.5 million of its ordinary shares at a subscription price of $16 per share. The gross proceeds that the Company received from this issuance were $200 million. The Company used a portion of these proceeds to repay a portion of its revolving credit facility and to make dividend payments to noncontrolling shareholders of the operating companies. Upon closing, a nominee of Buckland was appointed to the Company’s board of directors.

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21. EQUITY

Accumulated other comprehensive income (loss) consists of the following:


	December 31,
	2009			2008
	Millions of dollars (U.S.)
Cumulative foreign currency translation	$	265		$	(131	)
Unrealized derivative losses		(36	)		(68	)
Unamortized actuarial and investment gains		50			54
Unrealized gain (loss) on available-for-sale securities		10			(59	)

Total	$	289		$	(204	)

The change in the cumulative foreign currency translation results from the significant appreciation in the currencies of the Company’s subsidiaries compared to the U.S. dollar in 2009, particularly the Brazilian real.

The following table presents the effects of changes in ownership interest in subsidiaries on AEI’s equity:


	For The Years Ended December 31,
	2009			2008		2007
	Millions of dollars (U.S.)
Net income attributable to AEI	$	297		$	158	$	131
Transfers to (from) the noncontrolling interest
Increase (decrease) in AEI’s paid-in capital for:
Purchase 50% of Cuiaba		6			—		—
Purchase 31% of Trakya		(102	)		—		—
Amayo transaction		(4	)		—		—

Net transfers to the noncontrolling interests		(100	)		—		—

Change from net income attributable to AEI and transfers to the noncontrolling interest	$	197		$	158	$	131

22. RELATED-PARTY TRANSACTIONS

Ashmore provides certain management services to the Company through a Management Service Agreement (“MSA”) effective May 20, 2006. The initial term of the MSA was for one year and renews for successive one-year periods from May to May each year unless terminated by either party. Charges include (1) actual costs of employees performing the services (including salary, bonus, benefits, and long-term incentive grants) and (2) reimbursement of reasonable and documented expenses. The maximum annual amount of fees that may be billed under the MSA during each one-year term is approximately $5 million (excluding expenses).

A material amount of Elektra’s revenues and costs of sales is related to transactions with governmental or quasi-governmental entities, while the Panamanian government is also a significant shareholder in Elektra.

Interest expense to shareholders — The Company recorded interest expense to shareholders of $34 million, $52 million and $63 million during 2009, 2008 and 2007, respectively, related to debt.

Interest income from unconsolidated subsidiaries — The Company recognized interest income from shareholder loans to Emgasud in the amount of $1 million during 2009 and from development and shareholder loans to TBG and GTB in the amount of $2 million during each of 2009, 2008 and 2007.

23. COMPENSATION PLANS

Annual Incentive Plans — The Company has a discretionary annual incentive plan for the U.S. and certain foreign-based employees that is designed to recognize, motivate, and reward exceptional contribution toward the accomplishment of Company objectives. The plan is based on target bonus opportunities expressed as a percentage of annual base salary with threshold, target, and maximum award levels. Funding is calculated based on goal achievement and job-level weighting tied to financial, operational and individual performance. Many of the Operating Companies also provide annual incentive plans based on the performance of their individual businesses.

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2007 Equity Incentive Plan — AEI adopted a Board of Directors-approved Incentive Plan for a ten-year period commencing January 2007. The purpose of the plan is to attract and retain the best available talent; to encourage the highest level of performance by directors, executive officers, and selected employees; and to provide them with incentives to put forth maximum efforts for the success of the Company’s business in order to serve the best interests of the Company and its shareholders. The plan allows for an aggregate number of 15,660,340 ordinary shares to be awarded over the ten-year period. Awards can be made in the form of stock Appreciation Rights or Stock Options, or as Restricted Shares. The plan also allows for the issuance of the same types of stock Appreciation Rights, Stock Options, Restricted Shares, Restricted Stock Units, Performance Shares, or Performance Units in order to pay Annual Incentive Bonuses. Each grant is pursuant to the approval of the Compensation Committee of the Board of Directors, which has the power to set the value, quantity, and allocation of such awards.

Awards issued to non-employee directors vest over four years in accordance with the grant agreement. There were several grants to non-employee directors in 2009, 2008 and 2007, which resulted in compensation expense during 2009, 2008 and 2007 for these awards that was negligible.

The fair value of each grant has been estimated using the Black-Scholes-Merton model. Weighted average fair values and valuation assumptions used to value stock options issued under the 2007 Equity Incentive Plan are disclosed for the periods indicated as follows:


	2009			2008			2007
Weighted Average Fair Value of Grants	$	3.77		$	5.39		$	4.61
Expected Volatility		29.22	%		25.37	%		25.00	%
Risk-Free Interest Rate		1.55	%		3.20	%		4.00	%
Dividend Yield		0.00	%		0.00	%		0.00	%
Expected Life	5.08 Years			6.58 Years			7 Years

Expected volatility is based upon the weekly stock price changes over a four year period of certain competitors who closely approximate AEI in geographic diversity, nature of operations and risk profile. The risk-free interest rate is based upon United States Treasury yields in effect at the time of the grant. The expected life is based upon simplified calculations of expected term for non-public companies.

Under the plan, employees may be granted restricted non-vested stock. The restricted stock granted vests to the employee on a graduated vesting schedule ranging from one to four years as defined in the individual grant agreements. Upon vesting, restricted stock is converted into common stock and released to the employee. Stock-based compensation expense related to restricted stock was $3 million, $2 million and $1 million for 2009, 2008 and 2007, respectively.

Summarized restricted stock award activity under the 2007 Equity Incentive Plan for the periods indicated:


				Weighted-		Aggregate
				Average		Intrinsic
Restricted Stock	Shares			Grant Price		Value
						(Millions of
	(Thousands)					dollars (U.S.))
Granted during 2007		500		$	12.63	$	6
Vested during 2007		—			—		—
Granted during 2008		238		$	16.03	$	4
Vested during 2008		44		$	12.75		—

Nonvested, January 1, 2009		636		$	13.83	$	9
Granted		262			13.10		3
Forfeited		(43	)		13.79		(1	)
Exercised		(17	)		13.02		—
Vested		(74	)		13.30		(1	)

Nonvested, December 31, 2009		764		$	13.62	$	10

As of December 31, 2009, there was $6 million of total unrecognized compensation cost related to nonvested restricted stock under the 2007 Equity Incentive Plan. This cost is expected to be recognized over a weighted-average period of 2.17 years.

Under the plan, employees may be granted non-vested stock options. The stock options granted vest to the employee on a graduated vesting schedule ranging from one to four years as defined in the individual grant agreements. Upon vesting, stock options may be exercised by the employee, for which the Company will issue new shares. Stock-based compensation expense related to stock options was $4 million, $3 million and $1 million for 2009, 2008 and 2007, respectively.

F-45

Summarized option award activity under the 2007 Equity Incentive Plan for the periods indicated is as follows:


						Weighted
				Weighted		Average
				Average		Exercise		Aggregate
				Fair Value		Price of		Intrinsic
Stock Options	Options			of Grants		Grants		Value
								(Millions of
	(Thousands)							dollars (U.S.))

Exercised during 2007		31		$	4.11	$	11.18	$	—
Exercised during 2008		—			—		—		—

Outstanding, January 1, 2009		2,729		$	4.97	$	14.09	$	14
Granted		1,690			3.77		13.10		6
Forfeited		(238	)		4.57		13.83		(1	)
Expired		(31	)		4.54		12.70		—
Exercised		—			—		—		—

Outstanding, December 31, 2009		4,150		$	4.51	$	13.71	$	19

Exercisable as of December 31, 2009		505		$	4.81	$	13.36	$	2

As of December 31, 2009, there was $9 million of total unrecognized compensation cost related to nonvested stock options under the 2007 Equity Incentive Plan. This cost is expected to be recognized over a weighted-average period of 2.37 years.

As a Cayman Islands entity, AEI does not realize any tax benefits from the granting or exercising of restricted stock and stock options.

2004 Stock Incentive Plans — In 2004, PEI adopted a long-term incentive compensation plan (“Stock Incentive Plan”) that provided awards to certain directors, officers, and key employees of PEI and its subsidiaries. Awards issued to non-employee directors are fully vested at the grant date in accordance with the grant agreement.

Under the Stock Incentive Plan, PEI granted share units in 2004, some of which had time-based vesting and some of which had performance-based vesting. For the units that vested based on time, the units vested over a 36-month period from October 1, 2004 through December 31, 2007. The number of units that vested based on performance was determined based on the actual financial performance of PEI for the period from September 1, 2004 through December 31, 2006, compared to performance goals of PEI set out in the grant agreements.

Compensation expense recognized for the Stock Incentive Plan was $10 million for 2007. Amounts related to the share units granted in 2004 through 2006, which were settled in the form of shares, have been reflected in shareholders’ equity as additional paid-in capital. All restricted shares outstanding at December 31, 2007, relating to the Stock Incentive Plan, were vested as of such date.

Summarized time-based share unit award and performance-based share unit award activity is as follows:


			Weighted-
			Average		Aggregate
			Grant		Intrinsic
	Units/Shares		Price		Value
					(Millions of
	(Thousands)				dollars (U.S.))

Total time-based restricted shares vested during 2007		586	$	7.99	$	5
Total performance-based restricted shares vested during 2007		2,179	$	7.99	$	17

Sales Incentive Plan — In 2005, PEI adopted an incentive compensation plan (“Sales Incentive Plan”) to provide incentives and awards to retain and motivate certain directors, officers, and key employees of PEI and its subsidiaries in the event of a divestiture of PEI by Enron. Awards under this plan were granted as cash awards (“Cash Awards”). Cash Awards vested 50% upon the effectiveness of a change of control (September 6, 2006) and 50% on September 6, 2007. All vested Cash Awards have been settled and paid. Compensation expense recognized for the Sales Incentive Plan was $3 million and $17 million for 2008 and 2007, respectively.

F-46

Summarized activity of restricted stock of the company issued in lieu of the second Sales Incentive Plan payment, as was provided as an option for Sales Incentive Plan participants, is as follows:


			Weighted-
			Average		Aggregate
			Grant		Intrinsic
	Units/Shares		Price		Value
					(Millions of
	(Thousands)				dollars (U.S.))
Total restricted shares vested during 2007		312	$	7.99	$	2
Total restricted shares vested during 2008		201	$	7.99	$	2

24. PENSION AND OTHER POSTRETIREMENT BENEFITS

The Company maintains a defined contribution plan for substantial portions of its employees. All of its U.S.-based and expatriate employees are covered by a defined contribution plan. The Company matches 100% for the first 3% of eligible compensation contributed by the employee and 50% for the next 2% contributed. The Company also has defined contribution plans for other foreign employees. The Company contributes up to 5% of eligible compensation for these plans. The employees are fully vested in these plans immediately. The amount of cost recognized for defined contribution plans was less than $1 million each for 2009, 2008 and 2007, respectively. The Company’s U.S.-based and expatriate employees participate in AEI employee benefit programs, including health insurance and savings plans. The expense for these benefits was $2 million, $1 million and $1 million in 2009, 2008 and 2007, respectively.

In certain countries, including Panama, El Salvador, Turkey, Brazil and Colombia, local labor laws or union agreements require the Company to pay severance indemnities to employees when their employment is terminated. As required under the laws of Panama and El Salvador, the Company has funded a portion of its estimated severance benefit obligations into a trust account. Accrued severance indemnities included in other liabilities was $5 million and $4 million as of December 31, 2009 and 2008, respectively. In Brazil, the Company has agreed with its union to create a special retirement program in which the Company provides incentives to retirement eligible employees to retire. At December 31, 2009 and 2008, Elektro has accrued $8 million and $0 million, respectively, associated with this program. In Argentina, EDEN is required to pay certain benefits to employees upon retirement. EDEN is not required to deposit funds into a trust, but has accrued benefit obligations of $5 million and $7 million as of December 31, 2009 and 2008, respectively, and recorded an increase in other comprehensive income of $1 million and a decrease in other comprehensive income of $1 million in 2009 and 2008, respectively. The Company accrues these benefits based on historical experience and valuations performed by third parties or the Company.

Elektro Plans — Elektro sponsors two supplementary pension plans for its employees. The Proportional Balances Supplementary Benefit Plan (“PBSBP”) provides guaranteed benefits to employees who were participants prior to December 31, 1997. The Elektro Supplementary Plan of Retirement and Pension (“ESPRP”), which began on January 1, 1998, is a mixed plan that offers defined benefits for 70% of eligible compensation and defined contributions for 30% of eligible compensation.

The PBSBP does not accept new participants. When the ESPRP was created, the existing participants were allowed to transfer to the new plan. Participants who transferred were given the right to receive a balanced benefit proportional to their years of participation in the PBSBP. Participants could elect to make new contributions to the ESPRP.

Investment Policies and Strategies — The pension plan sponsored by Elektro is to provide eligible employees with scheduled payments. Elektro follows consistent standards for preservation and liquidity with the goal of earning the highest possible return while minimizing risk. Elektro employs a total return investment approach for its pension benefit plans, whereby a mix of fixed income, equity and real estate investments are used to maximize the long-term return of pension plan assets. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolios contain a diversified blend of fixed-income, equity and real estate investments. Furthermore, equity investments are diversified across market capitalization through investments in Brazilian large-capitalization stocks, Brazilian medium-capitalization stocks and Brazilian small-capitalization stocks. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies and quarterly investment portfolio reviews.

F-47

The target allocation percentage of the plan assets is as follows:


	December 31,
	2009			2008
Fixed income		76.1	%		70.6	%
Equity		14.5	%		21.9	%
Real estate		4.7	%		4.0	%
Loans to participants		4.7	%		3.5	%

Total		100.0	%		100.0	%

The actual allocation percentage of the plan assets is as follows:


	December 31,
	2009			2008
Fixed income		73.0	%		75.7	%
Equity		18.6	%		17.3	%
Real estate		5.2	%		3.6	%
Loans to participants		3.2	%		3.4	%

Total		100.0	%		100.0	%

The fair value and related input level for each major category of plan assets as of December 31, 2009 are as follows:


			Fair Value Measurement at Reporting Date Using
			Final Quoted
			Prices in Active		Significant
			Markets for		Other		Significant
	December 31,		Identical Assets		Observable		Unobservable
Plan assets	2009		(Level 1)		Inputs (Level 2)		Inputs (Level 3)
	Millions of dollars (U.S.)
Fixed income	$	327	$	327	$	—	$	—
Equity		74		74		—		—
Real estate		21		—		21		—
Loans to participants		11		—		11		—

Total	$	433	$	401	$	32	$

The plan assets investments are classified within Level 1 or Level 2 of the fair value hierarchy because they are valued using quoted market prices or alternative pricing models with reasonable levels of price transparency. The types of instruments valued based on quoted market prices in active markets include most fixed income and equity investments. The fair value of such instruments is generally classified within Level 1 of the fair value hierarchy. The fair value of real estate investments is measured primarily using a comparative method of assessment based on observable market value of similar real estate. Consequently, the fair value of real estate investments is generally classified within Level 2 of the fair value hierarchy.

Over 70% of the plan assets are invested in fixed income investments, the majority of which are Brazilian Federal Public Bonds. These government bonds are referenced to an inflation index, which effectively minimize plan risk.

The projected benefit obligation, accumulated benefit obligation, fair value of plan assets, and related balance sheet accounts for Elektro’s pension plans are as follows:


	December 31,
	2009		2008
	Millions of dollars (U.S.)
Projected benefit obligation	$	332	$	224
Accumulated benefit obligation		313		213
Fair value of plan assets		433		292
Prepaid pension asset		101		68

F-48

The Company uses a year-end measurement date for its plans. Elektro recorded other comprehensive income of $5 million (net of tax of $1 million) and $33 million (net of tax of $17 million) as of December 31, 2009 and 2008, respectively.

The changes in projected benefit obligation, changes in the fair value of plan assets, and the funded status of the plans are as follows:


	December 31,
	2009			2008
	Millions in dollars (U.S.)
Change in projected benefit obligation:
Benefit obligation, beginning of period	$	224		$	307
Service cost		5			4
Interest cost		35			32
Actuarial gains (losses)		(26	)		32
Benefits paid		(16	)		(15	)
Effect of foreign exchange rate change		74			(69	)
Change in assumptions		36			(67	)

Benefit obligation — end of period	$	332		$	224

Change in plan assets:
Fair value of plan assets, beginning of period	$	292		$	325
Actual return on plan assets		55			72
Contributions by employer		1			1
Contributions by plan participants		1			1
Benefits paid		(16	)		(15	)
Effect of foreign exchange rate change		100			(92	)

Fair value of plan assets — end of period	$	433		$	292

Funded status at end of year	$	101		$	68

Amounts recognized on the balance sheet — prepaid pension asset	$	101		$	68

Net amount recognized at end of year	$	101		$	68

The components of net periodic (benefit) cost are as follows:


	For the Years Ended December 31,
	2009			2008			2007
	Millions of dollars (U.S.)
Service cost	$	5		$	4		$	3
Interest cost		35			32			31
Recognized net actuarial gains		(4	)		—			—
Expected employee contribution		(1	)		(2	)		(2	)
Expected return on plan assets for the period		(51	)		(38	)		(33	)

Total net periodic pension benefit	$	(16	)	$	(4	)	$	(1	)

Projected benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The actuarial assumptions as of December 31, 2009, 2008 and 2007, are as follows:


	2009						2008						2007
				Periodic						Periodic						Periodic
	Benefit			Pension			Benefit			Pension			Benefit			Pension
	Obligation			Cost			Obligation			Cost			Obligation			Cost
Weighted-average of discount rates		11.40	%		12.37	%		12.37	%		12.37	%		10.24	%		10.24	%
Weighted-average rates of compensation increase		7.63	%		7.63	%		7.63	%		7.63	%		7.12	%		7.12	%
Weighted-average expected long-term rate of return on plan assets					13.29	%					13.29	%					11.28	%

The basis used to determine the expected long-term rate of return on assets were: (i) assets allocations (ii) forward rates for long-term government bonds and (iii) expected return on each asset category, as determined by the pension fund managers through historical experience and current market conditions.

F-49

The following table summarizes the scheduled cash flows for U.S. and foreign expected employer contributions and expected future benefit payments:


	Millions of
	dollars (U.S.)
Expected employer contribution in 2010	$	2
Expected benefit payments:
2010		16
2011		18
2012		20
2013		22
2014		24
2015 — 2018		168

25. COMMITMENTS AND CONTINGENCIES

The Company’s future minimum commitments as of December 31, 2009, are as follows:


	2010		2011		2012		2013		2014		Thereafter		Total
	Millions of dollars (U.S.)
Power commitments(a)	$	1,166	$	1,234	$	1,272	$	1,197	$	1,058	$	13,505	$	19,432
Fuel commitments(b)		1,722		463		481		292		298		1,656		4,912
Equipment commitments(c)		9		3		2		12		17		103		146
Transportation commitments(d)		79		81		84		86		89		735		1,154
Other commitments		9		4		1		1		—		1		16

Total	$	2,985	$	1,785	$	1,840	$	1,588	$	1,462	$	16,000	$	25,660


(a)		Represents take-or-pay and other commitments to purchase power of various quantities from third parties. Power purchases under long-term commitments for the year ended December 31, 2009, 2008 and 2007 totaled $1.07 billion, $716 million and $917 million, respectively.

(b)		Represents take-or-pay and other commitments to purchase fuel of various quantities from third parties. Fuel purchases under long-term commitments for the year ended December 31, 2009, 2008 and 2007 totaled $539 million, $541 million and $425 million, respectively.

(c)		Represents commitments of various duration for parts and maintenance services provided by third parties, which are expensed during the year of service.

(d)		Represents a commitment to purchase gas transportation services from an unconsolidated affiliate and third parties.

Letters of Credit — In the normal course of business, AEI and its subsidiaries enter into various agreements requiring them to provide financial or performance assurance to third parties. Such agreements include guarantees, letters of credit, and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish the subsidiaries’ intended business purpose. As of December 31, 2009, AEI and certain of its subsidiaries had entered into letters of credit, bank guarantees, and performance bonds with balances of $379 million issued of which $11 million of the total facility balances were fully cash collateralized. Additionally, as of December 31, 2009, lines of credit of $416 million were outstanding, with an additional $532 million available.

Under the Equity Guarantee Agreement, AEI on behalf of Accroven is obligated to provide, or cause to be provided, all performance bonds in the form of letters of credit, required under the service agreement between Accroven and its customer, Petróleos de Venezuela Gas, S.A. (“PDVSA”). In February 2006, AEI’s board of directors approved the execution of a reimbursement agreement with a bank to issue four letters of credit totaling approximately $21 million, which is also included in amounts above. Accroven is required to reimburse AEI for any payment made in connection with the letters of credit, subject to the consent of Accroven’s lender and approval by the Accroven shareholders. The letters of credit were cancelled by written notice delivered by the issuing bank to PDVSA Gas at the beginning of August with an expiration date as of August 31, 2009. However, a waiver of the requirement to have the letters of credit in place was granted by PDVSA Gas to Accroven. This waiver expired on January 31, 2010 and as a consequence, Accroven is in default under the service agreement and AEI is in default under the Equity Guarantee Agreement. On September 11, 2009, AEI signed a non-binding Letter of Intent (“LOI”) with PDVSA Gas pursuant to which AEI agreed to transfer its interest in Accroven to PDVSA Gas. After several extensions, the LOI expired on November 30, 2009, but negotiations to consummate the transaction are continuing.

F-50

Political Matters:

Turkey — Since November 2002, Trakya and other Turkish BOT projects have been under pressure from the Turkish Ministry of Energy and Natural Resources to renegotiate their current contracts. The primary aim of the Ministry is to reduce what it views as excess returns paid to the projects by the State Wholesale Electricity and Trading Company under the existing PPAs. AEI and the other shareholders of Trakya developed a proposal and presented it to the Ministry in April 2006. The Ministry has not formally responded to the proposal. The Company does not believe that the currently expected outcome under the proposed restructuring will have a material adverse effect on its financial condition, results of operations or liquidity.

Poland — The Polish government has been working on restructuring the Polish electric energy market since the beginning of 2000 in an effort to introduce a competitive market in compliance with European Union legislation. In 2007, legislation was passed in Poland that allowed for power generators producing under long-term contracts to voluntarily terminate their contracts and receive compensation for certain stranded costs. The compensation system consists of stranded costs compensation (which applies to certain capital expenditures incurred before December 31, 2004 which could not be recovered from future sales in the free market) and additional gas fuel cost compensation. Both forms of compensation are paid in quarterly installments of varying amounts. The compensation payments to ENS commenced in August 2008. ENS received $18 million of stranded-cost compensation in 2008 and $50 million in stranded-cost compensation and fuel gas compensation in 2009. The maximum remaining compensation for stranded-cost and gas fuel cost payable to ENS is 922 million Polish zloty (approximately U.S. $324 million based on the exchange rate as of December 31, 2009).

Venezuela — Accroven — Venezuela has nationalized a significant part of its hydrocarbon and electricity industries and changed its operation agreements to joint ventures with the state-owned oil company PDVSA (the only client of Accroven). On September 11, 2009, the Company signed a non-binding Letter of Intent with PDVSA Gas, S.A. (PDVSA Gas), pursuant to which the Company agreed to transfer its interest in Accroven to PDVSA Gas. On October 30, 2009, the Letter of Intent was amended to extend the termination date to November 30, 2009. The Letter of Intent has expired, but negotiations to consummate the transaction are continuing.

Litigation/Arbitration:

AEI holds $201 million principal amount of notes of CIESA, which are in default. AEI was previously party to a restructuring agreement with CIESA pursuant to which this debt was to be exchanged for equity of CIESA upon receipt of all required government approvals. After having granted two extensions, those approvals were not obtained and accordingly, in January 2009, AEI terminated the restructuring agreement. Following the termination, CIESA filed a complaint against AEI in New York state court seeking a judgment declaring that any claim by AEI against CIESA with respect to this debt is time-barred because the statute of limitations pertaining to any such claim had expired. CIESA subsequently amended its complaint to also include an allegation that AEI’s termination of its restructuring agreement was in breach of that agreement. AEI does not believe that there is any merit to the suit and is vigorously defending the claim. Separately, in February 2009, AEI filed a petition in Argentina for the involuntary bankruptcy liquidation of CIESA. In July 2009, the Argentine court ruled that if CIESA did not cure its insolvency status within 20 days of AEI serving this decision on CIESA, CIESA would be put into bankruptcy. AEI served this decision on CIESA on July 31, 2009. In August 2009, CIESA appealed the bankruptcy court’s decision. On October 9, 2009, the appellate court overturned the bankruptcy court’s decision, rejecting AEI’s petition. This decision did not rule on the enforceability of the debt. On October 14, 2009, AEI filed a motion to annul the appellate court’s decision. This motion was denied on December 28, 2009. AEI continues to believe that it has a strong case and is considering several alternatives in order to pursue its rights.

AEI’s subsidiaries are involved in a number of legal proceedings, mostly civil, regulatory, contractual, tax, labor, and personal injury claims and suits, in the normal course of business. As of December 31, 2009, we have accrued liabilities totaling approximately $117 million for claims and suits, as recorded in accrued liabilities and other liabilities. This amount has been determined based on management’s assessment of the ultimate outcomes of the particular cases, and based on its general experience with these particular types of cases. Although the ultimate outcome of such matters cannot be predicted with certainty, AEI accrues for contingencies associated with litigation when a loss is probable and the amount of the loss is reasonably estimable. AEI does not believe, taking into account reserves for estimated liabilities, that the currently expected outcome of these proceedings will have a material adverse effect on AEI’s financial position, results of operations or liquidity. It is possible, however, that some matters could be decided in a manner that AEI could be required to pay damages or to make expenditures in amounts materially in excess of that recorded, but cannot be estimated at December 31, 2009.

F-51

Elektro — Elektro is a party to approximately 6,000 lawsuits. The nature of these suits can generally be described in three categories, namely civil, tax and labor. Civil cases include suits involving the suspension of power to non-paying customers, real estate issues, suits involving workers or the public that allegedly suffer property damage or injury in connection with Elektro’s facilities and power lines, and suits contesting the privatization of Elektro, which occurred in 1998. Tax cases include suits with the tax authorities over appropriate methodologies for calculating value-added tax, social security contributions, social integration tax, income tax and provisional financial transaction tax. Labor suits include various issues, such as labor accidents, overtime calculations, vacation issues, hazardous work and severance payments. As of December 31, 2009, Elektro has accrued approximately $19 million related to these cases, excluding those described below.

In July 1998, two separate class actions were filed against Elektro and others. Each of these actions seeks the annulment of the privatization of Elektro and alleges, among other things, that the price paid for Elektro was unacceptably low. These cases are currently pending. Elektro believes that it has solid legal grounds on which to have each of the cases dismissed.

In August 2001, Elektro filed two lawsuits against the State Highway Department — DER (the State of Sāo Paulo’s regulatory authority responsible for control, construction and maintenance of the majority of the roads in the state) and other private highway concessionaires aiming to be released from paying certain fees in connection with the construction and maintenance of Elektro’s power lines and infrastructure in the properties belonging to or under the control of the DER and such concessionaires. The lower court and the State Court ruled in favor of the DER. Elektro appealed to the Superior Court and filed an injunction in August 2008 to suspend the decision of the State Court. In November 2008, the injunction was denied by one of the Superior Court Ministers. The Superior Court has not yet ruled on the appeal.

In December 2007, Elektro received two tax assessments issued by the Brazilian Internal Revenue Service (IRS). The first assessment alleges that Elektro is required to pay additional corporate income tax (IRPJ) and income contribution (CSLL) with respect to tax periods 2002 to 2006 and the other alleging that Elektro is required to pay additional social contribution on earnings (PIS and COFINS), with respect to tax periods June and July 2005. The assessments allege approximately $279 million (based on the exchange rate as of December 31, 2009) is due related to the tax periods involved. In June 2008, Elektro was notified that an administrative ruling was rendered on these matters that would fully cancel both tax assessments. The ruling is subject to an automatic review by the Administrative Court of Appeal, but Elektro believes that it is likely that the ruling will be confirmed.

In December 2006, the Brazilian National Social Security Institute notified Elektro about several labor and pension issues raised during a two-year inspection, which took place between 2004 and 2006. A penalty was issued to Elektro in the amount of approximately $35 million (based on the exchange rate as of December 31, 2009) for the assessment period from 1998 to 2006. Based upon a Brazilian Federal Supreme Court precedent issued during the second quarter of 2008 regarding the statute of limitations for this type of claim, Elektro believes that a portion of the amount claimed is now time-barred by the statute of limitations. Elektro is in the initial stage of presenting its administrative defense and, therefore, cannot determine the amount of any potential loss at this time.

Elektro has three separate ongoing lawsuits against the Brazilian Federal Tax Authority in each of the Brazilian federal, superior and supreme courts relating to the calculation of the social contribution on revenue and the contribution to the social integration program. These cases are currently pending. Elektro had made a judicial deposit of approximately $24 million (based on the exchange rate as of December 31, 2009) related to this issue. In May 2009, a newly enacted Brazilian law revoked a previous law which resulted in a change to the method by which such contributions should be calculated. Due to the revocation and pursuant to a technical notice issued by IBRACON (the local accounting standards board), in the second quarter of 2009, Elektro reversed a provision associated with the social contributions accruals made prior to 2004. However, the $24 million judicial deposit made by Elektro will not be released until the final decision by the Supreme Court on the appeal is made.

In March 2007, the Federal Labor District Attorney in Brazil filed a public lawsuit against Elektro seeking to prohibit the company from using contractors for certain of its core business activities. The District Attorney claimed that workers who render services for Elektro should be directly hired by the company rather than by a third party. In June 2009, the court ruled in favor of the Federal Labor District Attorney. Elektro believes that it has reasonable arguments on which to challenge this decision and has filed an appeal with the Regional Labor Court. This appeal is currently pending.

F-52

In December 2008, Elektro received a tax assessment from the São Paulo State Treasury claiming Elektro owed ICMS (Value Added Tax) of approximately $27 million (based on the exchange rate as of December 31, 2009). Elektro contested the assessment and the administrative tribunal hearing the matter ruled against Elektro. Elektro has appealed the tribunal’s ruling to the Tax Payer Council. Elektro believes that it has good legal grounds on which to dispute this claim.

EPE — On October 1, 2007, EPE received a notice from Furnas purporting to terminate the PPA as a result of the lack of gas supply from Bolivia. EPE initiated an arbitration proceeding in Brazil on the basis that there was no contractual basis for Furnas to terminate the PPA. In 2008, EPE amended its initial pleadings and requested the termination of the PPA based on Furnas’ failure to make capacity payments. The tribunal accepted the amendment of EPE’s pleadings in the first quarter of 2009. On October 20, 2009, the arbitrators determined that the PPA was terminated due to the occurrence of a force majeure event. In January 2010, each of EPE and Furnas submitted to the arbitration tribunal their assessment of the damages and losses suffered by them as a result of the force majeure event. There is no assurance that the arbitral tribunal will award damages to EPE or that it will not award damages to Furnas. In the event that EPE is not adequately compensated for such damages and losses, or if it is compelled to pay damages to Furnas, the operations of Cuiabá will be materially adversely affected, with a corresponding negative impact on the Company’s financial performance and cash flows.

San Felipe Limited Partnership — Under San Felipe’s PPA, CDEEE and the Dominican Republic Government have an obligation to perform all necessary steps in order to obtain a tax exemption for San Felipe. As of December 31, 2009, neither CDEEE nor the executive branch has obtained this legislative exemption. In February 2002, the local tax authorities notified San Felipe of a request for tax payment for a total of DOP 716 million (equivalent to approximately $20 million at the exchange rate as of December 31, 2009) of unpaid taxes from January 1998 through June 2001. San Felipe filed an appeal against the request which was rejected by the local tax authorities. In July 2002, San Felipe filed a second appeal before the corresponding administrative body which was rejected in June 2008. In July 2008, San Felipe appealed this ruling before the Tax and Administrative Court. San Felipe has accrued approximately $72 million as of December 31, 2009 with respect to the period from January 1998 through December 31, 2009 which management believes is adequate. In addition, San Felipe has a contractual right under its PPA to claim indemnification from CDEEE for taxes paid by San Felipe.

DCL — DCL entered commercial operations on April 17, 2008. In September 2008, DCL shut down the plant on the recommendation of Siemens AG, or Siemens, the manufacturer of DCL’s gas turbine, due to vibrations. As a result of the shutdown, DCL stopped generating revenues and cash inflows to pay vendors, which delayed the repairs. In January 2009, DCL received notice of default from one of its senior lenders. Shortly thereafter, two of DCL’s senior lenders filed claims against DCL and Sacoden, which holds AEI’s interest in DCL, in the courts of Sindh Province, Pakistan seeking repayment by DCL of loans totaling PKR 3,704 million (equivalent to approximately $46 million at the exchange rate as of December 31, 2009). The lenders petitioned the courts to force a sale of all of DCL’s assets and all of Sacoden’s shares in DCL and to replace DCL’s directors and officers with a court appointed administrator. DCL and Sacoden filed responses to these claims. In June 2009, DCL entered into loan agreements with its senior lenders and Sacoden pursuant to which the senior lenders and Sacoden made loans to DCL to fund its rehabilitation efforts. In connection with these loan agreements, DCL and Sacoden entered into a Standstill Agreement with the senior lenders pursuant to which the parties agreed to refrain from taking legal actions against each other while DCL rehabilitates the plant and negotiates a new PPA. The Standstill Agreement has now expired.

After completing a Reliability Run Test, DCL returned to commercial operation in the middle of October 2009. In early November 2009, due to a sudden and drastic frequency drop in the grid which overloaded the DCL generator, DCL’s turbine tripped on surge protection and the plant was shut down for repairs. The repairs have been completed and DCL resumed commercial operations in February 2010.

DCL was party to a PPA with Karachi Electric Supply Corporation, or KESC, for the sale of all of the plant’s output of power, which was terminated by KESC in April 2009. Subsequently, the parties entered into discussion and arrived at an interim PPA arrangement. DCL is also in discussions with KESC with respect to a new power PPA and will sell power to KESC on the said interim arrangement while the new PPA is negotiated.

F-53

If DCL is unable to enter into an acceptable PPA, the operations of DCL may be materially adversely affected or the lenders may exercise their right to take ownership of the plant, in either event with a corresponding negative impact on our financial performance and cash flows.

26. SEGMENT AND GEOGRAPHIC INFORMATION

The Company manages, operates and owns interests in energy infrastructure businesses through a diversified portfolio of companies worldwide. It conducts operations through global businesses, which are aggregated into reportable segments based primarily on the nature of its service and customers, the operation and production processes, cost structure, channels of distribution and regulatory environment. The operating segments reported below are the segments of the Company for which separate financial data is available and for which operating results are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The Company uses both revenue and operating income as key measures to evaluate the performance of its segments. Segment revenue includes inter-segment sales. Operating income is defined as total revenue less cost of sales (including depreciation and amortization) and operating expenses (including taxes other than income and losses on disposition of assets). Operating income also includes equity in earnings of unconsolidated affiliates due to the nature of operations in these affiliates.

Power Distribution — This segment delivers electricity to retail customers in their respective service areas. Each of these businesses operates exclusively in a designated service area based on a concession agreement. Under the majority of the concession agreements, the electric distribution companies are entitled to a full pass-through of noncontrollable costs, including purchased power costs. Tariffs are reviewed by the regulator periodically and adjusted to ensure that the concessionaire is able to recover reasonable costs. These businesses operate and maintain an electric distribution network under the concession, and bill customers directly via consumption and/or demand charges.

Power Generation — This segment generates and sells wholesale power primarily to large off-takers, such as distribution companies. Each of the businesses in this segment sells substantially all of its generating capacity under long-term contracts primarily to state-owned entities. These businesses use different types of fuel (hydro, natural gas, and liquid fuel) and different technologies (turbines and internal combustion engines) to convert the fuel to electricity. Generally, off-take agreements are structured to minimize business exposure to commodity fuel price volatility.

Natural Gas Transportation and Services — This segment provides transportation and related services for upstream oil and gas producers and downstream utilities and other large users who contract for capacity. Each of these businesses owns and operates pipeline, compression and/or liquids removal and processing equipment associated with the transportation or handling of large quantities of gas. The rates charged by these businesses are typically regulated or controlled by a government entity.

Natural Gas Distribution — This segment is involved in the distribution and sale of natural gas to retail customers. Each of these businesses operates a network of gas pipelines, delivers gas directly to a large number of residential, industrial and commercial customers, and directly bills these customers for connections and volumes of gas provided. These businesses are regulated and typically operate on long-term concessions giving them an exclusive right to deliver gas in a designated service area.

Retail Fuel — This segment distributes and sells gasoline, LPG and compressed natural gas (“CNG”). These businesses service both owned and affiliated retail outlets.

Headquarters and Other — Expenses include corporate interest, general and administrative expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources, information systems and incentive compensation, and certain businesses which are immaterial for the purposes of separate segment disclosure.

F-54

Eliminations — The eliminating transactions between segments include certain generation facilities, on one side, and distributors and gas services on the other, and intercompany interest and management fee arrangements between the operating segments and the Parent Company.


As of and for the Year	Power		Power		Nat. Gas.		Nat. Gas.		Retail		Headquarters and
Ended December 31, 2009	Dist.		Gen.		Trans.		Dist.		Fuel		Other			Eliminations			Total
	Millions of dollars (U.S.)
Revenues	$	2,151	$	1,027	$	197	$	654	$	4,245	$	27		$	(116	)	$	8,185
Equity income from unconsolidated affiliates		64		3		30		14		2		(2	)		(4	)		107
Operating income		413		99		32		128		140		(77	)		(4	)		731
Interest income		46		15		5		2		6		1			(1	)		74
Interest expense		93		57		41		17		52		105			(38	)		327
Depreciation and amortization		134		42		21		23		46		6			—			272
Capital expenditures		189		19		31		103		87		12			—			441
Equity method investments in unconsolidated affiliates		778		108		118		24		17		—			—			1,045
Goodwill		55		45		26		160		362		15			—			663
Long lived assets		3,307		1,272		725		1,008		992		3,082			(2,776	)		7,610
Total assets		4,447		2,269		1,018		1,410		1,535		2,948			(3,402	)		10,225


As of and for the Year Ended	Power		Power		Nat. Gas.		Nat. Gas.		Retail		Headquarters and
December 31, 2008	Dist.		Gen.		Trans.		Dist.		Fuel		Other			Eliminations			Total
	Millions of dollars (U.S.)
Revenues	$	2,217	$	1,175	$	202	$	584	$	5,137	$	22		$	(126	)	$	9,211
Equity income from unconsolidated affiliates		68		12		27		11		1		—			(2	)		117
Operating income		427		15		128		104		218		(36	)		(43	)		813
Interest income		54		14		6		2		9		3			—			88
Interest expense		134		45		44		19		53		136			(53	)		378
Depreciation and amortization		138		24		21		18		61		6			—			268
Capital expenditures		183		16		12		61		86		14			—			372
Equity method investments in unconsolidated affiliates		628		65		35		23		8		—			—			759
Goodwill		53		54		26		144		323		14			—			614
Long lived assets		2,598		1,300		701		832		841		2,491			(2,392	)		6,371
Total assets		3,304		1,897		924		1,110		1,323		3,865			(3,470	)		8,953


As of and for the Year Ended	Power		Power		Nat. Gas.		Nat. Gas.		Retail		Headquarters and
December 31, 2007	Dist.		Gen.		Trans.		Dist.		Fuel		Other		Eliminations			Total
	Millions of dollars (U.S.)
Revenues	$	1,746	$	874	$	199	$	352	$	160	$	19	$	(134	)	$	3,216
Equity income from unconsolidated affiliates		2		11		39		13		11		—		—			76
Operating income		373		77		128		85		49		286		(421	)		577
Interest income		58		27		7		2		2		14		—			110
Interest expense		90		41		42		14		12		143		(36	)		306
Depreciation and amortization		139		42		20		8		3		5		—			217
Capital expenditures		168		3		9		24		37		8		—			249
Equity method investments in unconsolidated affiliates		698		14		106		26		38		—		—			882
Goodwill		53		33		27		117		158		14		—			402
Total assets		3,732		1,433		1,138		913		384		4,170		(3,917	)		7,853

F-55

The table below present revenues and operating income of the Company’s consolidated subsidiaries by significant geographical location for the year ended December 31, 2009, 2008 and 2007. Revenues are recorded in the country in which they are earned and assets are recorded in the country in which they are located. Intercompany revenues between countries have been eliminated in Other and eliminations below.


	Revenues									Operating Income
	For the Years Ended December 31,									For the Years Ended December 31,
	2009			2008			2007			2009			2008			2007
	Millions of dollars (U.S.)
Andean

Colombia	$	3,603		$	3,926		$	563		$	315		$	371		$	198
Chile		907			1,311			—			71			68			—
Other countries		248			219			37			29			28			20

Subtotal		4,758			5,456			600			415			467			218

Southern Cone
Brazil		1,418			1,503			1,406			168			185			220
Argentina		173			122			52			29			14			8
Other countries		17			21			21			(27	)		17			32

Subtotal		1,608			1,646			1,479			170			216			260

Central America/Caribbean
Panama		602			808			389			44			44			57
El Salvador		214			172			97			12			12			8
Guatemala		193			206			168			36			23			42
Other countries		319			384			177			72			21			25

Subtotal		1,328			1,570			831			164			100			132

Europe/Middle East/North Africa
Turkey		357			416			337			59			24			46
Other countries		103			123			93			(1	)		30			16

Subtotal		460			539			430			58			54			62

China		151			104			8			11			(19	)		(6	)

Other and eliminations		(120	)		(104	)		(132	)		(87	)		(5	)		(89	)

Total	$	8,185		$	9,211		$	3,216		$	731		$	813		$	577

27. SUBSEQUENT EVENTS

In March 2010, the Company acquired the additional 30% ownership interest in BMG in exchange for $32 million in cash and a 5% ownership interest in Tongda. In connection with this transaction, the Company formed a new company, Huatong, which will hold and manage all of the natural gas distribution businesses in China, including those businesses held in Tongda. Following the closing of this acquisition, the Company will own 95% of Huatong and the remaining ownership interest will be owned by our current partner in BMG. The Company is in the process of obtaining the required governmental and regulatory approvals.

In March 2010, the Company through its wholly-owned subsidiary Jaguar, entered into a $350 million 10-year construction and term loan facility with a syndicate of regional and international banks and issued a notice to commence under the engineering, procurement and construction contract. Funding under the facility is subject to the satisfaction of various conditions, including a minimum equity contribution and the issuance of a parent guarantee by AEI. AEI has no direct obligations under the facility until the guarantee is signed and funding under the facility commences. Jaguar also has the ability to cancel the facility commitment at any time prior to the satisfaction of these conditions and the drawing of funds.

F-56

Item 19. Exhibits

In reviewing the agreements included as exhibits to this annual report on Form 20-F, please remember they are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

	•		should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

	•		have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

	•		may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors; and

	•		were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. Additional information about us may be found elsewhere in this annual report on Form 20-F and in our future public filings, which will be made available without charge through the SEC’s website at http://www.sec.gov.


Exhibit No.		Description
1.1*		Amended and Restated Articles of Association of AEI dated December 20, 2007.
1.2*		Amended and Restated Memorandum of Association of AEI dated December 20, 2007.
2.1*		Amended and Restated Registration Rights Agreement by and among AEI and certain Investors dated December 29, 2006.
4.1**		Amended and Restated Credit Agreement, dated as of June 6, 2008, among AEI, AEI Finance Holding LLC, various financial institutions as lenders, Credit Suisse, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Credit Suisse Securities (USA) LLC and J.P. Morgan Securities, Inc.
4.2		AEI 2007 Incentive Plan, as amended and restated on December 14, 2009.
4.3*		Concession Contract No. 187/98, dated August 27, 1998, between ANEEL and Elektro Eletricidade e Servicos S.A., as amended.
4.4*		Distribution First Amendment to Concession Contract No. 187/98, dated December 14, 1999, between ANEEL and Elektro Electricidade e Servicos S.A.
4.5*		Distribution Second Amendment to Concession Contract No. 187/98, dated July 12, 2005 between ANEEL and Elektro Electricidade e Servicos S.A.
4.6*		Distribution Third Amendment to Concession Contract No. 187/98, dated December 18, 2007, between ANEEL and Elektro Eletricidade e Servicos S.A.
4.7		Distribution Fourth Amendment to Concession Contract No. 187/98, dated March 4, 2010 between ANEEL and Elektro Electricidade e Servicos S.A.
4.8*		Second Amended and Restated Shareholders Agreement, dated May 9, 2008, among AEI and the shareholders of AEI identified therein.
4.9		Amendment to the Second Amended and Restated Shareholders Agreement, dated as of October 29, 2009.
4.10		Form of Indemnification Agreement, dated as of January 1, 2010, by and between AEI and the officer or director of AEI.

-133-


Exhibit No.		Description
8.1		List of Subsidiaries of AEI.
12.1		Certification of James Hughes, Chief Executive Officer (Principal Executive Officer) of AEI, pursuant to 15 U.S.C. Section 78(m)(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
12.2		Certification of Eduardo Pawluszek, EVP, Chief Financial Officer (Principal Financial Officer) of AEI, pursuant to 15 U.S.C. Section 78(m)(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
13.1		Certification of James Hughes, Chief Executive Officer (Principal Executive Officer) of AEI, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2		Certification of Eduardo Pawluszek, EVP, Chief Financial Officer (Principal Financial Officer) of AEI, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Previously filed as an exhibit to the Company’s registration statement on Form 20-F (File No. 000-53606) filed with the SEC on March 27, 2009 and incorporated herein by reference.

**		Previously filed as an exhibit to the Company’s annual report on Form 20-F (File No. 000-53606) filed with the SEC on June 17, 2009 and incorporated herein by reference.

-134-

ANNEX I

Proportional Financial Metrics⁽¹⁾
As of and for the Year Ended December 31, 2009
Unaudited


														Add Proportional		Proportional
								Deduct						Adjusted		Share of						Proportional
								Noncontrolling			Deduct Equity			EBITDA —		Adjusted			Net Debt			Share of
	Operating	AEI Ownership			AEI Consolidated			Interest			(Income)			Equity/Cost		EBITDA			as of			Net Debt
Business	Segment	% at 12/31/09			Adjusted EBITDA⁽²⁾			Share⁽³⁾			Loss⁽⁴⁾			Investments⁽⁴⁾		2009			12/31/09⁽⁵⁾			12/31/09⁽⁵⁾
(In millions of $, except for ownership percentages)
As of and for the year ended December 31, 2009
Delsur	Power Distribution		86.41	%	$	24		$	(3	)	$	—		$	—	$	21		$	52		$	45
EDEN	Power Distribution		90.00	%		24			(2	)		—			—		22			(16	)		(14	)
Elektra	Power Distribution		51.00	%		54			(26	)		—			—		28			113			58
Elektro	Power Distribution		99.68	%		392			(1	)		—			—		391			399			398
EMDERSA	Power Distribution		77.10	%		11			(2	)		—			—		9			57			44
Chilquinta	Power Distribution		50.00	%		15			—			(15	)		57		57			263			132
Luz del Sur	Power Distribution		37.97	%		38			—			(38	)		71		71			225			85
Emgasud	Power Generation		42.73	%		(2	)		—			2			8		8			134			57
ENS	Power Generation		100.00	%		32			—			—			—		32			56			56
PQP	Power Generation		100.00	%		44			—			—			—		44			47			47
San Felipe	Power Generation		100.00	%		50			—			—			—		50			(15	)		(15	)
Trakya	Power Generation		90.00	%		75			(8	)		—			—		67			(34	)		(31	)
Luoyang	Power Generation		50.00	%		6			(3	)		—			—		3			117			59
DCL	Power Generation		60.23	%		(3	)		1			—			—		(2	)		78			47
Accroven	Natural Gas Transportation and Services		49.25	%		18			—			(18	)		36		36			134			66
GTB	Natural Gas Transportation and Services		34.65	%⁽⁶⁾		8			—			(8	)		16		16			248			86
TBG	Natural Gas Transportation and Services		8.27	%⁽⁶⁾		—			—			—			13		13			196			16
Cuiabá	Natural Gas Transportation and Services		100.00	%⁽⁶⁾		(30	)		15			—			—		(15	)		(73	)		(73	)
Promigas Pipeline	Natural Gas Transportation and Services		52.13	%		62			(30	)		—			—		32			288			150
Promigas — Gases de Occidente	Natural Gas Distribution		46.87	%		59			(31	)		—			—		28			55			26
Promigas — Gases del Caribe	Natural Gas Distribution		16.16	%		13			—			(13	)		13		13			153			25
Cálidda	Natural Gas Distribution		80.85	%		20			(4	)		—			—		16			8			6
Promigas — Surtigas	Natural Gas Distribution		51.58	%		38			(19	)		—			—		19			75			39
China	Natural Gas Distribution		⁽⁷⁾			22			(5	)		—			—		17			(11	)		(12	)
Proenergia — SIE	Retail Fuel		27.45	%		142			(103	)		—			—		39			394			108
Proenergia — GNC	Retail Fuel		24.40	%		45			(34	)		—			—		11			88			21
Other	Various Segments					49			(18	)		(9	)		9		31			67			(23	)

SUBTOTAL (Excluding Headquarters and Other)					$	1,206		$	(273	)	$	(99	)	$	223	$	1,057					$	1,403
Headquarters and Other	Headquarters		100.00	%		(60	)		—			(8	)		—		(68	)		1,275			1,275

TOTAL					$	1,146		$	(273	)	$	(107	)	$	223	$	989					$	2,678


⁽¹⁾		The following table sets forth unaudited proportional metrics by business for AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

⁽²⁾		See “Non-GAAP Financial Measures” for a definition of Adjusted EBITDA. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA.

⁽³⁾		Represents the noncontrolling interests share of consolidated Adjusted EBITDA calculated as 100% less the AEI ownership percentage as of December 31, 2009 multiplied by the 2009 Adjusted EBITDA for the business. See Annex II for a detailed reconciliation of the business’ net income to Adjusted EBITDA.

⁽⁴⁾		Represents the subtraction of equity income (loss) included in the consolidated Adjusted EBITDA for the business and the addition of the AEI’s share of the business’ Adjusted EBITDA. See Annex II for a detailed reconciliation of the business’ net income to Adjusted EBITDA.

⁽⁵⁾		See “Non-GAAP Financial Measures” for a definition of net debt. See “Selected Consolidated Financial Data” for a reconciliation of AEI debt to net debt. The net debt column represents 100% of net debt for the particular business. This column is multiplied by AEI’s ownership to calculate the proportional column.

⁽⁶⁾		Ownership percentages changed in December 2009, however, previous percentages were used to calculate proportional EBITDA.

⁽⁷⁾		Includes Tongda and BMG at ownership percentages of 100% and 70%, respectively.

A-1

ANNEX I

Proportional Financial Metrics⁽¹⁾
As of and for the year ended December 31, 2008 and 2007
Unaudited


														Add
														Proportional		Proportional
					AEI Consolidated			Deduct			Deduct Equity			EBITDA —		Share of						Proportional
	Operating	AEI Ownership			Adjusted			Noncontrolling			(Income)			Equity/Cost		Adjusted			Net Debt as of			Share of Net Debt
Business	Segment	% at 12/31/08			EBITDA⁽²⁾			Interest Share⁽³⁾			Loss⁽⁴⁾			Investments⁽⁴⁾		EBITDA 2008			12-31-2008⁽⁵⁾			12-31-2008⁽⁵⁾
(In millions of $, except for ownership percentages)
As of and for the year ended December 31, 2008
Delsur	Power Distribution		86.41	%	$	23		$	(3	)	$	—		$	—	$	20		$	67		$	58
EDEN	Power Distribution		90.00	%		18			(2	)		—			—		16			24			22
Elektra	Power Distribution		51.00	%		49			(24	)		—			—		25			119			60
Elektro	Power Distribution		99.68	%		427			(2	)		—			—		425			241			240
Chilquinta	Power Distribution		50.00	%		36			—			(36	)		57		57			160			80
Luz del Sur	Power Distribution		37.97	%		31			—			(31	)		67		67			211			80
Cuiabá — EPE	Power Generation		50.00	%		(46	)		23			—			—		(23	)		24			12
ENS	Power Generation		100.00	%		32			—			—			—		32			56			56
PQP	Power Generation		100.00	%		29			—			—			—		29			70			70
Subic	Power Generation		50.00	%		12			—			(12	)		14		14			(10	)		(5	)
Trakya	Power Generation		59.00	%		40			(16	)		—			—		24			(59	)		(35	)
Accroven	Natural Gas Transportation and Services		49.25	%		17			—			(17	)		40		40			138			68
GTB	Natural Gas Transportation and Services		17.65	%		1			—			(1	)		13		13			323			57
TBG	Natural Gas Transportation and Services		4.21	%		—			—			—			10		10			777			33
Cuiabá — GOB	Natural Gas Transportation and Services		50.00	%		16			(8	)		—			—		8			28			14
Cuiabá — GOM	Natural Gas Transportation and Services		50.00	%		20			(10	)		—			—		10			7			4
Promigas Pipeline	Natural Gas Transportation and Services		52.13	%		65			(31	)		—			—		34			177			93
Promigas — Gases de Occidente	Natural Gas Distribution		46.87	%		48			(26	)		—			—		22			61			29
Promigas — Gases del Caribe	Natural Gas Distribution		16.16	%		10			—			(10	)		13		13			117			19
Cálidda	Natural Gas Distribution		80.85	%		19			(4	)		—			—		15			47			38
Promigas — Surtigas	Natural Gas Distribution		52.08	%		38			(18	)		—			—		20			66			35
Promigas — SIE	Retail Fuel		28.13	%		162			(116	)		—			—		46			440			124
Promigas — GNC	Retail Fuel		24.96	%		48			(36	)		—			—		12			68			17
Other	Various Segments					39			(14	)		(9	)		7		23			298			115

SUBTOTAL (Excluding Headquarters and Other)					$	1,134		$		(287)	$	(116	)	$	221	$	952					$	1,284

Headquarters and Other			100.00	%		(90	)		—			—			—		(90	)		1,474			1,474

TOTAL					$	1,044		$	(287	)	$	(116	)	$	221	$	862					$	2,758

For the year ended December 31, 2007
TOTAL					$	823		$	(131	)	$	(77	)	$	247	$	862


⁽¹⁾		The following table sets forth unaudited proportional metrics by business for AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

⁽²⁾		See “Non-GAAP Financial Measures” for a definition of Adjusted EBITDA. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA.

⁽³⁾		Represents the noncontrolling interests share of consolidated Adjusted EBITDA calculated as 100% less the AEI ownership percentage as of December 31, 2008 multiplied by the 2008 Adjusted EBITDA for the business. See Annex II for a detailed reconciliation of the business’ net income to Adjusted EBITDA.

⁽⁴⁾		Represents the subtraction of equity income (loss) included in the consolidated Adjusted EBITDA for the business and the addition of the AEI’s share of the business’ Adjusted EBITDA. See Annex II for a detailed reconciliation of the business’ net income to Adjusted EBITDA. For the year ended December 31, 2007 we included the full year of proportional EBITDA for equity investments acquired during the year. Had we included only the proportional EBITDA from the date of acquisition, the proportional EBITDA would have been $766 million.

⁽⁵⁾		See “Non-GAAP Financial Measures” for a definition of net debt. See “Selected Consolidated Financial Data” for a reconciliation of AEI debt to net debt. The net debt column represents 100% of net debt for the particular business. This column is multiplied by AEI’s ownership to calculate the proportional column.

A-2

ANNEX II

Reconciliation of Non-GAAP Measures⁽¹⁾
As of and for Year Ended December 31, 2009
Unaudited


																									LUZ									SAN
	DELSUR			DCL			EDEN			ELEKTRA			ELEKTRO			EMDERSA			EMGASUD			CHILQUINTA			DEL SUR			ENS			PQP			FELIPE			TRAKYA
	(In millions of $, except for ownership percentages)
EBITDA CALCULATION:
Net Income (Loss) Attributable to AEI	$	1		$	(29	)	$	11		$	11		$	208		$	3		$	(6	)	$	40		$	75		$	21		$	20		$	58		$	23
Add back:
Depreciation and amortization		12			5			3			15			102			2			11			20			28			1			8			(4	)		16
Noncontrolling interests		1			(16	)		1			10			1			1			—			3			23			—			—			—			17
Provision (benefit) for income taxes		6			—			4			10			97			—			2			9			50			6			10			26			15
Interest expense		5			12			2			9			46			3			14			14			15			4			5			1			10

EBITDA		25			(28	)		21			55			454			9			21			86			191			32			43			81			81
Subtract:
Interest Income		—			—			—			1			38			—			1			9			4			—			—			6			6
Foreign currency transaction gain (loss), net		—			—			(2	)		—			3			(1	)		1			(16	)		—			—			—			—			—
Gain (loss) on disposition of assets		—			—			—			—			(21	)		—			—			—			—			—			—			—			—
Other charges		—			(25	)		—			—			—			—			—			—			—			—			—			—			—
Other income (expense), net		1			—			(1	)		—			42			(1	)		1			(20	)		1			—			(1	)		25			—

ADJUSTED EBITDA⁽²⁾	$	24		$	(3	)	$	24		$	54		$	392		$	11		$	18		$	113		$	186		$	32		$	44		$	50		$	75
AEI Percentage Ownership		86.4	%		60.2	%		90.0	%		51.0	%		99.7	%		77.1	%		42.7	%		50.0	%		38.0	%		100.0	%		100.0	%		100.0	%		90.0	%
Proportional Share — Adjusted EBITDA	$	21		$	(2	)	$	22		$	28		$	391		$	9		$	8		$	57		$	71		$	32		$	44		$	50		$	67

NET DEBT CALCULATION:
Debt	$	65		$	79		$	3		$	119		$	617		$	62		$	136		$	267		$	232		$	62		$	71		$	—		$	80
Less: Cash		(10	)		(1	)		(19	)		(6	)		(174	)		(5	)		(2	)		(4	)		(7	)		(3	)		(20	)		(15	)		(114	)
Restricted cash — current		—			—			—			—			(4	)		—			—			—			—			(3	)		(4	)		—			—
Restricted cash — non-current		(3	)		—			—			—			(40	)		—			—			—			—			—			—			—			—

NET DEBT⁽²⁾	$	52		$	78		$	(16	)	$	113		$	399		$	57		$	134		$	263		$	225		$	56		$	47		$	(15	)	$	(34	)

Proportional Share — NET DEBT	$	45		$	47		$	(14	)	$	58		$	398		$	44		$	57		$	132		$	85		$	56		$	47		$	(15	)	$	(31	)


⁽¹⁾		The following table sets forth the reconciliation of net income to Adjusted EBITDA and debt to net debt, and calculation of the unaudited proportional metrics by business for certain of AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP measures and proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

⁽²⁾		See “Non-GAAP Financial Measures” for definitions of Adjusted EBITDA and net debt. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA and debt to net debt.

⁽³⁾		Ownership percentages changed in December 2009, however, previous ownership percentages were used to calculate proportional EBITDA.

⁽⁴⁾		Includes Tongda and BMG at ownership percentages of 100% and 70%, respectively.

A-3

Reconciliation of Non-GAAP Measures⁽¹⁾
As of and for year ended December 31, 2009 (cont’d)
Unaudited


																PROMIGAS			PROMIGAS			PROMIGAS						PROMIGAS						PROENERGIA			PROENERGIA
	LUOYANG			ACCROVEN			GTB⁽³⁾			TBG⁽³⁾			CUIABA⁽³⁾			PIPELINE			GDO			GDC			CALIDDA			SURTIGAS			CHINA⁽⁴⁾			SIE			GNC
	(In millions of $, except for ownership percentages)
EBITDA CALCULATION:
Net Income (Loss) Attributable to AEI	$	(6	)	$	28		$	37		$	299		$	(36	)	$	14		$	14		$	39		$	8		$	7		$	7		$	6		$	9
Add back:
Depreciation and amortization		7			23			18			55			11			14			4			4			7			3			9			35			11
Noncontrolling interests		(6	)		—			—			—			(132	)		10			18			3			—			11			5			39			9
Provision (benefit) for income taxes		2			6			16			155			9			9			16			23			3			10			1			30			10
Interest expense		9			15			24			62			27			27			4			16			4			8			1			43			9

EBITDA		6			72			95			571			(121	)		74			56			85			22			39			23			153			48
Subtract:
Interest Income		—			—			2			—			—			2			—			1			1			1			—			3			3
Foreign currency transaction gain (loss), net		—			(1	)		—			252			5			7			—			(1	)		1			—			1			9			—
Gain (loss) on disposition of assets		—			—			—			—			—			3			(2	)		—			—			—			—			—			—
Other charges		—			—			—			—			(96	)		—			—			—			—			—			—			—			—
Other income (expense), net		—			(1	)		—			—			—			—			(1	)		5			—			—			—			(1	)		—

ADJUSTED EBITDA⁽²⁾	$	6		$	74		$	93		$	319		$	(30	)	$	62		$	59		$	80		$	20		$	38		$	22		$	142		$	45
AEI Percentage Ownership		50.0	%		49.3	%		17.7	%		4.0	%		50.0	%		52.1	%		46.9	%		16.2	%		80.9	%		51.6	%					27.5	%		24.4	%
Proportional Share — Adjusted EBITDA	$	3		$	36		$	16		$	13		$	(15	)	$	32		$	28		$	13		$	16		$	19		$	17		$	39		$	11

NET DEBT CALCULATION:
Debt	$	119		$	138		$	273		$	346		$	—		$	313		$	78		$	164		$	27		$	90		$	34		$	486		$	96
Less: Cash		(2	)		(4	)		(25	)		(150	)		(17	)		(25	)		(23	)		(11	)		(16	)		(14	)		(45	)		(92	)		(7	)
Restricted cash — current		—			—			—			—			(49	)		—			—			—			(3	)		—			—			—			—
Restricted cash — non-current		—			—			—			—			(7	)		—			—			—			—			(1	)		—			—			(1	)

NET DEBT⁽²⁾	$	117		$	134		$	248		$	196		$	(73	)	$	288		$	55		$	153		$	8		$	75		$	(11	)	$	394		$	88

Proportional Share — NET DEBT	$	59		$	66		$	86		$	16		$	(73	)	$	150		$	26		$	25		$	6		$	39		$	(12	)	$	108		$	21


⁽¹⁾		The following table sets forth the reconciliation of net income to Adjusted EBITDA and debt to net debt, and calculation of the unaudited proportional metrics by business for certain of AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP measures and proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

⁽²⁾		See “Non-GAAP Financial Measures” for definitions of Adjusted EBITDA and net debt. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA and debt to net debt.

⁽³⁾		Ownership percentages changed in December 2009, however, previous ownership percentages were used to calculate proportional EBITDA.

⁽⁴⁾		Includes Tongda and BMG at ownership percentages of 100% and 70%, respectively.

A-4

ANNEX II

Reconciliation of Non-GAAP Measures⁽¹⁾
As of and for the year ended December 31, 2008
Unaudited


																LUZ			CUIABA
	DELSUR			EDEN			ELEKTRA			ELEKTRO			CHILQUINTA			DEL SUR			EPE			ENS			PQP			SUBIC			TRAKYA			ACCROVEN
	(In millions of $, except for ownership percentages)
EBITDA CALCULATION:
Net Income (Loss) Attributable to AEI	$	1		$	6		$	10		$	166		$	53		$	63		$	(63	)	$	35		$	13		$	17		$	(12	)	$	27
Add back:
Depreciation and amortization		11			3			13			110			24			36			1			2			5			10			16			23
Noncontrolling interests		2			1			8			1			3			19			(47	)		—									2
Provision (benefit) for income taxes		3			1			9			90			(25	)		43			3			(12	)		5			2			25			16
Interest expense		7			4			9			72			22			17			5			6			7			—			3			16
Loss from disposal of discontinued operations		—			—			—			—			47			—			—			—			—			—			—			—

EBITDA		24			15			49			439			124			178			(101	)		31			30			29			34			82
Subtract:
Interest Income		—			1			—			45			10			1			3			—			—			—			2			1
Foreign currency transaction gain (loss), net		—			(3	)		—			(2	)		(1	)		(1	)		(17	)		(1	)		—			—			(7	)
Gain (loss) on disposition of assets		—			—			—			(18	)		—			—			—			—			—			—			—			—
Other charges		—			—			—			—			—			—			(44	)		—			—			—			—			—
Other income (expense), net		1			(1	)		—			(13	)		1			2			3			—			1			2			(1	)		—

ADJUSTED EBITDA⁽²⁾	$	23		$	18		$	49		$	427		$	114		$	176		$	(46	)	$	32		$	29		$	27		$	40		$	81
AEI Ownership Percentage		86.4	%		90.0	%		51.0	%		99.7	%		50.0	%		38.0	%		50.0	%		100.0	%		100.0	%		50.0	%		59.0	%		49.3	%
Proportional Share — Adjusted EBITDA	$	20		$	16		$	25		$	425		$	57		$	67		$	(23	)	$	32		$	29		$	14		$	24		$	40

NET DEBT CALCULATION:
Debt	$	73		$	37		$	144		$	370		$	220		$	218		$	42		$	67		$	87		$	1		$	1		$	167
Less: Cash		(3	)		(13	)		(25	)		(93	)		(4	)		(7	)		(13	)		(8	)		(13	)		(11	)		(60	)		(8	)
Restricted cash — current		—			—			—			(7	)		(56	)		—			—			(3	)		(4	)		—			—			(21	)
Restricted cash — non-current		(3	)		—			—			(29	)		—			—			(5	)		—			—			—			—			—

NET DEBT⁽²⁾	$	67		$	24		$	119		$	241		$	160		$	211		$	24		$	56		$	70		$	(10	)	$	(59	)	$	138

Proportional Share — NET DEBT	$	58		$	22		$	61		$	240		$	80		$	80		$	12		$	56		$	70		$	(5	)	$	(35	)	$	68


⁽¹⁾		The following table sets forth the reconciliation of net income to Adjusted EBITDA and debt to net debt, and calculation of the unaudited proportional metrics by business for certain of AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP measures and proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

⁽²⁾		See “Non-GAAP Financial Measures” for definitions of Adjusted EBITDA and net debt. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA and debt to net debt.

A-5

Reconciliation of Non-GAAP Measures⁽¹⁾
As of and for the year ended December 31, 2008 (cont’d)
Unaudited


							CUIABA			CUIABA			PROMIGAS			PROMIGAS			PROMIGAS						PROMIGAS			PROMIGAS			PROMIGAS
	GTB			TBG			GOB			GOM			PIPELINE			GDO			GDC			CALIDDA			SURTIGAS			SIE			GNC
	(In millions of $, except for ownership percentages)
EBITDA CALCULATION:
Net Income (Loss) Attributable to AEI	$	19		$	235		$	3		$	9		$	2		$	8		$	44		$	6		$	7		$	(1	)	$	18
Add back:
Depreciation and amortization		—			—			2			3			14			3			4			6			3			46			14
Noncontrolling interests								(1	)		8			5			14			—			1			11			32			62
Provision (benefit) for income taxes		29			125			8			(6	)		16			17			22			2			10			17			4
Interest expense		31						8			6			29			4			15			5			9			46			7
Loss from disposal of discontinued operations		—			—			—			—			—			—			—			—			—			—			—

EBITDA		79			360			20			20			66			46			85			20			40			140			105
Subtract:
Interest Income		—			111			—			1			2			(1	)		1			2			1			7			2
Foreign currency transaction gain (loss), net		3						—			—			(3	)		—			(1	)		(1	)		—			(27	)		—
Gain (loss) on disposition of assets		—			—			—			—			—			—			—			—			—			—			68
Other charges		—			—			—			—			—			—			—			—			—			—			—
Other income (expense), net		—			2			4			(1	)		2			(1	)		6			—			1			(2	)		(13	)

ADJUSTED EBITDA⁽²⁾	$	76		$	247		$	16		$	20		$	65		$	48		$	79		$	19		$	38		$	162		$	48
AEI Ownership Percentage		17.7	%		4.2	%		50.0	%		50.0	%		52.1	%		48.9	%		16.2	%		80.9	%		52.1	%		28.1	%		25.0	%
Proportional Share — Adjusted EBITDA	$	13		$	10		$	8		$	10		$	34		$	22		$	13		$	15		$	20		$	46		$	12

NET DEBT CALCULATION:
Debt	$	344		$	918		$	31		$	23		$	212		$	64		$	130		$	86		$	71		$	505		$	78
Less: Cash		(21	)		(107	)		(3	)		(16	)		(34	)		(4	)		(13	)		(7	)		(5	)		(65	)		(10	)
Restricted cash — current		—			—			—			—			—			—			—			(32	)		—			—			—
Restricted cash — non-current		—			(34	)		—			—			—			—			—			—			—			—			—

NET DEBT⁽²⁾	$	323		$	777		$	28		$	7		$	178		$	60		$	117		$	47		$	66		$	440		$	68

Proportional Share — NET DEBT	$	57		$	33		$	14		$	4		$	93		$	29		$	19		$	38		$	34		$	124		$	17


⁽¹⁾		The following table sets forth the reconciliation of net income to Adjusted EBITDA and debt to net debt, and calculation of the unaudited proportional metrics by business for certain of AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP measures and proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

⁽²⁾		See “Non-GAAP Financial Measures” for definitions of Adjusted EBITDA and net debt. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA and debt to net debt.

A-6


Bcf/d		Billion cubic feet per day

BOMT		Build, operate, maintain and transfer agreement

BOT		Build, operate and transfer agreement

CFB		Circulated fluidized bed

CNG		Compressed natural gas

GWh		Gigawatt hour

LNG		Liquefied natural gas

Lost Time Incident		Any work-related injury or illness that prevents an employee (or contractor) from returning to work on his next regularly scheduled work shift; does not include restricted work cases, medical treatment cases, or sport injuries that occur on company premises during employee leisure time

Lost Time Incident Rate		Number of Lost Time Incidents multiplied by 200,000 divided by the number of man-hours worked; generally calculated on an annual and 12-month rolling basis

mmcfd		Million cubic feet per day

MW		Megawatt

MWh		Megawatt hour

NGL		Natural gas liquids

PPA		Power purchase agreement


			Page

INTRODUCTION			1
BUSINESS OF AEI			1
NON-GAAP FINANCIAL MEASURES			2
PRESENTATION OF INFORMATION			4
FORWARD-LOOKING STATEMENTS			5
GLOSSARY OF TECHNICAL TERMS			6
GLOSSARY OF DEFINED TERMS			7
Item 1. Identity of Directors, Senior Management and Advisers			12
Item 2. Offer Statistics and Expected Timetable			12
Item 3. Key Information			13
A. Selected Financial Data			13
B. Capitalization and Indebtedness			17
C. Reasons for the Offer and Use of Proceeds			18
D. Risk Factors			18
Item 4. Information on the Company			31
A. History and Development of the Company			31
B. Business Overview			31
C. Organizational Structure			57
D. Property, Plant and Equipment			58
Item 4A. Unresolved Staff Comments			60
Item 5. Operating and Financial Review and Prospects			61
A. Operating Results			66
B. Liquidity and Capital Resources			88
C. Research and Development, Patents and Licenses, Etc.			95
D. Trend Information			95
E. Off-Balance Sheet Arrangements			96
F. Tabular Disclosure of Contractual Obligations			97
Item 6. Directors, Senior Management and Employees			98
A. Directors and Senior Management			98
B. Compensation			102
C. Board Practices			102
D. Employees			106
E. Share Ownership			106
Item 7. Major Shareholders and Related Party Transactions			109
A. Major Shareholders			109
B. Related Party Transactions			109
C. Interests of Experts and Counsel			110
Item 8. Financial Information			111
A. Consolidated Statements and Other Financial Information			111
8.A.7 Legal Proceedings			111
8.A.8 Dividend Policy			111


	Page

B. Significant Changes		111
Item 9. The Offer and Listing		112
A. Offer and Listing Details		112
B. Plan of Distribution		112
C. Markets		112
D. Selling Shareholders		112
E. Dilution		112
F. Expenses of the Issue		112
Item 10. Additional Information		113
A. Share Capital		113
B. Memorandum and Articles of Association		113
C. Material Contracts		113
D. Exchange Controls		114
E. Taxation		114
F. Dividends and Paying Agents		116
G. Statement by Experts		116
H. Documents on Display		116
I. Subsidiary Information		117
Item 11. Quantitative and Qualitative Disclosures About Market Risk		118
Item 12. Description of Securities Other Than Equity Securities		120
Item 13. Defaults, Dividend Arrearages and Delinquencies		121
Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds		122
Item 15. Controls and Procedures		123
Item 16A. Audit Committee Financial Expert		124
Item 16B. Code of Business Conduct		125
Item 16C. Principal Accountant Fees and Services		126
Item 16D. Exemptions From the Listing Standards for Audit Committees		127
Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers		128
Item 16F. Change in Registrant’s Certifying Accountant		129
Item 16G. Corporate Governance		130
Item 17. Financial Statements		131
Item 18. Financial Statements		132
Item 19. Exhibits		133
Unaudited Proportional Financial Metrics		A-1
Reconciliation of Non-GAAP Measures		A-3
Exhibit 4.2
Exhibit 4.7
Exhibit 4.9
Exhibit 4.10
Exhibit 8.1
Exhibit 12.1
Exhibit 12.2
Exhibit 13.1
Exhibit 13.2


		Page

Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets		F-3
Consolidated Statements of Operations		F-4
Consolidated Statements of Cash Flows		F-5
Consolidated Statements of Equity		F-6
Notes to the Consolidated Financial Statements		F-7
Schedule II Valuation And Qualifying Accounts		F-57


	Balance at		Additions							Deductions
	Beginning of the		Charged to Costs		Translation			Acquisitions of					Balance at the End
Million of Dollars (U.S.)	Period		and Expenses		Adjustment			Business		Amounts Written off			of the Period
Allowance for lease receivables:
For the year ended December 31, 2007	$	—	$	40	$	—		$	—	$	—		$	40
For the year ended December 31, 2008		40		44		(3	)		10		(82	)(a)		9
For the year ended December 31, 2009		9		—		—			—		(9	)(a)		—
Allowance for accounts receivable:
For the year ended December 31, 2007	$	39	$	9	$	5		$	5	$	(12	)	$	46
For the year ended December 31, 2008		46		27		(8	)		31		(27	)		69
For the year ended December 31, 2009		69		18		8			1		(18	)		78


(a)		Due to termination of lease accounting, the lease receivable and associated allowance have been removed from the Company’s consolidated balance sheet and the amounts were recorded at the net carrying amount in the property, plant and equipment account. (see Note 4).


AEI
By:	/s/ James A. Hughes
	Name:	James A. Hughes
	Title:	Chief Executive Officer