20FR12G

As filed with the Securities and Exchange Commission on March 27, 2009

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number:

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)

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:


		Title of class

		Ordinary shares $0.002 par value

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, 2008 was:

224,624,481 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

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 o No þ

Indicate by check mark whether the registrant is a large 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

INTRODUCTION

AEI was incorporated in the Cayman Islands in June 2003. In this registration statement, the terms “AEI,” “we,” “us,” “our” 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

AEI manages, operates and owns interests in essential energy infrastructure businesses in emerging markets across multiple segments of the energy industry. Our company consists of 39 businesses which we aggregate into the following reporting segments: Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution, and Retail Fuel. See “Item 4. Information on the Company — A. History and Development” for additional detail about the company and its businesses.

iii

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 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 U.S. GAAP measure. From time to time we disclose non-GAAP financial measures, primarily Adjusted EBITDA, or earnings before interest, taxes, depreciation and amortization of long-lived assets, and net debt, or total debt less cash. The non-GAAP financial measures described herein or in other documents we issued are not a substitute for the GAAP measures of earnings and liquidity, for which management has responsibility.

We sometimes use Adjusted EBITDA in our communications with investors, financial analysts and the public. We define Adjusted EBITDA as net income (loss) excluding the impact of disposal of discontinued operations, income (loss) from discontinued operations, minority interests, provision (benefit) for income taxes, gain (loss) on early retirement of debt, interest expense and depreciation and amortization, interest income, foreign currency transaction gain (loss), net, gain (loss) on disposition of assets and other income (expense), net, excluding other charges. Adjusted EBITDA is a basis upon which we assess our financial performance. Adjusted EBITDA is generally perceived as a useful and comparable measure of operating performance. For example, interest expense, interest income and gain (loss) on early retirement of debt are dependent on the capital structure and credit rating of a company. However, debt levels, credit ratings and, therefore, the impact of interest expense, interest income and gain (loss) 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. Likewise, different ownership structures among companies can cause significant variability in the impact of minority interest on earnings. 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 gain (loss) 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 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. Accordingly, although Adjusted EBITDA and other non-GAAP measures as calculated by us may not be comparable to calculations of similarly titled measures by other companies, management believes that disclosure of Adjusted EBITDA can provide useful information to investors, financial analysts and the public in their evaluation of our operating performance.

We sometimes report net debt in our communications with investors, financial analysts and the public. 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, credit ratings and, therefore, the impact of interest expense on earnings 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 net cash position of the current operations. Accordingly, management believes that disclosure of net debt can provide useful information to investors, financial analysts and the public in their evaluation of our liquidity.

Management utilizes the non-GAAP measures of Adjusted EBITDA and net debt as key indicators of the financial performance and liquidity of our reporting segments and the underlying businesses. Adjusted EBITDA 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

PRESENTATION OF INFORMATION

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

This registration statement includes information regarding corporate 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 registration statement, 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;

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

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

	•	“Dominican pesos” or “DOP” are to the lawful currency of the Dominican Republic;

	•	“Guatemalan quetzals” or “GTQ” are to the lawful currency of Guatemala;

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

	•	“Panamanian balboas” are to the lawful currency of Panama;

	•	“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;

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

	•	“Venezuelan bolívares” are to the lawful currency of Venezuela.

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

FORWARD-LOOKING STATEMENTS

This registration statement 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 registration statement, 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 primarily 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 revenues.

	•	Governments exercise a greater degree of influence over the economies in which we operate and invest compared to those in developed economies. This influence, as well as political and economic conditions, could adversely affect our businesses.

	•	The uncertainty of the legal and regulatory environment in certain countries in which we operate, develop, or build infrastructure assets may make it more difficult for us to enforce our respective 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 business, financial condition and results of operations.

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

	•	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 involve significant risks that could lead to lost revenues, increased expenses, or termination of agreements.

	•	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 registration statement 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 registration statement 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.

vii

GLOSSARY OF TECHNICAL TERMS

Certain terms used in this registration statement are defined below:


Availability		For power plants, the ratio of the difference between maximum MWh that could be produced and MWh not produced due to planned and unplanned outages to maximum MWh that could be produced expressed as a percentage; for pipelines, the ratio of the difference between the maximum volume programmed to be transported and the volume not transported due to planned and unplanned restrictions/outages to the maximum volume programmed to be transported expressed as a percentage; and for gas plants, the ratio of the difference between the maximum volume that could be produced and the volume not produced due to planned and unplanned restrictions/outages to the maximum volume that could have been produced expressed as a percentage

Bcf/d		Billion cubic feet per day

BOMT		Build, operate, maintain and transfer agreement

BOT		Build, operate and transfer agreement

BTU		British thermal unit

Btu/kWh		British thermal unit/kilowatt hour

CNG		Compressed natural gas

DEC		Duration of outages (measured in hours per customer) as defined by ANEEL

FEC		Frequency of outages (measured in occurrences per customer) as defined by ANEEL

GJ		Gigajoule

GW		Gigawatt

GWh		Gigawatt hour

HRSG		Heat recovery steam generator

ISO		International Organization for Standardization

ISO 9001		ISO standards for quality management

ISO 14001		ISO standards for environmental management

kWh		Kilowatt hour

kV		Kilovolt

LDC		Local distribution company

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 and is generally calculated as annual and 12-month rolling

viii


LPG		Liquefied petroleum gas

Mbb/day		Million barrels per day

MMBtu		Million British thermal units

mmcfd		Million cubic feet per day

MVA		Megavolt ampere

MW		Megawatt

MWh		Megawatt hour

NGL		Natural gas liquids

OHSAS 18001		Occupational Health and Safety Assessment Series standards for occupational health and safety management systems

Reliability		For power plants, the ratio of the difference between maximum MWh that could be produced and MWh not produced as a result of unplanned outages to maximum MWh that could be produced expressed as a percentage; for pipelines, the ratio of the difference between the maximum volume programmed to be transported and the volume not transported due to unplanned restrictions/outages to the maximum volume programmed to be transported expressed as a percentage; and for gas plants, the ratio of the difference between the maximum volume that could be produced and the volume not produce due to unplanned restrictions/outages to the maximum volume that could be produced expressed as a percentage

SAIDI		System average interruption duration index; duration of outages (measured in hours per customer) as defined by the Institute of Electrical and Electronic Engineers

SAIFI		System average interruption frequency index; frequency of outages (measured in occurrences per customer) as defined by the Institute of Electrical and Electronic Engineers

TWh		Terawatt hour

GLOSSARY OF DEFINED TERMS

Certain terms used in this registration statement are defined below:


AEI Delaware		AEI LLC (formerly known as Ashmore Energy International LLC), a Delaware limited liability company

AEIL		Ashmore Energy International Limited, a Cayman Islands company

AESEBA		AESEBA S.A., an Argentine company that holds a controlling interest in EDEN

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

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

Ashmore		Ashmore Investment Management Limited, a holding company for certain energy-related assets acquired by the Ashmore Funds

Ashmore Funds		Investment funds directly or indirectly managed by Ashmore

BBPL		Bolivia-to-Brazil Pipeline which comprises 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., our Chinese Natural Gas Distribution business

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

BOTAŞ		Boru Hatlari Ile Petrol Tasima A.S., the Turkish government owned natural gas monopoly

Brazilian MME		Brazilian Ministry of Mines and Energy (Ministério de Minas e Energia)

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

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

CDEEE		Dominican Corporation of State-owned Electricity Companies (Corporación Dominicana de Empresas Eléctricias Estatales)

CIESA		Compañía de Inversiones de Energía S.A., an Argentine energy company that holds a controlling interest in TGS and in which we hold debt instruments

Colombian MME		Colombian Ministry of Mines and Energy

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

DCL		DHA Cogen Limited, our Pakistani power generation and water desalination company


EC		Electricidad de CentroAmerica S.A. de C.V., our wholly owned subsidiary which holds 86.4% of Delsur

EDEN		Empresa Distribuidora de Energía Norte S.A., our Argentine Power Distribution business

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

Elektra		Elektra Noreste, S.A., our Panamanian Power Distribution business

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

Emgasud		Emgasud S.A., an Argentine energy corporation

EMHC		EMHC Ltd., a wholly owned subsidiary of PEI

EMRA		Turkish Energy Market Regulatory Authority

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

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

Fenix		Empressa Electrica de Generacion de Chilca S.A., a Peruvian company in the advanced stages of developing a combined cycle power plant in Chilca, Peru

Furnas		Furnas Centrais Elétricas, S.A., one of Brazil’s federally controlled electricity generation companies

GASA		Gas Argentino S.A., which holds a controlling interest in MetroGas and in which we hold debt instruments

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 Promigas

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

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

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

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


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

MIHPS		Ministry of Infrastructure, Housing and Public Services of the Province of Buenos Aires, Argentina

NPC		National Power Corporation of the Philippines

NDRC		National Development and Reform Commission of China

Operadora San Felipe		Operadora San Felipe Limited Partnership, the operator of San Felipe and our wholly owned subsidiary

PDG		Panama Distribution Group, S.A., Panama, holder of AEI’s 51% ownership of Elektra common stock

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

PEI		Prisma Energy International Inc., our predecessor

Poliwatt		Politwatt Limitada, a wholly owned subsidiary of PQP

PPO		Private Power Operators Limited, the operator of JPPC

PQP		Puerto Quetzal Power LLC, our Guatemalan Power Generation business

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

Repsol		Repsol YPF, S.A., a Spanish integrated oil and gas company

Shell		Royal Dutch Shell plc and its affiliates

SIE		Sociedad de Inversiones de Energía S.A., our Colombian Retail Fuel business which owns Terpel and Gazel

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

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

TBS		Transborder Gas Services Ltd., one of our Natural Gas Transportation and Services businesses operating in Brazil and Bolivia and part of the Cuiabá Integrated Project

Tecnored		Tecnored S.A., a company that provides electricity maintenance and construction services in Chile, primarily to Chilquinta

Tecsur		Tecsur S.A., a company that provides electricity maintenance and construction services in Peru, primarily to Luz de Sur.

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

xii

PART I.

Item 1. Identity of Directors, Senior Management and Advisers


A.	Directors and Senior Management

The following table sets forth our directors and senior management and the positions held by them. The business address for each of our directors and senior management is c/o AEI Services LLC, 700 Milam, Suite 700, Houston, TX 77002.


Name		Position

Ronald W. Haddock		Non-Executive Chairman of the board of directors
Brent de Jong		Non-Executive Vice Chairman of the board of directors
James Hughes		Chief Executive Officer and Director
Robert Barnes		Director
Philippe A. Bodson		Director
Henri Philippe Reichstul		Director
Robert E. Wilhelm		Director
George P. Kay		Director
John G. Fulton		Chief Financial Officer
Maureen J. Ryan		General Counsel and Chief Compliance Officer
Emilio Vicens		VP Business Development
Laura C. Fulton		VP Chief Accounting Officer
Andrew Parsons		VP Chief Administrative Officer
Brian Zatarain		VP Chief Risk Officer
Brian Stanley		VP Operations


B.	Advisers

Not Applicable.


C.	Auditors

Our auditors for the preceding three years have been Deloitte & Touche LLP, whose address is 1111 Bagby Street, Suite 4500, Houston, Texas 77002. Deloitte & Touche LLP is a public accounting firm registered with the Public Company Accounting Oversight Board.

Item 3. Key Information

A. Selected Financial Data

The following table presents selected financial data for AEI, the successor entity, and for both of our predecessor companies, Elektra Noreste, S.A. and Prisma Energy International Inc. We have derived the historical successor AEI financial data for the years ended December 31, 2006 and 2007 from our audited consolidated financial statements included elsewhere in this registration statement. We have derived the historical predecessor Elektra financial data for the 275-day period ended October 2, 2005 and the historical successor AEI financial data for the 90-day period ended December 31, 2005 from the audited consolidated financial statements which are not included elsewhere in this registration statement. We have derived the historical predecessor Prisma Energy International Inc. information for the years ended December 31, 2005 and 2004, which is not included elsewhere in this registration statement, and the 249-day period ended September 6, 2006 from the audited consolidated financial statements, which are included elsewhere in this registration statement. The summary historical data as of and for the nine months ended September 30, 2007 and as of and for the nine months ended September 30, 2008 are derived from the AEI unaudited condensed consolidated financial statements included elsewhere in this registration statement. Our historical results for any prior period are not necessarily indicative of results to be expected for any future period.

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

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			For the
							275-Day			90-Day
							Period			Period									For the			For the
							From			From			For the			For the			Nine			Nine
	For the			For the			January 1,			October 3,			Year			Year			Months			Months
	Year Ended			Year Ended			2005 to			2005 to			Ended			Ended			Ended			Ended
	December 31,			December 31,			October 2,			December 31,			December 31,			December 31,			September 30,			September 30,
	2003			2004			2005			2005			2006⁽¹⁾			2007			2007			2008
	Millions of dollars (U.S.)									Millions of dollars (U.S.) except per share data

Statement of Operations Data:
Revenues	$	211		$	225		$	200		$	72		$	946		$	3,216		$	2,287		$	7,152
Cost of sales		148			152			140			53			566			1,796			1,227			5,679
Operating expenses:
Operations, maintenance, general and administrative expenses		30			31			22			7			193			630			445			681
Depreciation and amortization		10			11			9			3			59			217			153			203
Taxes other than income		—			—			1			—			7			43			24			34
Other charges		—			—			—			—			—			50			—			44
(Gain) loss on disposition of assets		—			—			1			—			7			(21	)		(13	)		(40	)
Equity income from unconsolidated affiliates		—			—			—			—			37			76			55			102

Operating income		24			32			27			9			151			577			506			653
Interest income		—			—			1			—			71			110			84			68
Interest expense		(4	)		(4	)		(6	)		(3	)		(138	)		(306	)		(228	)		(292	)
Foreign currency transactions gain (loss), net		—			—			—			—			(5	)		19			12			(24	)
Loss on early retirement of debt		—			—			—			—			—			(33	)		(33	)		—
Other income (expense), net		—			—			—			—			7			(22	)		(8	)		9

Income before income taxes and minority interests		20			28			22			6			86			345			333			414
Provisions for income tax		(6	)		(8	)		(7	)		(2	)		(84	)		(193	)		(164	)		(169	)
Minority interests		—			—			—			(2	)		(20	)		(65	)		(79	)		(120	)

Income (loss) from continuing operations		—			—			—			—			(18	)		87			90			125
Income from discontinued operations, net of tax		—			—			—			—			7			3			3			—
Gain from disposal of discontinued operations, net of tax		—			—			—			—			—			41			—			—

Net income (loss)	$	14		$	20		$	15		$	2		$	(11	)	$	131		$	93		$	125


	Elektra Noreste, S.A. (Predecessor)									AEI (Successor)
							For the			For the
							275-Day			90-Day
							Period			Period									For the			For the
							From			From			For the			For the			Nine			Nine
	For the			For the			January 1,			October 3,			Year			Year			Months			Months
	Year Ended			Year Ended			2005 to			2005 to			Ended			Ended			Ended			Ended
	December 31,			December 31,			October 2,			December 31,			December 31,			December 31,			September 30,			September 30,
	2003			2004			2005			2005			2006⁽¹⁾			2007			2007			2008
	Millions of dollars (U.S.)									Millions of dollars (U.S.) except per share data

Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	26		$	28		$	19		$	12		$	155		$	686		$	510		$	182
Investing activities		(17	)		(16	)		(13	)		(6	)		(1,729	)		(1,151	)		(461	)		(289	)
Financing activities		(8	)		(7	)		(12	)		(5	)		2,395			88			(281	)		182
Capital expenditures		(17	)		(18	)		(13	)		(6	)		(76	)		(249	)		(155	)		(240	)
Other Financial Data:
Adjusted EBITDA⁽²⁾														217			823			646			860
Basic and diluted earnings per share:
Income (loss) from continuing operations														(0.09	)		0.42			0.43			0.58
Net income (loss)														(0.05	)		0.63			0.44			0.58
Weighted average shares outstanding														202			209			209			217


	Elektra Noreste, S.A.
	(Predecessor)				AEI (Successor)
	As of		As of		As of		As of		As of		As of
	December 31,		December 31,		December 31,		December 31,		December 31,		September 30,
	2003		2004		2005		2006		2007		2008

Balance Sheet Data:
Property, plant and equipment (net)	$	218	$	221	$	228	$	2,307	$	3,035	$	3,559
Total assets		280		282		568		6,134		7,853		9,470
Long-term debt		38		95		90		2,390		2,515		2,877
Total debt		55		100		100		2,677		3,264		3,981
Net debt⁽²⁾		50		91		91		1,591		2,525		3,233
Total shareholders’ equity		155		110		327		1,441		1,858		1,934


(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:


	Elektra Noreste, S.A.
	(Predecessor)						AEI (Successor)
	As of			As of			As of			As of			As of			As of
	December 31,			December 31,			December 31,			December 31,			December 31,			September 30,
	2003			2004			2005			2006			2007			2008

Total debt	$	55		$	100		$	100		$	2,677		$	3,264		$	3,981
Less
Cash and cash equivalents		(1	)		(7	)		(6	)		(830	)		(516	)		(588	)
Current restricted cash		—			—			—			(117	)		(95	)		(74	)
Non-current restricted cash		(4	)		(2	)		(3	)		(139	)		(128	)		(86	)

Net debt	$	50		$	91		$	91		$	1,591		$	2,525		$	3,233

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)	$	93		$	18		$	15	$	1	$	2	$	(140	)	$	(11	)
Depreciation and amortization		47			9			2		—		1		—			59
Minority 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 gain (loss), net		(4	)		(1	)		—		—		—		—			(5	)
(Gain) 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

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)	$	227		$	83		$	53		$	22		$	55		$	(309	)	$	131
Depreciation and amortization		139			42			20			8			3			5			217
Minority 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 nine months ended September 30, 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)	$	173		$	80	$	39		$	15		$	4		$	(218	)	$	93
Depreciation and amortization		98			28		15			5			4			3			153
Minority interests		7			27		2			34			7			2			79
Provision for income taxes		86			30		25			15			5			3			164
Interest expense		61			31		32			10			10			84			228
Subtract:
Income from discontinued operations		—			—		—			—			3			—			3
Gain from disposal of discontinued operations		—			—		—			—			—			—			—
Interest income		47			20		5			1			—			11			84
Foreign currency transaction gain (loss), net		3			17		(6	)		—			(2	)		—			12
(Gain) loss on disposition of assets		(8	)		21		—			—			—			—			13
Other charges		—			—		—			—			—			—			—
Other income (expense), net		(3	)		14		4			(3	)		(1	)		(52	)		(41	)

Adjusted EBITDA		386			124		110			81			30			(85	)		646

The following table sets forth the reconciliation of net income to Adjusted EBITDA for AEI for the nine months ended September 30, 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)	$	155		$	21		$	(10	)	$	21		$	77		$	(139	)	$	125
Depreciation and amortization		109			19			17			14			40			4			203
Minority interests		9			(31	)		70			26			44			2			120
Provision for income taxes		89			6			19			22			30			3			169
Interest expense		109			35			34			15			40			59			292
Subtract:
Income from discontinued operations		—			—			—			—			—			—			—
Gain from disposal of discontinued operations		—			—			—			—			—			—			—
Interest income		44			12			5			1			4			2			68
Foreign currency transaction gain (loss), net		—			6			(1	)		(1	)		(19	)		3			(24	)
(Gain) loss on disposition of assets		(15	)		—			—			—			69			(14	)		40
Other charges		—			(44	)		—			—			—			—			(44	)
Other income (expense), net		(8	)		11			10			(1	)		(6	)		3			9

Adjusted EBITDA		450			77			116			99			183			(65	)		860

PEI

The following table sets forth the financial results for the historical predecessor, Prisma Energy International Inc.


	Prisma Energy International Inc. (Predecessor)
							For the 249-Day
	For the Year Ended			For the Year Ended			Period Ended
	December 31, 2004			December 31, 2005			September 6, 2006
	Millions of dollars (U.S.)

Statement of Operations Data:
Revenues	$	1,187		$	1,901		$	1,414
Cost of sales		575			930			750
Operating expenses
Operations, maintenance, general and administrative		233			387			233
Depreciation and amortization		77			101			63
Taxes other than income		20			31			32
Loss on disposition of assets		3			14			6
Equity income from unconsolidated affiliates		111			109			35

Operating income		390			547			365
Interest income from unconsolidated affiliates		—			4			2
Interest income		41			97			80
Interest expense		(65	)		(104	)		(96	)
Foreign currency transaction gain (loss), net		74			95			17
Other income (expense), net		82			71			26

Income before income taxes and minority interest		522			710			394
Provision for income taxes		112			181			209
Minority interest		16			79			21

Net income	$	394		$	450		$	164

Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	304		$	507		$	448
Investing activities		9			186			(448	)
Financing activities		(169	)		(169	)		(580	)
Capital expenditures		(53	)		(97	)		(72	)
Other Financial Data:
Adjusted EBITDA⁽¹⁾		—			662			434


	Prisma Energy International Inc. (Predecessor)
	As of		As of
	December 31, 2004		December 31, 2005
	Millions of dollars (U.S.)

Balance Sheet Data:
Property, plant and equipment (net)	$	1,673	$	1,629
Total Assets		4,145		4,759
Long-term debt		622		748
Total debt		838		870
Net debt⁽¹⁾		174		(375	)
Total shareholders’ equity		2,080		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			As of
	December 31, 2004			December 31, 2005
	Millions of dollars (U.S.)

Total debt	$	838		$	870
Less
Cash and cash equivalents		(489	)		(1,046	)
Current restricted cash		(144	)		(150	)
Non-current restricted cash		(31	)		(49	)

Net debt	$	174		$	(375	)

The following table sets forth the reconciliation of net income to Adjusted EBITDA for Prisma Energy International for the year ended December 31, 2005 on a consolidated basis and by segment.


						Natural Gas
	Power			Power		Transportation		Natural Gas
	Distribution			Generation		and Services		Distribution			Retail Fuel		Other⁽¹⁾			Total
	Millions of dollars (U.S.)

Net income	$	215		$	116	$	58	$	23		$	19	$	19		$	450
Depreciation and amortization		33			56		8		—			4		—			101
Minority interests		1			61		17		—			—		—			79
Provision for income taxes		102			72		9		—			—		(2	)		181
Interest expense		99			63		18		—			12		(88	)		104
Subtract:
Interest income from unconsolidated affiliates		—			1		2		1			—		—			4
Interest income		34			50		4		—			1		8			97
Foreign currency transaction, gain, net		83			6		4		—			2		—			95
(Loss) on disposition of assets		(5	)		—		—		(9	)		—		—			(14	)
Gain on early retirement of debt		32			21		—		—			—		—			53
Other income (expense), net		5			31		—		—			—		(18	)		18

Adjusted EBITDA	$	301		$	259	$	100	$	31		$	32	$	(61	)	$	662


(1)		Other primarily includes 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. It also includes the effects of eliminating transactions between segments including 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.


B.	Capitalization and Indebtedness

The following table sets forth our combined cash, cash equivalents, restricted cash and capitalization and indebtedness as of January 31, 2009 on an actual basis.

The table below should be read in conjunction with “Item 5 — Operating and Financial Review and Prospects” and the consolidated financial statements and related notes included elsewhere in this registration statement.


	As of January 31,
	2009
	Actual
	Millions of dollars (U.S.)

Cash and cash equivalents	$	700

Restricted cash		135	⁽¹⁾

Long-term debt, including current portion:
Debt held by parent company:
Senior credit facility		936
Revolving credit facility		390
Synthetic revolving credit facility		105
PIK notes		355
Debt held by consolidated subsidiaries:⁽²⁾
Cálidda		84
Cuiabá		97
Delsur		73
DCL		78
EDEN		37
Elektra		129
Elektro		368
ENS		55
Luoyang		136
PQP		88
Promigas		957
Other		64

Total long-term debt, including current portion		3,952
Stockholder’s equity:
Ordinary shares, $0.002 par value: actual:
5,000,000,000 shares authorized and 222,984,113 issued and outstanding		—
Additional paid-in-capital		1,756
Retained earnings		296
Accumulated other comprehensive income		(220	)

Total stockholders’ equity		1,832

Total capitalization	$	5,784


(1)		Includes $51 million of noncurrent restricted cash. As of January 31, 2009, our current restricted cash balance was $84 million.

(2)		Not guaranteed by AEI. See “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources.”

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 primarily 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 revenues.

We have operations and/or development activities in Argentina, Bolivia, Brazil, Chile, China, Colombia, Dominican Republic, Ecuador, El Salvador, Guatemala, Jamaica, Mexico, Nicaragua, Pakistan, Panama, Peru, the Philippines, Poland, Turkey, Venezuela, and Vietnam. We expect that in the future we will have additional operations in these or other countries with similar political, economic and social conditions. We derive our revenue primarily from the sale or transportation of electricity, natural gas and liquid fuels. Energy demand is driven by economic conditions in the countries in which we operate. Many of these countries have a history of economic instability. Our results of operations and financial condition are to a large extent dependent upon the overall level of economic activity, political and social stability in these emerging markets. Should economic conditions deteriorate in emerging markets generally, our revenues will likely decrease.

Governments exercise a greater degree of influence over the economies in which we operate and invest compared to those in developed economies. This influence, as well as political and economic conditions, could adversely affect our businesses.

Governments in many of the markets in which we operate frequently intervene in the economy and occasionally make significant changes in monetary, credit 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 business, financial condition and results of operations 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;

	•	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;

	•	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 hydrocarbon and electricity infrastructure.

The uncertainty of the legal and regulatory environment in certain countries in which we operate, develop, or build infrastructure assets may make it more difficult for us to enforce our respective 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 can 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, such legal proceedings are costly and may not be successful or resolved in a timely manner, and such resolution may not be enforced. Areas in which we may be affected include:


	•	forced renegotiation or modification of concession and purchase agreements,

	•	termination of permits or concessions and compensation upon any such termination, and

	•	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 business, financial condition and results of operations.

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, 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 appropriate exchange rate. 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. 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. Where possible, we match external indebtedness in the functional currency of the subsidiary. There may be instances where this is not possible or uneconomical. As a result, currency fluctuations may affect the earnings of that entity and may have an affect on our consolidated earnings.

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 to occur in one or a combination of the countries in which we operate, our business, results of operations, cash flows and financial condition could be adversely affected.

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 could adversely affect our business, results of operations, cash flows and 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 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 civil conflicts or unrest, which could affect our assets, our ability to operate and our personnel. In the past, we occasionally experienced attacks on our assets, and in 2008 there was a failed attempt to destroy a portion of the GTB pipeline in Bolivia. 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 business, financial condition and 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 would 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 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. In an inflationary environment, the value of uncollected accounts receivable, as well as of 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 business, results of operations, cash flows and financial condition.

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

Bolivia has experienced political and economic instability that has resulted in significant changes in its general economic policies and regulations. In May 2005, the Bolivian Congress approved and enacted a new Hydrocarbons Law which substantially changed the legal framework for the energy sector in Bolivia and forced all upstream foreign companies to enter into new “operating contracts.” Subsequently, the current Bolivian President took over the presidency on December 18, 2005 and on May 1, 2006, the Bolivian government purported to nationalize the hydrocarbons industry under Supreme Decree No. 28701. The Decree, among other things, anticipated, through future action, the nationalization of the shares necessary for the state-run oil and gas company, Yacimientos Petroliferos Fiscales Bolivianos, or YPFB, to control at least 50% plus one share of certain named companies, including Transredes. On May 1, 2008, the Bolivian government issued Supreme Decree No. 29541, or the Expropriation Decree, pursuant to which it stated that 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 referenced in the decree. The government subsequently registered these shares in YPFB’s name. At that time, TR Holdings had not been compensated for these shares and we filed an arbitration claim against the government, among other things, demanding full compensation. On October 17, 2008, we reached a settlement with the Bolivian government pursuant to which the Bolivian government agreed to pay us $120 million in two installments. The first payment of $60 million was made on October 22, 2008 and the second

payment of $60 million was made on March 2, 2009. Upon reaching this settlement, we withdrew the arbitration proceeding. We are currently evaluating the commercial impact that these political events in Bolivia could have on Cuiabá in Brazil. The developments in Bolivia may increase the risk that our other assets in Bolivia, including GTB and GOB, will be subject to expropriation without fair compensation. See “Item 5. Operating and Financial Review and Prospects — Recent Developments — Bolivia Hydrocarbons Nationalization.”

Venezuela has nationalized parts of the hydrocarbon and electricity industries and switched 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. This development may increase the risk that our other assets in Venezuela will be subject to expropriation without fair compensation.

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.

As an international company with shares registered in the United States, we will be 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 business. In addition, when we acquire a new business, we may be required to implement certain measures to ensure its compliance with the FCPA if the new business has not been previously subject to anti-bribery legislation.

Risks Relating to the Industries in which We Operate

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

We operate energy businesses located in 20 countries 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 or our ability to meet our projections. 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 business, including, but not limited to:


	•	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 non-controllable 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,

	•	rules governing energy supply and purchase contracts,

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

	•	rules governing dispatch order,

	•	methodology of calculating firm capacity payment charges and frequency of adjustment of those charges,

	•	calculation of transportation/transmission rates, and

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

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

Our Power Distribution and Natural Gas Distribution businesses, and most of our Natural Gas Transportation and Retail Fuel businesses, as well as some of our Power Generation 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 liquidity, results of operations, cash flows and financial condition may be adversely affected. We expect several of our businesses to have tariff reviews prior to the year 2010, including BMG, Chilquinta, EDEN Gases de Occidente, Luz del Sur, Surtigas and Tongda.

The Brazilian National Electric Energy Agency (Agência Nacional de Energia Elétrica), or ANEEL, has jurisdiction to regulate and oversee various other aspects of Elektro’s business, including decisions as to whether or not to reduce our tariffs or that our investments must be increased. Elektro’s tariff was reset in August 2007 and the tariffs for the residential and industrial customers were reduced, respectively, by 20.65% and 13.57%, resulting in a reduction across all customer segments averaging 17.2%. In case we are obliged by ANEEL to make additional and unexpected investments and not allowed to adjust our tariffs accordingly, or if ANEEL issues resolutions that modify regulations related to such adjustment, our results of operations may be adversely affected.

For our Argentine business, EDEN, in 2002 the tariffs that we charge were converted from their original U.S. dollar values to Argentine pesos at a rate of AR$1.00 per U.S.$1.00. In 2006, EDEN renegotiated its tariff structure with the government of Buenos Aires Province. On August 25, 2008, a new decree was issued raising the EDEN tariff by 44% on average. We expect the next tariff review to be sometime during the first half of 2009.

In El Salvador, the General Superintendence of Electricity and Telecommunications (Superintendencia General de Electricidad y Telecomunicaciones), or SIGET, has the power to regulate Delsur’s tariff to final end consumers and for other services such as new customer connections and re-connections to the distribution network. Delsur’s tariff was reset in December 2007 and amended in March 2008. Following this reset, as amended, Delsur’s regulated income will be reduced by an average of 21.6% (20.0% due to reductions in distribution and commercial tariffs and 1.6% due to technical and non-technical losses).

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 a 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 of our concession.

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 legislation.

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.

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 business, financial condition and results of operations.

Our business performance may be adversely affected by our ability 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 Power Generation 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 facilities may prevent the facility from performing under applicable power sales 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 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;

	•	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 business, results of operations, cash flows and financial condition.

Additionally, under some of our contracts, a breakdown or failure of one of our facilities preventing the facility from performing under those agreements could, in certain situations, result in the termination of the agreement or incurring liability for liquidated damages.

We are dependent on external parties and other factors for consumables, energy and fuel and our inability to obtain such supplies could adversely affect our ability to operate, financial condition and results of operations and cash flows.

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 distribution capacity of our gas and liquids pipelines; any prolonged interruption in our ability to access upstream reserves would affect our ability to generate revenues;

	•	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, or availability of fuel to our power plants or for resale by our Natural Gas Distribution and Retail Fuel businesses, which would materially and adversely affect our overall revenues and profits;

	•	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 that such available remedies will 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 distributions 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 energy may not be available, or become available, in sufficient time to preclude an interruption of our operations.

For example, EPE, our Brazilian Power Generation business, has experienced natural gas supply issues due to a lack of supply combined with a sharp increase in regional demand. For additional information, see “Item 4. Information on the Company — B. Business Overview — Power Generation — Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE),” “Item 4. Information on the Company — B. Business Overview — Natural Gas Transportation and Services — Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS)” and “Item 5. Operating and Financial Review and Prospects — Recent Developments — Cuiabá Integrated Project,” regarding the risks presented by the reduction in the supply of natural gas to EPE.

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 and results of operations and cash flows.

All of our Power Generation businesses, except PQP and 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.

Some of our businesses have experienced payment issues from large customers. In particular, the Corporación Dominicana de Empresas Electricas Estatales, or CDEEE, which is the sole purchaser of power from San Felipe, had significant payment delays prior to 2005 and Accroven is currently experiencing significant payment delays from its sole customer, PDVSA.

Our electricity and gas distribution businesses are impacted by the creditworthiness of our governmental, wholesale and retail residential 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.

A default by any of our key customers in our Power Generation and Natural Gas Transportation and Services businesses could materially and adversely affect our results of operations.

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 on-going 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, cash flows and financial condition.

Risks Related to Our Businesses

The operation of our businesses involves significant risks that could lead to lost revenues, increased expenses, or termination of agreements.

The operation of our businesses involve many risks, including:


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

	•	fuel spillage, seepage or release of hazardous materials;

	•	the unavailability of critical equipment or parts;

	•	fuel or energy supply interruptions;

	•	work stoppages and labor unrest;


	•	errors in the operation and failures of critical equipment;

	•	social unrest;

	•	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;

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

	•	forecasting errors in total volumes of gas transported and/or distributed;

	•	decreases in energy consumption due to higher energy prices;

	•	miscalculation of our energy needs in our power distribution businesses which are required to contract in advance for their electricity needs; and

	•	construction and operational delays or unanticipated cost overruns.

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

A failure to resolve current gas supply issues at the Cuiabá Integrated Project may have a material adverse effect on the operations and performance of that business.

The adverse effects on production of natural gas resulting from the nationalization of the Bolivian hydrocarbon industry, force majeure issues, operational issues affecting the production of gas fields in Bolivia and increasing demand for natural gas have significantly reduced the gas supply from Bolivia to the Cuiabá Integrated Project. EPE has experienced periods of no gas supply resulting in periodic shutdowns and has generally not been operational since August 2007. Furnas, EPE’s sole offtaker, has been refusing to make capacity payments. The Bolivian government has indicated that gas availability may continue to be limited in the short- and medium-term. As a result of a Brazilian government order, EPE entered into an agreement on March 31, 2008 with Furnas to operate on diesel fuel for a 30-day period which was renewable up to a maximum of 120 days. EPE operated for approximately one month under this agreement and its term has now expired.

Lack of gas supply to the Cuiabá Integrated Project may have a material adverse effect on that business, including on EPE’s power purchase agreement with Furnas, one of Brazil’s federally controlled electricity generation companies. On October 1, 2007, EPE received a notice from Furnas purporting to terminate the power purchase agreement as a result of the current lack of gas supply. EPE strongly disagrees with Furnas’ position and notified Furnas that EPE believes Furnas had no contractual basis to terminate the power purchase agreement and initiated an arbitration proceeding in accordance with the power purchase agreement. We expect a decision in this arbitration in mid 2009.

If we are unable to secure an adequate long-term supply of gas from Bolivia to EPE or find acceptable alternative sources of fuel supply, or if we are unable to satisfactorily resolve our dispute with Furnas, the operations of the Cuiabá Integrated Project will be materially adversely effected. Under these circumstances, there will be a corresponding impact on our financial performance and cash flows which could be material. We are unable at the current time to predict the ultimate impact or duration of the current issues at the Cuiabá Integrated Project. For additional information, see “Item 4. Information on the Company — B. Business Overview — Power Generation — Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE),” “Item 4. Information on the Company — B. Business Overview — Natural Gas Transportation and Services — Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS)” and “Item 5. Operating and Financial Review and Prospects — Recent Developments — Cuiabá Integrated Project.”

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. In particular, we routinely are required to assess the financial and tax impacts of complicated business transactions which occur on a worldwide basis. These assessments are dependent on hiring personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with U.S. reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse affect on our ability to report our financial condition and results of operations.

Our proposed acquisitions and development projects may not be completed or, if completed, perform as expected. Our acquisition and development activities may consume a portion of our management’s focus, and 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, and obtain the necessary licenses, permits and financing.

Although acquired businesses may have significant operating histories at the time we acquired 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 business may not generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them;

	•	the rate of return from acquired businesses may not justify 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.

Acquisitions may place a strain on our internal accounting and managerial controls. In order to integrate acquisitions outside the United States, we will need to hire personnel with sufficient expertise in U.S. GAAP to timely and accurately comply with our financial reporting obligations, including Section 404 of the Sarbanes-Oxley Act. Our inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse affect on our ability to report our financial condition and results of operations.

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 business.

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 liabilities that are not fully covered by our insurance policies.

We maintain insurance policies intended to mitigate our losses due to customary risks; covering 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 liabilities that may arise in the course of our business or that this insurance will 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 may be adversely affected if we incur liabilities that are not fully covered by our insurance policies.

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 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 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 we 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 non-controlling 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 non-controlling 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 non-controlling 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 performance.

While we operate wholly or partially without long-term agreements, some of our Power Generation and distribution businesses buy and sell electricity in the wholesale spot markets to the extent they require or need to dispose of any additional capacity. 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 fluctuating cost of coal, natural gas, oil or conditions of hydro reservoirs, which price fluctuations have previously been cyclical. 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. Although we generally prefer risk controls, including appropriate commodity and other hedges, if available, we may not always engage in hedging transactions. 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 companies do not produce volumes or other contractual obligations in accordance with the hedging contracts.

Financial Risks

We have identified significant deficiencies and material weaknesses in our internal controls that could affect our ability to ensure timely and reliable financial reports.

In connection with the year end audits of our 2007 and 2006 financial statements, several matters were identified that were deemed to be “material weaknesses” in our internal controls as defined in standards established by the American Institute of Certified Public Accountants, or AICPA.

The AICPA defines a significant deficiency as a control deficiency, or a combination of control deficiencies, that adversely affects the entity’s ability to initiate, authorize, record, process, or report financial data reliably in accordance with generally accepted accounting principles such that there is more than a remote likelihood that a misstatement of the entity’s financial statements will not be prevented or detected. The AICPA defines a material weakness as a significant deficiency, or a combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements will not be prevented or detected.

In 2006, a material weakness was identified in our internal controls. This material weakness related to the size and levels of expertise of our accounting department. Following the acquisition of PEI by Ashmore Energy International Limited, or AEIL, in September 2006, a number of personnel on the accounting staff elected to leave following the payment of certain retention and incentive bonus payments to which they became entitled under long term incentive plans put in place by PEI. As a result, it was determined that our controls over the financial statement close process, including those controls implemented at our subsidiary, Promigas, and communication of information to our accounting department, were not operating effectively, which could adversely affect our ability to produce accurate financial reports on a timely basis. Corrective actions taken by us, in 2007 and 2008, included an internal audit review, hiring seasoned accounting professionals with expertise in financial reporting, and developing enhanced financial reporting guidelines. We believe these actions will assist us in adequately researching, documenting, reviewing and drawing conclusions on accounting and reporting matters as well as providing timely financial data. In 2007, management concluded the material weakness had not been fully remediated. In 2008, we strengthened the accounting function through the hiring of a chief accounting officer in March 2008. We have hired additional accounting professionals in 2008. In 2009, we plan to implement a new consolidation system.

In 2006, a material weakness was also identified in our internal controls related to income taxes. This material weakness was identified as a result of the inability to capture and process income tax information in a timely manner, along with the recording of income tax valuation allowances and the preparation and reviewing of income tax disclosures. To improve our income tax reporting in 2007, we hired additional personnel with expertise in these areas and have added additional positions in 2008. We have also standardized and automated some of the data gathering processes needed for the preparation of income tax disclosures. In 2007, management concluded the material weakness had not been fully remediated. We plan to continue automating the gathering of information through the implementation of the new consolidation system in 2009. We also plan to enhance our training in these areas and develop improved reporting guidelines.

While we have taken actions to address these material weaknesses, additional measures are necessary, and these actions, along with other measures we expect to take to improve our internal controls, may not be sufficient to address the issues identified to ensure that our internal controls are effective or to ensure that such material weaknesses or other material weaknesses would not result in a material misstatement of our annual or interim financial statements. In addition, other material weaknesses or significant deficiencies may be identified in the future, in particular, in connection with the implementation of Section 404 of the Sarbanes-Oxley Act (SOX) relating to internal controls over financial reporting. We are not currently required to meet the standards set forth in Section 404 of SOX, but will be subject to these requirements after our

registration statement becomes effective. If we are unable to correct existing or future material weaknesses or deficiencies in internal controls in a timely manner, our ability to record, process, summarize and report financial data will be adversely affected. This failure could materially and adversely impact our business, our financial condition, the market value of our securities and subject us to civil and criminal investigations and penalties. In addition, there could be a negative reaction in the financial markets due to a loss of confidence in the reliability of future financial statements.

A downgrade in our credit ratings or that of our subsidiaries could adversely affect our ability to access the capital markets which could increase our interest costs or adversely affect our liquidity and cash flows.

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, were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs would increase.

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 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 developments.

Current market developments may adversely affect our industry, business, results of operations and 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, initially of mortgage-backed securities but spreading 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 credit-worthy 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 and results of operations and 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 continuing or further disruptions in the capital markets or other events.

We could incur significant costs due to the financial condition of our insurance carriers.

We insure our properties through insurance companies that we believe have a good rating at the time our policies are put into effect. The financial condition of one or more of our insurance companies that we hold policies with may be negatively impacted resulting in their inability to pay on future insurance claims. Their inability to pay future claims may have a negative impact on our financial results. In addition, the failure of one or more insurance companies may increase the costs to renew our insurance policies or increase the cost of insuring additional properties or recently developed or redevelopment properties.

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 or project financing arrangements, to satisfy certain obligations or other conditions before they may make distributions to us. Under our credit agreements, indentures 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 significantly reduce our future earnings and cash flow.

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 minority shareholders from influencing significant corporate decisions and policies.

As of September 30, 2008, investment funds directly or indirectly managed by Ashmore, or the Ashmore Funds owned approximately 54% of our ordinary shares. Other institutional fund investors owned approximately 45%, and members of management directors and our employees and former employees owned

the remaining ordinary shares. Consequently, the Ashmore Funds 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. In addition, the ability of shareholders, other than the Ashmore Funds, to influence our management and policies will 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.

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

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. Furthermore, one of our directors, Brent de Jong, is affiliated with the Ashmore Funds. As a result of this relationship, when conflicts between the interests of the Ashmore Funds and the interests of our other shareholders arise, Mr. de Jong may not be disinterested. The concentration of ownership also may have the effect of delaying, preventing or deterring a change in control of our company, could deprive our shareholders of an opportunity to receive a premium for their ordinary shares as part of a sale of our company and might ultimately affect the market price of our ordinary shares.

We have granted to our current institutional shareholders certain rights to have their securities registered in accordance with the U.S. securities laws pursuant to the terms of our existing Amended and Restated Registration Rights Agreement.

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 been advised by Ashmore Investment Management Limited, or Ashmore, that its funds do not currently control other companies that currently operate in the same segments of the energy industry as we do. We have no ability to control, nor will we necessarily be aware of, whether Ashmore or any of our other shareholders will in the future acquire interests in companies that operate in the same businesses as us.

We are a Cayman Islands company. As such, shareholders may face difficulties in protecting their interests, and it may be difficult for them to enforce judgments against us and our directors and executive officers.

We are incorporated under the laws of the Cayman Islands. A majority of our current directors are not residents of the United States, and all of our operating assets, and we believe some of the assets of our directors and officers, are located outside the United States. As a result, it may be difficult for shareholders to effect service of process on us or those persons in the United States, or to enforce in the U.S. judgments obtained in U.S. courts against us or those persons based on civil liability provisions of the U.S. securities laws.

Our corporate affairs will be governed by our Amended and Restated Memorandum and Articles of Association, the Companies Law (as the same may be supplemented or amended from time to time) and the common law of the Cayman Islands. The rights of shareholders to take action against the directors and the fiduciary responsibilities of our directors to us under Cayman Islands law are to a large extent governed by the common law of the Cayman Islands. The common law of the Cayman Islands is derived in part from judicial precedent in the Cayman Islands and from English common law, the decisions of whose courts are of highly persuasive authority, but are not technically binding, on a court in the Cayman Islands. The Cayman Islands

has a less developed body of securities laws as compared to the United States and provides significantly less protection to investors. Moreover, it is doubtful whether courts in the Cayman Islands or the jurisdictions in which we operate will enforce judgments obtained in other jurisdictions, including the United States, against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in the Cayman Islands or Latin America against us or our directors or officers under the securities laws of other jurisdictions. In particular, we have been advised by Walkers, our legal advisors as to Cayman Islands law, that the United States and the Cayman Islands do not currently have a treaty providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters and that a final judgment for the payment of money rendered by any Federal or state court in the United States based on civil liability, whether or not predicated solely upon United States securities laws, would, therefore, not be automatically enforceable in the Cayman Islands and there is doubt as to the enforceability in the Cayman Islands, in original actions or in actions for the enforcement of judgments of the United States courts, of liabilities predicated solely upon United States securities laws.

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 in 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 registration statement.

History

Our largest shareholders are investment funds, the Ashmore Funds, directly or indirectly managed by Ashmore, an emerging markets investment manager. Ashmore is part of Ashmore Group plc, a company whose shares are traded on the London Stock Exchange. Although a number of investors own interests in the Ashmore Funds, the Ashmore Funds and their investment decisions are controlled by Ashmore and the Ashmore Funds are considered entities under common control.

Acquisition of Elektra Noreste, S.A. by certain Ashmore Funds

Elektra was formed in 1998 to own and operate certain power distribution facilities and related assets in Panama. On October 3, 2005, certain Ashmore Funds acquired 51.0% of Elektra’s voting and equity capital from Constellation Power, Inc., or Constellation Power, for a purchase price of approximately $88.0 million. Constellation Power transferred its interest in Elektra by selling to these Ashmore Funds 100.0% of its interest in one of its offshore holding companies, Constellation Power International Investments, Ltd., or CPI, the indirect holder of the 51.0% interest in Elektra.

As of December 31, 2007, 51.0% of Elektra’s common stock is owned by us, indirectly through a chain of subsidiaries, 48.25% is owned by the Panamanian government and 0.75% is owned by employees or held as treasury stock. Aside from its proportionate voting rights based on its common stock ownership, the Panamanian government’s only other right is the ability to select two out of the five members of Elektra’s board of directors.

Contribution of Enron Corporation’s international energy infrastructure businesses to Prisma Energy International Inc.

Enron Corporation, or Enron, and certain of its affiliates filed for protection pursuant to Chapter 11 of the U.S. Bankruptcy Code in December 2001. A plan of reorganization was confirmed by the bankruptcy court on July 15, 2004.

As part of the plan of reorganization, PEI was formed in June 2003 for the purpose of owning and, in certain circumstances, operating many of the international energy infrastructure businesses owned by Enron and its subsidiaries, principally in emerging markets. Under Enron’s plan of reorganization, the businesses transferred to PEI included certain of Enron’s non-U.S. Power Generation, transmission and distribution businesses, and natural gas and natural gas liquids transportation and distribution businesses.

Upon approval of the plan of reorganization by the bankruptcy court, PEI and Enron entered into a contribution and separation agreement, dated August 31, 2004, which provided for the contribution of certain equity interests, transferred contracts, transferred receivables and shared services assets between Enron and certain of its controlled affiliates, on the one hand, and PEI, on the other, in return for ordinary shares in PEI. The plan of reorganization contemplated that these shares would either be distributed to Enron’s unsecured creditors or sold to a third party. Most of the contributed assets were transferred to PEI between August 31, 2004 and November 30, 2004 in exchange for additional ordinary shares of PEI. Certain remaining assets were transferred to PEI in January and May 2006, in exchange for additional ordinary shares.

Formation of AEIL

On October 12, 2005, AEIL (originally known as Elektra International Limited), a Cayman Islands company, was formed by Ashmore to act as the holding vehicle for the energy-related assets owned at that time by the Ashmore Funds and to act as a platform to acquire PEI. Ashmore is a specialist fund manager focusing on emerging markets globally and looks at many investment opportunities in various industries. We believe that it decided to acquire PEI because all of PEI’s operations were in emerging markets and it represented an opportunity to make a sizeable investment meeting the Ashmore funds’ investment criteria.

In March 2006, certain Ashmore Funds transferred their interest in Elektra by contributing their collective ownership in CPI to AEI LLC (formerly known as Ashmore Energy International LLC), or AEI Delaware, a Delaware limited liability company, in return for 100.0% of the membership interests in AEI Delaware. All the membership interests in AEI Delaware were in turn contributed to AEIL by the Ashmore Funds in return for ordinary shares of AEIL. The Ashmore Funds are now our controlling shareholders, and we, through a controlled subsidiary, indirectly own 100.0% of CPI.

Interests in certain debt instruments related to a number of Argentine energy companies were also contributed by certain Ashmore Funds to AEIL in exchange for AEIL shares. These contributions occurred immediately after the contribution of Elektra was made. The debt interests related to certain of these Argentine companies, namely AES Ocean Springs, Ltd. (which held a controlling interest in EDEN, an Argentine electrical distribution company, through its equity interest in AESEBA S.A., or AESEBA), Compañía de Inversiones de Energía, S.A., or CIESA (which holds a controlling interest in Transportadora de Gas del Sur S.A., or TGS, an Argentine gas transportation company), and Gas Argentino S.A., or GASA (which holds a controlling interest in MetroGas S.A., or MetroGas, an Argentine natural gas distribution company), subsequent to contribution to AEIL have been or are expected to be exchanged for equity interests in such holding companies pursuant to various restructuring agreements upon receipt of all required governmental approvals. The debt interest in AES Ocean Springs, Ltd. was exchanged into equity interest in AESEBA on June 26, 2007, and such transaction is still subject to local anti-trust approval. The conversion of the CIESA debt interest is pending. On May 20, 2008, we sold our debt interests in GASA.

Acquisition of PEI by AEIL

In 2006, AEIL acquired PEI for a purchase price of approximately $1.8 billion from Enron and certain of its subsidiaries in two stages as follows:


	•	Stage 1 (completed May 25, 2006): AEIL acquired 24.26% of the voting capital and 49.0% of the economic interest in PEI;

	•	Stage 2 (completed September 7, 2006): AEIL acquired the remaining 75.74% of the voting capital and 51.0% of the economic interests.

The transaction was designed as a two-step transaction because of the need to obtain certain regulatory approvals and lender/partner consents, which approvals and consents were obtained between the completion of Stage 1 and Stage 2.

Legally, because of required regulatory approvals, AEIL was not permitted to, and did not control the PEI operating businesses between the completion of the first stage and the completion of the second stage of the acquisition, although AEIL had significant influence over PEI’s operating and financial policies as a result of its voting ownership rights and its ability to appoint three of seven directors and certain officers, including the chief executive officer. During that period, PEI remained controlled by Enron and its affiliates. PEI was consolidated with AEIL only upon the completion of the second step of the acquisition when AEIL acquired control of PEI.

AEIL’s Acquisition of a Controlling Interest in Promigas S.A. ESP

Prior to the completion of the first stage of AEIL’s acquisition of PEI, PEI held, through one of its wholly owned subsidiaries, 42.94% of the outstanding shares of Promigas S.A. ESP, or Promigas, a company listed on the Colombian Stock Exchange and one of Colombia’s leading energy companies with investments in natural gas transportation, natural gas distribution and retail fuel businesses.

At the time of the Stage 1 closing, under Colombian securities laws, transfers, direct or indirect, of 10% or more of the outstanding shares of a listed Colombian company had to be made pursuant to certain mandated offering/sale procedures. These procedures required the making of, among other things, certain applications and publications in Colombia. So as not to delay the Stage 1 closing of the rest of the PEI acquisition, immediately prior to such closing, in May 2006, PEI caused its wholly owned subsidiary to transfer, via a spin-off under Cayman law, 33.04% of the outstanding shares of Promigas, or the Subject Promigas Shares, to EMHC Ltd., another wholly owned subsidiary of PEI, or EMHC. Immediately following such transfer (and prior to the completion of the first stage of AEIL’s acquisition of PEI), PEI dividended all of the outstanding ordinary shares of EMHC to Enron and certain of its affiliates. Enron delegated to PEI its voting rights relating to the 33.04% of transferred shares, which enabled PEI to hold two out of five outstanding seats on the Promigas board of directors.

In September 2006, after the completion of the second stage of the acquisition of PEI by AEIL, EMHC solicited the Colombian Stock Exchange (Bolsa de Valores de Colombia) to conduct a public offer of the Subject Promigas Shares pursuant to a public auction procedure called a “Martillo.” The auction occurred on December 22, 2006 and PEI, through its wholly owned subsidiary AEI Colombia Ltd., bid $350 million for the Subject Promigas Shares in the auction and was successful in such bid. Accordingly, PEI once again had ownership of 42.94% of Promigas.

On December 27, 2006, PEI, through its wholly owned subsidiary AEI Colombia Ltd., subsequently acquired an additional 9.94% stake in Promigas from another holder of shares of Promigas pursuant to another Martillo auction overseen by and under the rules of the Colombian Stock Exchange and the Colombian Finance Superintendency (Superintendencia Financiera de Colombia). This second acquisition brought PEI’s total interest in Promigas to 52.88% and allowed PEI to gain a controlling interest in Promigas. Following completion of the second acquisition, we began consolidating Promigas into our financial statements. The purchase price for this 9.94% stake was $161 million.

Merger of AEIL and 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.

The following diagram sets out the significant events in our formation:

Our Recent Acquisitions

During 2007, we completed several acquisitions resulting in either an increase in our current equity investment or a new investment. See “Item 5. Operating and Financial Review and Prospects — Recent Developments” for additional information. We increased our equity investment in San Felipe, Operadora San Felipe, PQP and Corinto. Our new investments in 2007 were BMG, Delsur, EDEN, Tongda, Cálidda, JPPC, Chilquinta, Luz del Sur and Terpel’s acquisition of Repsol’s Chilean gasoline service stations.

From January 1, 2008 to the date of this registration statement, we have completed the additional transactions listed below.


	•	Promigas contributed its ownership interests in its wholly owned subsidiary Gazel to SIE, in exchange for additional shares of SIE on January 2, 2008. Promigas’ ownership in SIE has increased from 37.19% to 54%. SIE now owns 88.7% of Gazel through its subsidiary Terpel. We currently indirectly own 24.95% of Terpel and 24.95% of Gazel.

	•	Acquisition of an additional 59.77% interest in BMG and its subsidiaries, which was completed on January 30, 2008.

	•	Acquisition of a 50.00% interest in Luoyang. The acquisition of a 48.00% interest was completed on February 5, 2008 and an additional 2.00% interest was purchased on June 6, 2008.

	•	Promigas purchased additional interests in its affiliates Surtigas and Gases de Occidente on March 7, 2008 for $9 million and $40 million, respectively. Promigas’ ownership in these businesses has increased to 99.89% and 90.10%, respectively.

	•	Acquisition of a 100.0% interest in Tipitapa for $18 million on June 11, 2008. Tipitapa owns a 50.9 MW diesel electric generation facility located approximately 12 miles east of Managua, Nicaragua, which began operations in 1999.

	•	Acquisition of a 60.22% interest in DHA Cogen Limited, or DCL, for approximately $29 million in a series of transactions from July through January of 2009. DCL owns a 94 MW combined cycle electric generation plant and a 3 million gallons per day water desalination facility located in Karachi, Pakistan, which began operations in 2008.

	•	A subsidiary of the Company was awarded, on May 5, 2008, 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-fixed generating facility. A subsidiary of the Company also executed power purchase agreements to sell capacity and energy for 15 year terms.

	•	Acquisition of an 85% interest in Empresa Electrica de Generacion de Chilca S.A., or Fenix, a Peruvian company developing a 544 MW combined cycle power plant in Chilca, Peru on June 26, 2008.

	•	Acquisition of a 28.00% equity interest in Emgasud S.A., or Emgasud, an Argentine energy corporation focused on the electricity and gas industries on November 28, 2008. On December 23, 2008, we made a second capital contribution to Emgasud of $10 million which increased our ownership interest in Emgasud to 31.89%.

	•	On December 8, 2008, we signed an agreement with Centrans Energy Services, a Cayman Islands company, or Centrans, to contribute our respective interests in various Nicaragua power companies to a common holding company, Nicaragua Energy Holdings, a Cayman Islands company. This transaction closed on January 1, 2009, and currently we own 57.67% and Centrans owns 42.33% of Nicaragua Energy Holdings, which indirectly owns 100% of Corinto and Tipitapa and an interest in the Amayo wind project. In addition, we gave Centrans a call option that may be exercised at any time prior to December 8, 2013 to increase its interest in Nicaragua Energy Holdings up to 50%.

B. Business Overview

We manage, operate and own interests in essential energy infrastructure businesses in emerging markets across multiple segments of the energy industry, which we refer to in this registration statement as “our businesses.” Our company consists of 39 businesses which we aggregate into the following reporting segments: Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution, and Retail Fuel. For the year ended December 31, 2007, we generated consolidated revenues of $3.2 billion, consolidated operating income of $577 million and consolidated net income of $131 million. For the nine months ended September 30, 2008, we generated consolidated revenues of $7.2 billion, consolidated operating income of $653 million and consolidated net income of $125 million.

We are diversified across 20 countries in Latin America, Europe and Asia. The businesses in which we own interests include approximately:


	•	104,000 miles of power distribution and transmission lines;

	•	2,215 MW of electric power generation capacity;

	•	4,900 miles of natural gas and gas liquids transportation pipelines;

	•	20,500 miles of natural gas distribution pipeline networks;

	•	6.6 million retail customers, including approximately 4.3 million electric power customers and 2.3 million natural gas customers;

	•	2,327 owned and affiliated gasoline and CNG service stations; and

	•	14,250 employees.

We currently operate in emerging markets in Latin America, Europe and Asia. Most markets in which we operate have experienced significant growth and we expect electricity and gas consumption to continue to grow at a faster rate in these economies than in more developed countries. According to the U.S. Department of Energy’s International Energy Outlook 2008, published in June 2008, total energy demand in economies which are not members of the Organisation for Economic Co-operation and Development, or OECD, is expected to grow by 85% between 2005 and 2030 (3.4% average annual growth rate), or by 187 quadrillion BTU. In particular, electricity generation in non-OECD countries over this period is forecasted to grow at 4.0% per year on average, three times faster than in developed economies. To meet these growth forecasts, total energy generation is expected to grow by 16% over the next five years, according to the U.S. Department of Energy. We estimate that new Power Generation capacity of approximately 400 GW will be necessary during the same period to meet that growth forecast. We expect, based on this report, that approximately 67% of the incremental capacity in non-OECD countries will be installed in Asia, including approximately 43% in China. Due to the financial constraints on many of the governments in emerging markets and their ability to complete large-scale projects in a timely, cost-effective manner, we believe that a significant portion of this new investment capital will need to be provided by private, non-governmental entities. The expected growth provides us with a significant opportunity to further grow and diversify our energy infrastructure businesses.

Our Competitive Strengths

We believe that the following strengths distinguish us from our competitors and are critical to our continuing success.

Well-positioned and diversified across multiple segments of the energy industry

Our established presence across key segments of the energy industry in natural gas processing, transportation and distribution and electricity generation and distribution, together with our knowledge of multiple markets, allows us to effectively identify and capitalize on business opportunities.

Operational excellence

We have had a consistent track record of responsible, efficient and safe operation at our businesses. Operationally, many of our assets have surpassed both U.S. and local industry standards and contractual requirements in recent years. We had a 2008 company-wide power plant reliability of 97.58%, pipeline reliability of 99.99% and gas processing reliability of 99.72%. Our Lost Time Incident Rate, or LTIR, for all

our businesses was 0.30 in 2007, well below the U.S. industry average of over 1.1 according to the U.S. Bureau of Labor Statistics, while our LTIR for 2008 was 0.38. Some of our businesses have been recognized with operational excellence awards by their peers and regulators. In addition, our largest subsidiary, Elektro, is consistently one of the market leaders in Brazil in operating and efficiency statistics.

Strong contracted and regulated cash flows to support growth

We believe that our businesses are able to generate stable and predictable cash flows which are predominantly derived from long-term contracts and regulated services. In addition, our diversification across multiple regional markets, countries within those regions and multiple segments contributes to the stability and predictability of our cash flows. Our long-term contracts and regulated operations additionally limit the exposure of our businesses to fluctuations in commodity prices. Our stable and predictable cash flows allow us to reinvest and grow our existing businesses and support our growth strategy.

Exclusive focus in emerging markets

AEI operates exclusively in emerging markets. We believe that our dedication to meeting the energy infrastructure needs of emerging markets allows governments, regulators and local partners to recognize our commitment to the long-term success of our businesses in these countries, as our investments are not subject to the risk of capital redeployment to developed markets. We believe that our focus on emerging markets therefore strengthens our ability to forge partnerships, recognize opportunities and build long-term, mutually beneficial relationships in the countries where we operate.

Demonstrated capability to execute strategy

Since January 1, 2007, we have successfully identified, evaluated and completed acquisitions of interests in 12 new businesses and we have increased our ownership in seven of our existing businesses. During this same period, we have divested our interests in two businesses. These transactions have originated in many cases through our local relationships. Among the acquisitions we have consummated are deals involving complex transactions and funding structures, and multiple regulatory and/or other third party consents. In some instances, our financing experience and our operating companies’ local expertise have allowed us to better assess risks and conduct more efficient due diligence compared to our competition. We have demonstrated our ability to complete these transactions in a timely manner. Our disciplined approach has also resulted in some opportunities not being pursued after preliminary assessments indicated that they did not meet our target risk-adjusted returns. We believe this approach will continue to enable us to be well positioned in the origination, structuring and implementation of value-creating transactions to support our growth plans.

Strong local presence with experienced management team and strong local brands

We believe that the experience of our management team provides us with significant advantages in the management and expansion of our operations. Our management team, including the executives in each of the markets in which we operate, has extensive experience in the energy industry, with an average of approximately 20 years of service. Additionally, we have developed strong working relationships with regulators and other industry participants in the markets in which we operate. We believe that the knowledge, experience and expertise of our local management with respect to the business environment and regulatory framework allows us to effectively collaborate with regulators and to align our strategies with the needs of the markets in which we participate. In addition, we believe our strong local brands further enhance the recognition our businesses receive from local stakeholders.

Our Strategy

Our strategy is to own and operate essential energy infrastructure assets in emerging markets and to grow our business. Our growth is generated in part by the organic expansion of our business, which is driven by the demand for energy infrastructure in our markets and market penetration of the services we provide, as well as a combination of acquisitions and greenfield development, which we seek to execute in a disciplined manner that creates shareholder value. We have clear criteria to prioritize growth opportunities designed to allocate capital to the projects that present the best risk-adjusted returns. These opportunities may reinforce our existing business lines, result in synergies with existing operations, and/or further enhance our diversification

from a geographical, business segment and risk standpoint. Our focus in any given market is to establish critical mass to become a key participant in the market, successfully manage the relationships with key stakeholders and play an important role in its development. We prefer investments that provide operational control, the ability to exert significant influence or strategic non-control positions that offer the opportunity for control or influence over the investment in the future.

The following are our key areas of focus to execute our strategy:


	•	maximizing the financial performance of our existing businesses;

	•	applying technical, environmental, health and safety best practices to maximize operational performance of our businesses;

	•	developing and maintaining our strong relationships with local regulators, governments and communities through active involvement in the regulatory process and the maintenance of open communication channels;

	•	maintaining a flexible financial profile through moderate levels of debt and reinvestment of cash flow to deliver growth;

	•	leveraging our strong management teams and their relationships and market knowledge to pursue opportunities to grow the business; and

	•	integrating new businesses into our platform and sharing best practices to maximize operating and financial performance.

To identify, evaluate and develop these growth opportunities, we rely on a combination of business development professionals and teams with significant experience in operating energy businesses in our markets. Greenfield development projects, which involve the origination, design, engineering and construction of new infrastructure assets, require years to realize and involve siting, permitting, sourcing, marketing, financing and ultimately operating activities. Currently, we are primarily pursuing several greenfield development opportunities in our Power Generation segment in both the markets where we currently operate and other emerging markets, including advanced opportunities in Guatemala and Peru. Additionally, our business Luoyang has obtained key regulatory approvals in China for a 600 MW expansion next to the existing 270 MW power plant. See “— Power Generation — Power Generation Growth” and “— Power Generation — Luoyang Sunshine Cogeneration Co., Ltd. (Luoyang)” for additional information.

Challenges in Implementing Our Strategy

We face numerous challenges implementing our strategy, including:


	•	our revenues are dependent upon economic growth in general and growth in our customer base and in energy demand in particular;

	•	we operate in emerging markets, where we are exposed to political and regulatory risks, including the possibility of nationalization and the fact that tariffs are set by governmental agencies;

	•	we are affected by trends in energy consumption and fluctuations in availability and cost of fuel, labor, and supplies; and

	•	the fact that some of our growth is dependent on the expansion of existing businesses, the integration of newly acquired businesses, which we have no history of owning or operating and successful greenfield developments.

See “Item 3. Key Information — D. Risk Factors” for a detailed discussion of these and other risks that we face.

Our Businesses

We own interests in 39 businesses which operate in 20 countries. In all but five of these businesses, we retain operating control or maintain joint control of the business. The tables below list our businesses and describe the five reportable segments in which they operate. Three of our businesses operate across multiple business segments through various subsidiaries. The Cuiabá Integrated Project operates in two of these segments in Bolivia and Brazil. Promigas, a Colombian company which holds interests in 13 businesses, and

Emgasud, an Argentine Company, each operates across three of these segments. Each of our businesses has related entities, such as holding companies, operating companies and marketing companies, the most significant of which are discussed in the description of the relevant business.

Business Segments

Our Power Distribution businesses deliver electricity to customers in their respective service areas. Most of these businesses operate in a designated service area defined in a concession agreement. All of the concession agreements and/or subsequent regulations provide for a pass-through of the main non-controllable cost items, namely power purchases and transmission charges. Our tariffs are reviewed by regulators periodically and adjusted to allow us to recover reasonable costs, incentivize us to continue cost reductions and make needed capital investments and earn a regulated rate of return. These six businesses operate and maintain an electric distribution network under the concession, and bill customers directly via consumption and/or demand charges. See our financial statements attached hereto for a discussion of revenue for the years ended 2006 and 2007 and the nine-months ended September 30, 2008, for each business segment described below.


Power Distribution
					AEI Ownership										Adjusted
					Interest (Direct										Contribution
					and Indirect) as				Approximate				GWh		Percentage
			Start of		of December 31,			Operating	Number of		Network		Sold		(Operating
Business	Country		Operations⁽¹⁾		2007			Control⁽²⁾	Customers		in Miles		(2007)⁽³⁾		Income)⁽⁴⁾
									(Thousands)

Elektro		Brazil		1998		99.68	%	Yes		2005		64,478		13,336		49.9	%
Elektra		Panama		1998		51.00	%	Yes		328		5,154		2,193		5.3	%
EDEN⁽⁵⁾		Argentina		1997		90.00	%	Yes		315		10,745		2,420		1.1	%
Delsur		El Salvador		1996		86.41	%	Yes		299		4,037		1,113		1.2	%
Chilquinta		Chile		1981		50.00	%	Joint with Sempra		465		4,921		2,928		0.2	%⁽⁶⁾
Luz del Sur⁽⁷⁾		Peru		1994		37.94	%	Joint with Sempra		782		11,169		5,548		N/A

										4,189		100,560		27,538		57.7	%


(1)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.

(2)		“Operating Control” means that AEI has either a controlling interest in the business or operates the business through an operating agreement.

(3)		Represents GWh sold plus GWh transmitted through the business’ service territory on behalf of others.

(4)		“Adjusted Contribution Percentage (Operating Income)” means the business’ contribution to AEI in 2007 as measured by operating income. The contribution percentages exclude Vengas, BLM and $(134) million from the Headquarters and Other segment, which includes inter-/intra-segment eliminations.

(5)		Subject to local anti-trust approval.

(6)		The contribution percentage of Chilquinta includes Luz del Sur.

(7)		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 Power Generation businesses generate and sell wholesale power to large off-takers. Most of the businesses in this segment sell substantially all of their generating capacity under long-term contracts, primarily to state-owned entities. These businesses convert fuel to electricity. Most of our off-take agreements are structured to minimize our business exposure to commodity fuel price volatility. Our 11 businesses in this segment are listed in the table below.


Power Generation
						AEI
						Ownership
						Interest (Direct							Adjusted
						and Indirect)				Installed			Contribution
						as of				Generating			Percentage
			Start of			December 31,			Operating	Capacity			(Operating
Business	Country		Operations⁽¹⁾			2007			Control⁽²⁾	(MW)		Fuel Type	Income)⁽³⁾

Trakya		Turkey		1999			59.00	%	Yes		478	Natural Gas		7.1	%
Cuiabá-EPE		Brazil		1999			50.00	%	Joint with Shell		480	Natural Gas		0.0	%⁽⁴⁾
Luoyang⁽⁵⁾		China		2006			—		Yes		270	Coal		—
PQP		Guatemala		1993			100.00	%	Yes		234	Bunker Fuel		6.5	%

San Felipe		Dominican Republic		1994			100.00	%	Yes		180	Diesel Oil/ Bunker Fuel		3.0	%
ENS		Poland		2000			100.00	%	Yes		116	Natural Gas		2.4	%
Subic		Philippines		1994			50.00	%	Yes		116	Bunker Fuel		1.7	%
Corinto		Nicaragua		1999			50.00	%	Yes		70	Bunker Fuel		0.5	%
Tipitapa⁽⁶⁾		Nicaragua		1999			—		Yes		51	Bunker Fuel		—
JPPC		Jamaica		1996			84.40	%	Yes		60	Bunker Fuel		0.4	%
DCL⁽⁷⁾		Pakistan		2008			—		Yes		94	Natural Gas		—
Emgasud⁽⁸⁾		Argentina		1991	⁽⁹⁾		—		No		66	Natural Gas		—

											2,215			2.4	%⁽⁴⁾


(1)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.

(2)		“Operating Control” means that AEI has either a controlling interest in the business or operates the business through an operating agreement.

(3)		“Adjusted Contribution Percentage (Operating Income)” means the business’ contribution to AEI in 2007 as measured by operating income. The contribution percentages exclude Vengas, BLM and $(134) million from the Headquarters and Other segment, which includes inter-/intra-segment eliminations.

(4)		EPE’s contribution to operating income was (19.2%).

(5)		On February 5, 2008, we acquired a 48.00% interest in Luoyang. On June 6, 2008, we acquired an additional 2.00% interest in Luoyang.

(6)		On June 11, 2008, we acquired a 100.00% interest in Tipitapa.

(7)		On July 18, 2008, we acquired a 48% interest in DCL. Since the additional acquisition, we have executed additional share subscription agreements that have resulted in an increase in our ownership to 60.22%.

(8)		On November 28, 2008, we acquired a 28.00% equity interest in Emgasud. On December 23, 2008 we made a second capital contribution thereby increasing our ownership interest to 31.89%.

(9)		Operations commenced in 1991, however, power generation operation began in 2008.

Our Natural Gas Transportation and Services businesses provide transportation and related services for upstream oil and gas producers and downstream utilities and other large users who contract for capacity. Our businesses in this segment own and operate natural gas and liquids pipelines and gas processing facilities. The rates charged by these businesses are typically regulated. Our 13 businesses in this segment are listed below.


Natural Gas Transportation and Services
					AEI Ownership										Adjusted
					Interest (Direct and										Contribution
					Indirect) as of				2007						Percentage
			Start of		December 31,			Operating	Throughput			Network			(Operating
Business	Country		Operations⁽¹⁾		2007			Control⁽²⁾	(mmcfd)⁽³⁾			in Miles			Income)⁽⁴⁾

Promigas						52.13	%
Promigas Pipeline		Colombia		1974		52.13	%	Yes⁽⁵⁾		305			1,297			6.2	%
Transmetano		Colombia		1993		50.87	%	Yes⁽⁵⁾		35			93			1.4	%
GBS		Colombia		1999		49.17	%	Yes⁽⁵⁾		12			196			0.9	%
Centragas		Colombia		1996		13.03	%	Yes⁽⁵⁾		155			458			0.6	%
PSI		Colombia		2003		51.95	%	Yes⁽⁵⁾		305			N/A	⁽⁶⁾		0.4	%
Transoccidente		Colombia		1998		35.57	%	Yes⁽⁵⁾		34			7			0.1	%
Transoriente		Colombia		1994		12.76	%	No		12			98			0.1	%
Cuiabá
GOB		Bolivia		2001		50.00	%	Joint with Shell		20			225			2.0	%
GOM		Brazil		2001		50.00	%	Joint with Shell		20			175			2.4	%
		Brazil/
TBS		Bolivia		1999		50.00	%	Joint with Shell		N/A	⁽⁷⁾		N/A	⁽⁷⁾		0.9	%
Accroven		Venezuela		2001		49.25	%	Joint with Williams		763			N/A	⁽⁸⁾		1.9	%
Bolivia-to-Brazil Pipeline
GTB⁽⁹⁾		Bolivia		1999		29.75	%	Joint with Shell		987			346			3.0	%⁽¹⁰⁾
TBG⁽⁹⁾		Brazil		1999		7.00	%	No		987			1,611			N/A

										3,635			4,506			19.9	%


(1)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.

(2)		“Operating Control” means that AEI has either a controlling interest in the business, operates the business through an operating agreement or has operating control through its operating control of Promigas.

(3)		Includes both gas and liquids.

(4)		“Adjusted Contribution Percentage (Operating Income)” means the business’ contribution to AEI in 2007 as measured by operating income. The contribution percentages exclude Vengas, BLM and $(134) million from the Headquarters and Other segment, which includes inter-/intra-segment eliminations, and include Transredes.

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

(6)		PSI provides services related to the drying and compression of natural gas.

(7)		TBS is a natural gas shipper which purchases natural gas in Bolivia and resells it to EPE.

(8)		Accroven operates a natural gas liquids extraction, fractionation, storage and refrigeration facility.

(9)		Includes the percentages of GTB and TBG previously owned through Transredes. We currently own 17.65% of GTB and 4.27% of TBG.

(10)		Includes the percentages contributed by TBG and Transredes.

Our Natural Gas Distribution businesses distribute and sell gas to retail customers. These businesses operate networks of gas pipelines, deliver gas directly to a large number of residential, industrial and commercial customers and directly bill these customers for connections and volumes of gas provided. These businesses are regulated and typically operate under long-term concessions giving them an exclusive right to deliver gas in a designated service area. Our six businesses in this segment are listed in the table below.


Natural Gas Distribution
					AEI
					Ownership
					Interest											Adjusted
					(Direct and						Approximate					Contribution
					Indirect) as						Number of					Percentage
			Start of		of December 31,			Operating			Customers			Network in		(Operating
Business	Country		Operations⁽¹⁾		2007			Control⁽²⁾			(Thousands)			Miles		Income)⁽³⁾

Promigas						52.13	%
Surtigas⁽⁴⁾		Colombia		1968		49.85	%		Yes	⁽⁵⁾		426			4,740		5.1	%
Gases de Occidente⁽⁴⁾		Colombia		1992		41.46	%		Yes	⁽⁵⁾		573			3,798		6.0	%
Gases del Caribe		Colombia		1966		16.16	%		No			858	⁽⁶⁾		6,120		2.0	%⁽⁶⁾
Cálidda		Peru		2002		80.85	%		Yes			8			310		0.8	%
BMG⁽⁷⁾		China		1988		10.23	%		Yes			101			1,118		—
Tongda		China		1998		100.00	%		Yes			114			1,223		0.0	%⁽⁸⁾

												2,082			17,309		13.0	%⁽⁸⁾


(1)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.

(2)		“Operating Control” means that AEI has either a controlling interest in the business, operates the business through an operating agreement or has operating control through its operating control of Promigas.

(3)		“Adjusted Contribution Percentage (Operating Income)” means the business’ contribution to AEI in 2007 as measured by operating income. The contribution percentages exclude Vengas, BLM and excludes $(134) million from the Headquarters and Other segment, which includes inter-/intra-segment eliminations.

(4)		On March 7, 2008, Promigas purchased additional interest in Surtigas and Gases de Occidente, which increased our ownership to 52.07% and 46.97%, respectively.

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

(6)		Includes its consolidated subsidiaries, Gases de La Guajira, Gases del Quinido, Gases del Risaralda and Gas Natural del Centro.

(7)		On January 30, 2008, we acquired an additional 59.77% interest in BMG, which increases our ownership to 70.00%.

(8)		Tongda’s contribution to operating income is (0.9)%.

Our Retail Fuel businesses primarily distribute and sell liquid fuels and compressed natural gas (CNG) to retail customers. In addition to owning, licensing and operating outlets, these businesses own fleets of bulk-fuel distribution vehicles. Our two businesses in this segment are listed in the table below.

Retail Fuel

AEI

Ownership

Interest

(Direct and

Adjusted

Indirect) as of

Contribution

Start of

December 31,

Operating

Product

Volume Sold

Percentage

Business

Country

Operations⁽¹⁾

2007

Control⁽²⁾

Sold

(2007)

(Operating Income)⁽³⁾

Promigas

52.13

Gazel⁽⁴⁾

Colombia, Chile,
Mexico, Peru

1986

51.93

Yes

Compressed
Natural Gas

11,758
mmscf

4.9

SIE

19.39

Terpel⁽⁴⁾

Colombia, Chile,
Ecuador, Panama

1968

15.07

Gasoline,
Diesel, Jet
Fuel,
Lubricants

1,424 million
gallons

2.0

6.9


(1)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.

(2)		“Operating Control” means that AEI has either a controlling interest in the business, operates the business through an operating agreement or has operating control through its operating control of Promigas.

(3)		“Adjusted Contribution Percentage (Operating Income)” means the business’ contribution to AEI as measured by operating income. The contribution percentages exclude Vengas, BLM and $(134) million from the Headquarters and Other segment, which includes inter-/intra-segment eliminations.
(4)		On January 2, 2008, Promigas contributed its ownership interests in its wholly-owned subsidiary Gazel to SIE in exchange for additional shares of SIE. SIE subsequently transferred Gazel to its subsidiary Terpel. We currently own indirectly 24.95% of Terpel and 24.95% of Gazel.

AEI Services LLC, a Delaware limited liability company and our wholly-owned direct subsidiary, is located in Houston, Texas. AEI Services LLC provides us with various management services, including financial, accounting, legal and tax services.

Power Distribution

Segment Overview

Our Power Distribution businesses deliver electricity to customers in their respective service areas. Most of these businesses operate in a designated service area defined in a concession agreement. All of the concession agreements and/or subsequent regulations provide for a pass-through of the main non-controllable cost items, namely power purchases and transmission charges. Our tariffs are reviewed by regulators periodically and adjusted to allow us to recover reasonable costs, incentivize us to continue cost reductions and make needed capital investments and earn a regulated rate of return. These businesses operate and maintain an electric distribution network under the concession, and bill customers directly via consumption and/or demand charges.

Information about our businesses in this segment is summarized in the table shown below:


			AEI
			Ownership				Scheduled
			Interest				Termination
			(Direct and				Date of	Approximate
			Indirect) as				Principal	Number of		Approximate				GWh
			December 31,			Operating	Concession	Customers		Number		Network		Sold
Business	Country		2007			Control⁽¹⁾	Agreement	(thousands)		of Employees		in Miles		(2007)⁽²⁾

Elektro		Brazil		99.68	%	Yes	2028, extendable for 30 years		2005		2,696		64,478		13,336
Elektra		Panama		51.0	%	Yes	Expires in 2012, then subject to new bid		328		546		5,154		2,193
EDEN		Argentina		90.0	%⁽³⁾	Yes	2092		315		726		10,745		2,420
Delsur		El Salvador		86.41	%	Yes	Terminates only if Delsur breaches agreement		299		285		4,037		1,113
Chilquinta		Chile		50.0	%	Joint with Sempra	Indefinite; may be revoked if Chilquinta fails to meet certain quality and safety standards		465		544		4,921		2,928
Luz del Sur		Peru		37.94	%⁽⁴⁾	Joint with Sempra	Indefinite; terminates only if Luz del Sur breaches agreement		782		670		11,169		5,548

									4,189		5,461		100,560		27,538


(1)		“Operating Control” means that AEI either has a controlling interest in the business or operates the business through an operating agreement.

(2)		Represents GWh sold plus GWh transmitted through the business’ service territory on behalf of others.

(3)		Subject to local anti-trust approval.

(4)		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.

The power distribution segment accounted for 52.4% of our net revenues, 52.4% of our operating income and 54.8% of our Adjusted EBITDA in 2007.

Elektro Eletricidade e Serviços S.A. (Elektro)

Overview

Our subsidiary, Elektro, is the eighth largest electricity distribution company in Brazil and the third largest, among peers, in the state of São Paulo. Elektro was created through a spin-off of the power distribution business of Companhia Energética de São Paulo in January 1998 pursuant to a national power sector privatization program. We indirectly control 99.68% of the economic interests and 99.97% of the voting rights of Elektro. The remaining shares are publicly traded on the São Paulo Stock Exchange under the symbols “EKTR3” for its ordinary shares and “EKTR4” for its preferred shares. Elektro is regulated by the Brazilian Securities and Exchange Commission (Comissão de Valores Mobiliários) and, as a regulatory distribution concessionaire, by ANEEL. In 2007, Elektro recognized revenues of $1,239 million.


	As of and for the Year Ended December 31,
	2005		2006		2007
	Millions of dollars (U.S.) except GWh, customers and miles

Customers at year end (thousands)		1,904		1,954		2005
Energy sales (GWh)		9,455		9,868		10,093
Operating income	$	268	$	332	$	332
Depreciation and amortization	$	33	$	60	$	115
Net debt⁽¹⁾	$	144	$	135	$	229
Network length (miles)		61,229		62,678		64,478


(1)		See “Non-GAAP Financial Measures” and “Item 3. Key Information — A. Selected Financial Data.” Net debt as indicated in the table above is reconciled below:


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	376		$	415		$	414
Less
Cash and cash equivalents		(212	)		(237	)		(130	)
Current restricted cash		(18	)		(23	)		(25	)
Non-current restricted cash		(2	)		(20	)		(30	)

Net debt	$	144		$	135		$	229

Concession and Contractual Agreements

Elektro holds a 30-year renewable concession from ANEEL covering 223 municipalities in the state of São Paulo, which is the most highly urbanized and industrialized state in Brazil, accounting for 33.9% of Brazilian GDP and 30.5% of national electricity consumption in 2007, and five municipalities in the State of Mato Grosso do Sul. Elektro’s concession area encompasses 46,080 square miles and has a population of approximately 5.5 million.

Elektro’s concession agreement, the first term of which expires in 2028, provides exclusive distribution rights within the concession area. We may 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 fiscal and social obligations required by law.

Tariffs

Tariffs for Brazilian power distribution companies are reviewed by ANEEL periodically. Elektro has reviews every four years, and its last review was in August 2007. During this review, Elektro’s tariffs, considering all customer segments, were reduced by 20.65%. This reduction reflects the high returns that Elektro had been able to achieve during the last four years since the 2003 tariff review, primarily due to

efficiency gains as well as higher market growth and favorable changes in the sales mix, with higher increases in consumption in the higher tariff residential and commercial segments. The four-year reviews reset the tariffs to compensate for Elektro’s capital, operational and administrative costs, investments to maintain the existing assets, plus a pass-through of non-controllable costs, including energy purchases and sector charges.

ANEEL uses a model distribution company as its basis for operational and administrative cost allowances. For Elektro, there may be an adjustment in the operations and maintenance cost allowance in 2009 due to ongoing regulatory changes in the model distribution company, a mechanism used by the regulator to calculate reasonable reimbursable costs. Capital costs and depreciation expenses are determined based on a regulated asset base calculated at replacement costs of Elektro’s assets. Tariffs are also adjusted annually for inflation of controllable costs adjusted by the X factor, and to pass through adjustments to non-controllable 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 last tariff readjustment occurred in August 2008 and increased the average tariff by 11.63%. Under its concession, Elektro is also entitled to an extraordinary tariff review to restore the economic equilibrium if significant macroeconomic events or changes in law alter its cost and revenue structure.

The pass through cost methodology also contributes to LDCs gains with respect to recovering price variations for non-controllable costs, or Parcel A costs, during the 4 year cycle between each tariff review. Parcel B is the portion of the distribution company’s revenues that covers its controllable costs and remuneration over the regulatory asset base. If the MWh sales are higher than forecasted by the LDC, gains would result and would be captured on Parcel B, due to the Parcel B calculation formula, as per the concession contract. Nevertheless, losses may also result if the MWh is lower than forecasted.

ANEEL has indicated that Parcel A costs should be neutral, meaning that it should not cause any gains or losses to the LDCs. In September 2008, ANEEL issued a technical note proposing changes to adjust these costs. The resolution will be submitted to the Ministry of Mines and Energy once the methodology is declared effective by the Ministry.

Customer Base

Elektro serves approximately two million customers. Over the past five years, Elektro has experienced a 2.5% average annual growth rate of its customer base. Additionally, electricity consumption in Elektro’s concession area has grown 4.4% per year during the past three years. Approximately 99% of Elektro’s revenue base is generated through regulated business, with the majority of the customer base composed of commercial, small and mid-sized industrial and residential customers. Elektro’s large and fragmented concession area results in a diversified customer base which operates in different sectors of the economy, thus mitigating Elektro’s exposure to economic cycles. Elektro has limited customer concentration, as its 30 largest customers represent only 8.4% of total 2007 GWh sales and 5.9% of total 2007 revenues.

The following table sets forth the average number of customers by category for the periods indicated.

Number of Customers


							Weighted
							Average
							Annual Growth
	As of December 31,						2007/2005
Customer Type	2005		2006		2007		(%)

Residential		1,637,410		1,674,743		1,712,012		2.3
Commercial		129,531		131,522		133,693		1.6
Industrial		21,623		21,475		21,833		0.5
Government		18,767		19,432		20,041		3.3
Rural		97,112		107,035		117,314		9.9

Total		1,904,443		1,954,207		2,004,893		2.6

Sales by Types of Customer


																Average Annual
	For the Year Ended December 31,															Growth 2007/2005
Customer Type	2005					2006					2007					%
	Millions of dollars (U.S.) except GWh
				GWh					GWh					GWh				GWh

Residential	$	504			2,962	$	618			3,060	$	704			3,184		18.3		3.7
Commercial		203			1,308		256			1,379		296			1,490		20.9		6.8
Industrial		354			3,288		445			3,348		469			3,464		15.4		2.6
Government		113			1,001		138			1,004		150			1,024		15.7		1.2
Rural		65			742		80			770		90			809		18.0		4.4
Other revenues/taxes		(300	)		154		(507	)		306		(514	)		123		35.2		19.3
Total net revenues — Elektro		939			9,455		1,031			9,868		1194			10,094		12.8		3.3
EKCE⁽¹⁾		33			1,204		49			1,338		45			986		20.6		(7.6	)

Total net revenues — consolidated	$	972			10,659	$	1,080			11,206	$	1,239			11,080		13.0		2.0


(1)		EKCE’s results are consolidated into Elektro’s U.S. GAAP financial results.

Under Brazilian regulations, customers with demand higher than 3 MW may elect to become “free customers.” Free customers can purchase energy directly from marketing companies and/or generating plants and pay wheeling charges to Elektro. In addition to free consumers, certain consumers with capacity equal to or greater than 500 kW, or special consumers, may choose to purchase energy in the free market, subject to certain terms and conditions. These special consumers may only purchase energy from (i) small hydroelectric power plants with capacity up to 30,000 kW, and (ii) renewable energy generators (solar, wind and biomass enterprises) with capacity injected in the system up to 30,000 kW. As of December 2007, 38 customers had left Elektro’s regulated market for the free market and 11 potential free customers remain with Elektro. Our marketing company, EKCE — Elektro Comercializadora de Energia Ltda., sells energy to free customers. Elektro charges each free customer within its service concession area a distribution fee to use its distribution network.

Power Supply

All of 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) though bilateral contracts which were signed before the 2004 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 account for about 27% of Elektro’s power supply. 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 must contract 100% of their energy needs through federally regulated public auctions. The power purchase agreements resulting from these auctions are non-negotiable 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 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. Amounts 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 in 2008 and 2009, when the limit will be 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 — CCEE). 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, thirty-year term contracts with new hydro power plants and fifteen-year term contracts with new thermal power plants. With these purchases, Elektro believes it has met its forecasted energy needs through the year 2012.

Operations

Elektro has extensive experience in power distribution operations management, including the management of a modern call center and an operations dispatch center. Elektro’s operations are centralized and integrated into its corporate headquarters in the city of Campinas, state of São Paulo. Elektro was one of the first electricity distributors in Brazil to achieve significant cost savings from fully centralized operations. The automation of Elektro’s customer interactions through the Elektro website in 2007 reduced demand on its call center enabling further cost reductions. In addition, Elektro has certifications under ISO 9001 (call center and input processing and output of technical and commercial indicators), ISO 14001 (for four substations) and OHSAS 18001.

Elektro is recognized as one of the best electricity distribution businesses in Brazil compared to peer companies based on operating and efficiency measures, despite its large and non-contiguous concession area, and has been repeatedly recognized in Brazil for social responsibility and human development. Elektro was awarded the “Best LDC” in Brazil award from the Brazilian Power Distribution Companies Association (Associação Brasileira de Distribuidoras de Energia Elétrica) in 2004, 2005 and 2007, the Best in Operations Management award in 2004, 2006, 2007 and 2008, the Best in Social Responsibility award in 2007 and the Best in Customer Service award in 2007. In 2008, Elektro received the Award for Customer Satisfaction (IASC) in the category of “Southeast Region Having More Than 400,000 Consumer Units” from ANEEL. Elektro has also received awards for achieving the highest safety levels in the industry in 2001, 2002 and 2005 and for Best Economic and Financial Performance in 2006 from the Brazilian Power Distribution Companies Association (Associação Brasileira de Distribuidoras de Energia Elétrica). In 2008, Elektro received the first place award for its Values and System of the Management of Knowledge project, from the COGE Foundation and, the magazine Exame recognized Elektro, for the fourth consecutive year, as one of the top 20 companies acting to support sustainability.

Elektro has 119 substations, 2,941 MVA of installed transformation power with over 63,634 miles of distribution lines and 844 miles of transmission lines and serves a 2,199 MW peak load. Elektro has eight regional offices and technical teams in 101 strategic locations for services, including the restoration of electricity service, maintenance of the distribution network and other commercial services.

Elektro has historically maintained outages at low levels as shown in the table below:


	For the Year Ended December 31,
	2005		2006		2007

FEC (number per customer per year)		6.6		6.7		6.4
DEC (hours per customer per year)		9.1		10.2		9.4

Efficiency measures implemented by Elektro since privatization in 1998 include reduction of employee headcount from 2,757 at the time of privatization to 2,696 as of December 31, 2007, despite the increase of about 518,000 customers. The collective bargaining agreement will expire in May 2009. Relations with the

union have been constructive and there have been no work stoppages. Elektro has successfully implemented a corporate-wide resource planning system and modern operations management, billing and telecommunications systems. Elektro has maintained its focus on a measurement inspection program in order to control fraud and replace defective equipment, recovering 124.5 GWh in 2006 and 80.3 GWh in 2007. Compared to other large power distributors in Brazil, Elektro was ranked second for lowest energy losses in 2006.

Electricity supply to rural customers has been an important issue for the Brazilian government. In November 2003, the Brazilian government announced a long-term plan in order to provide energy to 12 million people in rural areas of Brazil. Pursuant to the mandatory program Light for All (Luz para Todos), Elektro has connected over 33,500 new customers since November 2004 (over 9,400 in 2007 plus an additional 3,267 in that year through rural universalization) and connected approximately 7,600 new rural customers in 2008 and currently plans to connect approximately 7,300 new rural customers in 2009. Elektro has invested $69.4 million in this program from November 2004 until December 2007. Financing covers approximately 45% of these capital expenditures, with 30% provided by the Brazilian Energy Development Account (Conta de Desenvolvimento Energético), 10% provided by Brazilian government funding and 15% from Elektro’s own cash.

Financing

Elektro finances its capital expenditures through subsidized financing sources available in the Brazilian financial market such as BNDES and Eletrobrás. All of Elektro’s financing is denominated in local currency to match its cash flows.

In the last quarter of 2007, Elektro redeemed part of the non-convertible debentures in the amount of $162 million.

In March 2008, Standard & Poor’s upgraded Elektro’s rating to brAA, one of the highest Standard & Poor’s ratings in the electricity distribution sector in Brazil. Standard & Poor’s also upgraded the rating to brAA+ for Elektro’s non-convertible debentures.

Elektra Noreste, S.A. (Elektra)

Overview

Our subsidiary Elektra is the second largest electricity distribution company in Panama in terms of electricity volume distributed, number of customers and area served. In connection with the process of privatizing the Panamanian electricity sector, Elektra was incorporated on January 22, 1998 and, through a Sale and Purchase Agreement dated October 30, 1998, 51% of its common stock was sold to the Panama Distribution Group, S.A., or PDG, with the remaining 49% retained by the Panamanian government and Elektra employees. 51% of Elektra’s common stock is owned indirectly by AEI through PDG. In 2007, Elektra recognized revenues of $358 million.


	As of and for the Year Ended December 31,
	2005		2006		2007
	Millions of dollars (U.S.), except GWh, customers and miles

Customers at year end (thousands)		297		312		328
Energy sales (GWh)⁽¹⁾		1,916		2,029		2,179
Operating income	$	35	$	34	$	34
Depreciation and amortization	$	12	$	12	$	13
Net debt⁽²⁾	$	92	$	67	$	91
Network length (miles)		4,693		4,914		5,154


(1)		Does not include sales for distribution in third-party transmission.


(2)		See “Non-GAAP Financial Measures” and “Item 3. Key Information — A. Selected Financial Data.” Net debt as indicated in the table above is reconciled below:


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	100		$	99		$	99
Less
Cash and cash equivalents		(6	)		(32	)		(8	)
Current restricted cash		0			0			0
Non-current restricted cash		(2	)		0			0

Net debt	$	92		$	67		$	91

Concession and Contractual Agreements

Elektra holds from the Panamanian National Authority of Public Services (Autoridad Nacional de los Servicios Públicos), or ASEP, an exclusive concession for electricity distribution in the northern and eastern parts of Panama, including the eastern part of Panama City and the province of Colón. As of December 31, 2007, Elektra’s operations covered a territory of approximately 11,261 square miles that included approximately 1.4 million inhabitants, or 41% of Panama’s total population including two of Panama’s main economic centers: the province of Colón with a Panama Canal terminal, the International Free Zone and 55% of the country’s container port activities; and the province of Panama with the international airport, the main water company and the main cement company. As of December 31, 2007, Elektra had a market share of approximately 44% of the customers and approximately 41% of total energy sales in Panama. In 2007, Elektra had total energy sales of 2,179 GWh to approximately 328,000 customers.

Elektra’s concession has a 15-year term and expires in October 2013. In accordance with Panamanian law, 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 to a higher bidder, retaining the amount bid by the higher bidder. Following the auction a new 15-year concession will be granted to Elektra.

Elektra is required to provide contract coverage for its regulated customers for 24 months, renewable every two years, to limit fluctuations in energy costs. Historically, Elektra has contracted annually approximately 79% to 95% of its total requirements through purchase agreements in the contract market. For the year ended December 31, 2007, Elektra purchased approximately 93% of its total energy requirements through power purchase agreements. Purchase prices for these contracts are based on competitive bidding processes, and Elektra satisfies the balance of its requirements, including during peak demand periods, through purchases in the spot market. For 2008, Elektra has contracted 80% of its energy requirements and for 2009 to 2011 over 81% of its requirements.

Elektra’s tariff structure remains in effect for a four-year period, with the next reset scheduled for June 2010. The charges under the tariff are adjusted every six months by ASEP due to inflation and actual energy costs. ASEP establishes the maximum distribution tariff that Elektra may charge its customers which will generate revenues to cover efficient investments, operating, maintenance, administrative and service expenses, a standard level of loss and depreciation and a reasonable return on invested capital.

Customer Base

Elektra serves approximately 328,000 customers. The average annual growth in customers from 2004 through 2007 was 5.1%. As of December 31, 2007, no single customer represented more than 10.0% of Elektra’s sales. As of that date, Elektra had a customer mix by volume of 40.4% commercial, 33.5% residential, 14.4% governmental and 11.7% industrial.

Operations

As of December 31, 2007, Elektra had a peak demand of 376 MW. Elektra has a workforce of 1,283 people. Out of the 546 direct employees, 237, or 43%, were unionized. The collective bargaining agreement was recently re-negotiated and expires in February 2012. Relations with the union have historically been constructive and there have been no work stoppages. As of December 31, 2007, Elektra’s electricity distribution network comprised approximately 5,154 miles of distribution lines, 13 key substations and 1,122 MVA of transforming capacity. Elektra achieves a load factor, which is the ratio of average load to peak load, of approximately 74%. Certain customers are serviced by isolated systems, which are distribution systems not connected to the National Interconnected System for the transmission and distribution of electricity. Elektra has certifications under ISO 9001.

The following table summarizes Elektra’s actual urban outages for the periods indicated. Since 2001, Elektra has reduced total annual urban forced outages by approximately 72.4%. Under Panamanian regulations, Elektra is not permitted to have more than six interruptions per customer per year. The total duration of the interruptions cannot exceed 8.76 hours.


	For the Year Ended December 31,
	2005		2006		2007

SAIFI (number per customer per year)		3.28		3.02		2.69
SAIDI (hours per customer per year)		4.06		3.39		2.99

Pursuant to a Management Consulting Agreement, CPI Limited, our wholly-owned subsidiary, provides Elektra with management and consulting services and is entitled to a management fee of 4% of Elektra’s earnings before interest, taxation, depreciation and amortization.

Financing

As of December 31, 2007, Elektra’s total outstanding third-party indebtedness consisted of $99 million unsecured senior notes issued in June 2006. Elektra has four revolving credit facilities totaling $60 million, none of which were drawn as of December 31, 2007. Elektra is in the process of conducting a $40 million note offering that is being issued in two tranches, $20 million of which has closed and the remaining $20 million is currently on hold due to market conditions.

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

Overview

Our subsidiary EDEN is the electricity distribution company of northern Buenos Aires Province in Argentina. EDEN supplies a region of approximately 42,000 square miles, and had energy sales of 2,420 GWh of electricity in 2007, through 10,745 miles of medium and high tension lines including 7,168 substations. We acquired our 90.00% interest in EDEN in 2007 through the exchange of debt for equity. The transaction is subject to local anti-trust approval. In 2007, we recognized from EDEN revenues of $52 million, operating income of $7 million and depreciation and amortization of $2 million. As of December 31, 2007, EDEN had net debt of $35 million, which is derived from $44 million of total debt, less $9 million for cash and cash equivalents.

The table below provides a summary of EDEN’s operational information for the dates indicated:


	As of and for the Year Ended
	December 31,
	2005		2006		2007

Customers at year end (thousands)		300		307		315
Energy sales (GWh)⁽¹⁾		2,104		2,279		2,129
Network length (miles)		9,861		10,644		10,745


(1)		Does not include sales for distribution in third-party transmission.

Concession and Contractual Agreements

EDEN has a concession agreement with the government of Buenos Aires Province which expires in 2092. The concession term is divided into nine administrative periods. The first period lasts 15 years and expires in 2012. The concession is subsequently renewable for an additional 10-year period, subject to certain conditions. The concession agreement establishes an auctioning mechanism for the sale of the controlling stake in EDEN at the end of each administrative period; provided, however, that the controlling shareholder of EDEN retains the controlling stake, without having to make any payment, if it submits to the government of Buenos Aires Province a valuation for the controlling stake that is equal to or higher than the highest offer submitted in the bidding process.

In 2002, EDEN’s tariffs for the provision of services were converted from their original U.S. dollar values to Argentine pesos at a rate of AR$1.00 per U.S.$1.00. In 2006, EDEN renegotiated its tariff structure with the government of Buenos Aires Province. On August 25, 2008, a new decree was issued raising the EDEN tariff by 44% on average. We expect the next tariff review to be sometime during the first half of 2009.

Customer Base

As of December 31, 2007, EDEN served approximately 315,000 customers. No single customer represented more than 10% of EDEN’s sales. The customer base grew at a rate of 8.2% for the period 2004 to 2007. In 2007, customer mix by volume was: 22% residential, 11% commercial, 30% industrial, 21% cooperatives, 12% transmission-only services and 4% others.

Operations

As of December 2007, EDEN had a workforce of 726 employees, of which 601, or 83%, were unionized. Relations with the unions have been constructive. EDEN has earned certifications under ISO 9001.

The following table summarizes EDEN’s forced outages for the periods indicated. Since its privatization in 1997, EDEN has reduced total overall forced outages by over 53.70%.


	For the Year Ended December 31,
	2005		2006		2007

SAIFI (number per customer per year)		8.35		8.67		8.21
SAIDI (hours per customer per year)		12.28		15.48		13.83

Financing

As of December 31, 2007, EDEN had $44 million in debt in the form of a dollar-denominated syndicated credit agreement. The change in control and the change of operator resulting from our acquisition of EDEN constituted a breach of the credit agreement; consequently EDEN is in default. However, EDEN has continued paying quarterly interest and principal on its financial debt. The designated administrative agent, upon receipt of instructions from the lenders of this debt, may declare the principal, accrued interest, and all other obligations under the credit agreement to be immediately due and payable. EDEN is not currently taking any steps with regards to curing the technical default and it does not have any plans to refinance the facility. EDEN remains current in all of its payment obligations under the credit agreement and, to date, has not been notified by the lenders of the acceleration of its obligations under the credit agreement.

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

Overview

Our subsidiary Delsur is the second largest electricity distribution company in El Salvador in terms of electricity volume distributed and number of customers. Delsur serves the south-central region of the country. This service region comprises 1,774 square miles, or approximately 22% of El Salvador’s territory, which includes approximately 2.0 million people, or approximately 29% of El Salvador’s total population, and constitutes approximately 25% of total energy sales in El Salvador. In 2007, Delsur had total energy sales of 1,113 GWh to approximately 299,000 customers. Delsur was privatized in 1998 in connection with the

privatization process of the Salvadoran electricity sector, and 75% of Delsur’s common stock was sold to Electricidad de CentroAmerica S.A. de C.V., or EC, which subsequently acquired an additional 11.4% through purchases in the open market. The remaining stock is held by minority shareholders. Delsur is listed on the El Salvador Stock Exchange (Bolsa de Valores de El Salvador) under the symbol “ADELSUR.” In May 2007, AEI acquired 86.4% of Delsur’s common stock through the acquisition of EC. On August 29, 2008, we restructured the ownership chain of EC and EC transferred all of Delsur’s shares to AEI El Salvador Holdings, Ltd. In 2007, we recognized from Delsur revenues of $97 million, operating income of $8 million and depreciation and amortization of $9 million.

The table below provides a summary of Delsur’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Customers at year end (thousands)		279		289		299
Energy sales (GWh)		1,008		1,093		1,113
Network length (miles)		3,594		4,037		4,037

Concession and Contractual Agreements

Delsur holds an electricity distribution license in El Salvador approved by the General Superintendency of Electricity and Telecommunications (Superintendencia General de Electricidad y Telecomunicaciones), or SIGET. Delsur’s distribution license is automatically renewed by SIGET on an annual basis as long as Delsur provides certain basic operational information to SIGET. An existing license of an electricity distribution company may only be cancelled by SIGET if a distributor fails to remediate after notice of any specific breach of applicable Salvadoran law or regulations governing its distribution of electricity. Although electricity distribution companies in El Salvador have no exclusivity over a specific territory, in practice they serve specific geographic areas.

There are three components to Delsur’s regulated distribution tariff: (1) an energy charge, (2) a distribution charge, and (3) a customer service charge. The energy charge is adjusted every six months based on the last six-month period average spot power prices. The distribution charge is adjusted and approved by SIGET every five years and is indexed annually by 50% of the change in inflation. The distribution charge provides for the recovery of the investment (at a 10% rate of return) and operating costs of a model distribution company delivering energy to end-users. The customer service charge includes costs related to billing, customer service, marketing and other services. This charge is also adjusted and approved by SIGET every five years and is indexed for inflation. Delsur’s tariff was reset in December 2007 and amended in March 2008. As a result, regulated income will be reduced by an average of 21.6% (20.0% due to reductions in distribution and commercial tariffs and 1.6% due to technical and non-technical losses). Delsur’s management has also implemented several measures to improve operational efficiency and adjust the costs of Delsur to levels more consistent with the new tariffs.

Customer Base

As of December 31, 2007, no single customer represented more than 10.0% of Delsur’s sales. As of that date, Delsur served 299,000 customers, with a customer mix by volume of 35% residential, 7% commercial, 56% industrial and 2% governmental. The average annual growth of the number of customers from 2004 to 2007 was 3.6%.

Operations

As of December 31, 2007, Delsur had a peak demand of 215 MW. As of that date, Delsur’s electricity distribution network comprised 4,037 miles of distribution lines, 24 key substations and 294 MVA of transforming capacity. Delsur achieves a load factor, which is the ratio of average load to peak load, of approximately 70%. As of December 31, 2007, Delsur had a workforce of 780 people, of which 495 were contractors. Out of the 285 direct employees of Delsur, 173, or 61%, were unionized. Relations with the union have historically been constructive and there have been no work stoppages.

The following table summarizes Delsur’s forced outages for the periods indicated. Since the privatization in 1998, Delsur has reduced total overall forced outages by approximately 23%.


	For the Year Ended December 31,
	2005		2006		2007

SAIFI (number per customer per year)		15		11		17
SAIDI (hours per customer per year)		37		31		41

Pursuant to an operations and management agreement, EC, our wholly-owned subsidiary, provides Delsur with operations and management services and is entitled to a management fee equivalent to 1.5% of Delsur’s revenues.

Financing

On August 29, 2008, Delsur entered into a $75 million seven-year senior term loan. Delsur has entered into interest rate option caps for a notional amount of $37.5 million to partially mitigate interest rate exposure.

Chilquinta Energia S.A. (Chilquinta)

Overview

On December 14, 2007, we acquired a 50.0% interest in Chilquinta and associated companies. Chilquinta, together with its subsidiaries, is the fourth largest power distribution group in Chile as measured by 2007 energy sales. Chilquinta owns a controlling interest in four small power distribution companies in Chile: Litoral (75.61%), LuzParral (56.59%), LuzLinares (85.00%), and Energía Casablanca (69.75%).

The table below provides a summary of Chilquinta’s stand-alone operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Customers at year end (thousands)		444		454		465
Energy sales (GWh)⁽¹⁾		1,977		2,121		2,281
Network length (miles)		4,923		4,949		4,921


(1)		Does not include sales for distribution in third-party transmission.

Concession and Contractual Agreements

Chilquinta is the main power distributor for Chile’s Region V, which comprises approximately 1,958 square miles and includes the city of Valparaiso. Chilquinta’s concession licenses have no expiration dates.

Under the Chilean regulatory framework, Chilquinta’s tariffs are subject to a four-year review cycle, the most recent of which was conducted in November 2008. However, no official decrees related to the November 2008 review have currently been published. Chile has a well-established, independent regulatory structure. Rates are regulated through an autonomous technical agency, the National Energy Commission (Comisión Nacional de Energía). The tariff includes three major components: (i) a capacity and energy charge, which is passed through to the end customer, (ii) a value-added distribution charge, which includes regulated returns on assets, operating and maintenance charges and an allowance for distribution losses and (iii) a transmission charge and sub-transmission surcharge.

Following the enactment of Short Law II in Chile in May 2005, prices with respect to new contracts between generators and distributors for the supply of electricity to regulated clients from 2010 and thereafter are now determined through competitive tenders by distributors.

Customer Base

As of December 31, 2007, Chilquinta served approximately 465,000 customers, comprising 32% residential, 24% industrial, 18% commercial, 11% governmental, 9% agricultural and 6% other.

Operations

As of December 31, 2007, Chilquinta employed approximately 544 people, 304 of whom were unionized. Strikes against “strategic” public service companies such as Chilquinta are prohibited under Chilean government decrees and there have been no work stoppages since privatization.

Tecnored provides management of technical projects and services, construction work, and preventative and corrective maintenance for Chilquinta and third parties.

The following table summarizes Chilquinta’s forced outages for the periods indicated.


	For the Year Ended December 31,
	2005		2006		2007

SAIFI (number per customer per year)		2.5		2.7		1.5
SAIDI (hours per customer per year)		6.4		7.3		4.1

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

Overview

On December 14, 2007, we acquired a 50.00% interest in Peruvian Opportunity Company, SAC, or POC, the holding company of Luz del Sur and associated companies, through which we acquired 37.94% of Luz del Sur. 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. Luz del Sur is the largest power distribution company in Peru as measured by 2007 energy sales and is listed on the Lima Stock Exchange under the symbols “LU.S.URC1” and “LU.S.URBC1.”

The table below provides a summary of Luz del Sur’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Customers at year end (thousands)⁽¹⁾		741		787		782
Energy sales (GWh)⁽¹⁾⁽²⁾		4,266		4,642		4,994
Network length (miles)⁽¹⁾		10,870		11,004		11,169


(1)		Includes Luz del Sur only and does not include its subsidiary.

(2)		Does not include sales for distribution in third-party transmission.

Concession and Contractual Agreements

Luz del Sur holds an exclusive concession for electricity distribution in the southern half of Lima province and Cañete province in Peru. Luz del Sur’s concession area spans approximately 1,157 square miles and includes important commercial and residential areas in the capital city. The concession area includes over 3.5 million inhabitants, or approximately 13% of Peru’s total population. Peruvian power distribution companies are required to provide services within their concession area at applicable tariffs to public service customers. Concession licenses have no expiration dates.

Luz del Sur operates under a four-year tariff review cycle. Luz del Sur’s next review is scheduled for November 2009. Rates are regulated through an autonomous technical agency, the Tariff Regulatory Bureau (Gerencia Adjunta de Regulación Tarifaria). The tariff includes two major components: (i) a capacity and energy charge, which is passed through to the end customer and (ii) a value-added distribution charge, which includes regulated returns on assets, operating and maintenance charges and an allowance for distribution losses. In between tariff review periods, the value-added distribution component is adjusted periodically by reference to a tariff index.

Customer Base

As of December 31, 2007, Luz del Sur served approximately 782,000 customers and has energy sales of 4,994 GWh, broken down as follows: 39% residential, 25% industrial, 17% commercial and 19% other. This represented approximately 20% of market share in Peru by sales volume.

Operations

As of December 31, 2007, Luz del Sur employed approximately 670 people, 278 of whom were unionized. Relations with the union have been constructive and there have been no significant work stoppages since Luz del Sur was privatized.

Tecsur provides supply, storage and purchasing of materials, leasing of vehicles, maintenance, construction, as well as service termination and reconnection services for Luz del Sur and its subsidiary.

The following table summarizes Luz del Sur’s forced outages for the periods indicated.


	For the Year Ended December 31,
	2005		2006		2007

FEC (number per customer per year)		2.3		3.1		2.2
DEC (hours per customer per year)		5.4		6.9		6.3

Power Generation

Segment Overview

Our Power Generation businesses generate and sell wholesale power to large off-takers. Most of the businesses in this segment sell substantially all of their generating capacity under long-term contracts primarily to state-owned entities. These businesses convert fuel to electricity. Most of our off-take agreements are structured to minimize our business exposure to commodity fuel price volatility. Our businesses in this segment are summarized in the table shown below:

Power Generation

Percent

Generating

Capacity Under

Contracts and

AEI Ownership

Scheduled

Interest (Direct

Installed

Termination Date

and Indirect) as

Generating

Under Principal

Approximate

of December 31,

Operating

Capacity

Primary Fuel

Power Purchase

Number of

Business

Country

2007

Control⁽¹⁾

(MW)

Type

Agreements

Employees

Trakya

Turkey

59.0

Yes

478

Natural Gas

100%
until June 2019

Cuiabá — EPE

Brazil

50.0

Joint with
Shell

480

Natural Gas

100%
until May 2019

Luoyang⁽²⁾

China

—

Yes

270

Coal

PPA renewed
annually.

PQP

Guatemala

100.0

Yes

234

Bunker Fuel

47%
until February 2013

San Felipe

Dominican
Republic

100.0

Yes

180

Diesel Oil/
Bunker Fuel

100%
until January 2015

ENS

Poland

100.0

Yes

116

Natural Gas

74%

Thermal

until December 2010

Subic

Philippines

50.0

116

Bunker Fuel

100%
until February 2009

Corinto

Nicaragua

50.0

Yes

Bunker Fuel

71%
until September 2014

Tipitapa⁽³⁾

Nicaragua

—

Yes

Bunker Fuel

100% until 2014

JPPC

Jamaica

84.4

Yes

Bunker Fuel

100% until 2016

DCL⁽⁴⁾

Pakistan

—

Yes

Natural Gas

100%
until April 2038

2,219

762


(1)		“Operating Control” means that AEI has either a controlling interest in the business or operates the business through an operating agreement.


(2)		On February 5, 2008, we acquired a 48.00% interest in Luoyang. On June 6, 2008, we acquired an additional 2.00% interest in Luoyang.

(3)		On June 11, 2008, we acquired a 100.00% interest in Tipitapa.

(4)		On July 18, 2008, we acquired a 48% interest in DCL. Since the additional acquisition, we have executed additional share subscription agreements that have resulted in an increase in our ownership to 60.22%.

In 2007, the Power Generation segment accounted for 26.2% of our net revenues, 10.8% of our operating income and 15.5% of our Adjusted EBITDA.

Power Generation Growth

We are actively involved in several development projects in this segment. By their nature, these opportunities are long-term projects involving siting, permitting, sourcing, marketing, constructing, financing and ultimately operating activities. Our greenfield development activities are focused primarily in our Power Generation segment in the markets where we currently operate, including opportunities that are significantly advanced in Guatemala, Peru and other emerging markets. In May 2008, one of our subsidiaries was awarded a contract to supply 200 MW to local distribution companies as part of a competitive public bid process in Guatemala for which we expect to build, own and operate a nominal 300 MW solid fuel-fired generating facility in the Department of Escuintla, Guatemala. Our subsidiary also executed power purchase agreements with the distribution companies to sell capacity and energy for 15 year terms pursuant to the bid terms. The anticipated investment size for this facility is expected to exceed $700 million. We anticipate commencing construction in the second half of 2009 and commercial operations in 2012. In June 2008, we completed the purchase of an 85.00% interest in a nominal 530 MW generating project under development near Lima, Peru for $120 million, with $20 million of the purchase price to be paid to the seller upon the achievement of certain project development milestones. The purchase includes the project site and major equipment. Subject to the receipt of certain licenses, completion of off-take and supply agreements, financing and construction we anticipate commercial operations to begin during 2011. Additionally, Luoyang has obtained key regulatory approvals in China for a 600 MW expansion next to the existing 270 MW power plant. See “— Luoyang Sunshine Cogeneration Co., Ltd. (Luoyang)” for additional information.

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

Overview

We own a 59% interest in Trakya, a Turkish combined cycle combustion turbine generator with a nominal capacity of 478 MW and related equipment. The plant is located in the province of Tekirdag on the northern coast of the Sea of Marmara approximately 60 miles to the west of Istanbul. The plant consists of two Siemens V 94.2 combustion turbine generators designed to run on natural gas or diesel oil, two heat recovery system generators manufactured by Nooter/Eriksen and a single Siemens steam turbine generator. A storage facility on site is capable of holding 15 days’ supply of diesel oil. The power plant commenced commercial operations in June 1999. In 2007, Trakya recognized revenues of $337 million.

The table below provides a summary of Trakya’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005			2006		2007
	Millions of dollars (U.S.), except MW, % and Btu/kWh

Capacity (MW)		478			478		478
Capacity factor (%)		99.3			96.3		98.6
Heat rate (Btu/kWh)		7,377.2			7,431.8		7,400.2
Operating income	$	52		$	77	$	46
Depreciation and amortization	$	26		$	18	$	19
Net debt⁽¹⁾	$	(28	)	$	82	$	(62	)


(1)		See “Non-GAAP Financial Measures” and “Item 3. Key Information — A. Selected Financial Data.” Net debt as indicated in the table above is reconciled below:


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	140		$	94		$	47
Less
Cash and cash equivalents		(59	)		(60	)		(8	)
Current restricted cash		(109	)		(13	)		(13	)
Non-current restricted cash		0			(103	)		(88	)
Net debt	$	(28	)	$	(82	)	$	(62	)

Contractual Agreements

The 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. The contract was designed with larger upfront capacity fixed payments to repay the original debt financing within the ten-year period ending September 2008, and therefore payments under it decrease over time. Trakya beneficially owns and operates the power plant during the authorization period, which initially ends in June 2019. The authorization period may be extended until 2046, subject to tariff modification, sufficient gas supplies 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. BOTAŞ, the state-owned natural gas monopoly, also provides Trakya with certain utility and other services under a separate agreement.

Trakya’s revenue is derived from selling 100% of the capacity and energy produced by the power plant to Turkiye Elektrik Ticaret ve Taahhut A.S., or TETAŞ, the state-run electricity contracting and trading company, under an energy sales agreement with an initial term ending in June 2019. The tariff under the energy sales agreement is based on a take-or-pay structure with fixed capacity, variable capacity and variable energy components that allow for recovery of fixed capital costs, servicing of debt, operation and maintenance costs, a pass-through of fuel costs and a return on investment. The variable energy component is paid for energy actually delivered to TETAŞ and is calculated based on a contract heat rate and the actual gas price paid to BOTAŞ. The tariff is denominated and paid in U.S. dollars, except for payments relating to the 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.

Since November 2002, Trakya and the other Turkish build-operate-transfer (BOT) projects have been under pressure from the Ministry 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 power purchase agreements. 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, but if accepted, implementation of changes to the power purchase agreements will take some time due to the need for a coordinated interaction among multiple government agencies. We do not believe that the currently expected outcome under the proposed restructuring will have a material adverse effect on our financial condition, results of operations, or liquidity.

The Turkish Energy Market Regulatory Authority has also been attempting to submit Trakya to additional regulation. Trakya filed an appeal with the administrative appellate court to set aside current regulations on the basis that they do not protect the vested rights of Trakya. A failure of Trakya to prevail in these actions could materially and negatively affect the project and its revenues and/or lead to a buyout of the plant pursuant to the implementation contract.

Natural gas is the plant’s primary fuel source and is provided by BOTAŞ under a gas sales agreement with an initial term ending in 2014, which may be extended to 2019 subject to availability of gas. The obligations of TETAŞ and BOTAŞ are guaranteed by the Republic of Turkey acting through its treasury department. The gas sales agreement and the implementation contract were designed to provide Trakya with a

secure fuel supply and a full pass-through of fuel costs, subject to target efficiencies. Due to force majeure events, the supply of natural gas to Trakya may be impeded or curtailed. Trakya’s ability to operate using alternate fuel (gasoil) may be limited by its current inventory of gasoil and/or by working capital constraints.

Operations

Commercial operations at the plant began on June 5, 1999. Trakya has consistently had strong operating performance with availability of 93.33%, reliability of 98.08% and total delivered energy of 31,168,888 MWh from the beginning of commercial operations through December 2007.


	For the Year Ended December 31,
	2005		2006		2007

Availability (%)		91.15		97.55		97.72
Reliability (%)		99.97		99.94		99.72
Generation (GWh)		3,587		3,703		3,753

Trakya is certified under ISO 9001, ISO 14001 and OHSAS 18001 and has an excellent safety and environmental record with zero employee lost time incidents in 2004 through 2007.

Operation and maintenance services for the power plant are provided by an operator consortium consisting of our affiliates under a long-term operations and maintenance agreement.

Management and Governance

Trakya’s affairs and the relationship among its shareholders are regulated by its articles of association and a shareholders agreement. The other shareholders of Trakya are an affiliate of E.ON, which owns 31%, and Gama Holdings, a Turkish conglomerate which, along with its affiliates, owns 10%.

The board consists of nine members, seven “interested” and two “independent.” All members are appointed by the shareholders. We nominate four of the seven interested members who are elected by Trakya’s general assembly of shareholders. The two independent members are elected by unanimous vote of the shareholders. All decisions of the board require an affirmative supermajority vote.

Financing

As of December 31, 2007, Trakya had $47 million of debt outstanding under loans with the Export-Import Bank of the United States, the Overseas Private Investment Corporation and Bayerische Landesbank Group. This debt matured and was repaid in September 2008.

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

Cuiabá Integrated Project Overview

The Cuiabá Integrated Project consists of four companies that on an integrated basis operate a power plant in Brazil, purchase natural gas in Bolivia and transport it through pipelines to Brazil for use as fuel in the generation of electrical energy at the power plant. The project was designed to be expanded with additional available pipeline capacity through additional compression. The four companies are EPE, TBS, GOB, and 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).”

The figure below depicts the contractual relationships between the primary Cuiabá entities and major third-party suppliers and customer.


(1)		This agreement expired on June 30, 2008.

EPE is a Power Generation company that operates an approximately 480 MW dual fuel (natural gas/diesel), combined-cycle power plant located in Cuiabá, Mato Grosso, Brazil. The plant uses two V84 3A Siemens combustion turbine generators, one Siemens steam turbine generator and two HRSG — Heat Recovery Steam Generators. EPE’s in-service date was April 1999 and it began commercial operations in May 2002. We own a 50% interest in EPE. In 2007, EPE recognized revenues of $68 million.

The table below provides a summary of EPE’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007
	Millions of dollars (U.S.), except MW, % and Btu/kWh

Capacity (MW)		480		480		480
Capacity factor (%)		29.09		25.06		24.56
Heat rate (Btu/kWh)		6,717		7,564		6,519
Operating income	$	73	$	0	$	(85	)
Depreciation and amortization	$	8	$	1	$	1
Net debt⁽¹⁾⁽²⁾	$	24	$	12	$	3


(1)		Attributable to notes owed to shareholder affiliates.

(2)		See “Non-GAAP Financial Measures” and “Item 3. Key Information — A. Selected Financial Data.”

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


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	51		$	44		$	42
Less
Cash and cash equivalents		(22	)		(32	)		(39	)
Current restricted cash		0			0			0
Non-current restricted cash		(5	)		0			0
Net debt	$	24		$	12		$	3

Concession and Contractual Agreements

In January 1998, EPE was granted a generation license by ANEEL to sell electricity to third parties. EPE sells all of its capacity to Furnas, one of Brazil’s federally controlled electricity generation companies under a power purchase agreement, or PPA, with a twenty-one year term ending in 2019. The obligations of Furnas under the PPA are guaranteed by Eletrobrás.

Pursuant to the PPA, EPE has committed to sell its entire capacity and associated energy to Furnas in exchange for a monthly payment in reais from Furnas based on a guaranteed available capacity and delivered energy. The PPA capacity and energy price is adjusted annually for Brazilian inflation, foreign exchange fluctuations (R$/U.S.$) and the U.S. consumer price index. It also has an account-tracking mechanism which compensates EPE for monthly U.S. dollar variations that are paid (or received) by Furnas in the following year. In addition, the PPA also allows EPE to request an extraordinary price adjustment for an economic-financial imbalance and contains a pass-through clause for tax increases. Under the PPA, payments for fixed capacity decrease over time.

If EPE defaults under the PPA, Furnas has the right but not the obligation to purchase the EPE power plant at the lowest value of: (i) the market value defined by the valuation of three specialists and (ii) 80% of the power plant portion of the capacity revenue discounted at 11.5%.

If Furnas defaults under the PPA, EPE has the right to sell the EPE power plant to Furnas at the highest value of (i) the market value defined by the valuation of three specialists and (ii) the power plant portion of the capacity revenue discounted at 11.5%.

EPE and TBS are parties to a Gas Supply Agreement, or GSA, with a 19-year term that ends in 2021. The contract is take-or-pay for 80% of the daily contract quantity with a five-year make-up period.

TBS purchased the gas through a Provisional Gas Supply Agreement, or PGSA, with YPFB, dated as of June 22, 2007. The PGSA has been amended several times and the last extension expired on June 30, 2008. Negotiations regarding an extension to this agreement, as well as a permanent GSA, are currently on hold. The Brazilian Ministry of Mines and Energy, or the Brazilian MME, issued ministerial order number MME 44/2007 acknowledging the adverse economic impact to EPE and allowed Furnas to pass-through the extra cost to its current regulated contract tariff. ANEEL is required to publish a specific resolution to allow the pass-through of the cost increase, as authorized by the Brazilian MME, to support the contractual amendments between EPE and Furnas, as well as among Furnas and its off-takers. ANEEL has submitted the matter to a public hearing. However, the process has been on hold due to the delay of signing a definitive GSA with firm volumes and a defined gas price adjustment mechanism. In February 2008, the Brazilian MME published ministerial order MME 31/2008 instructing Furnas and EPE to take all necessary actions to run the EPE power plant on diesel, due to an extraordinary situation related to the energy supply in Brazil. During the month of April, pursuant to this ministerial order, the EPE power plant ran on diesel at a 158 MW average capacity and collected approximately $5.5 million in revenue. The term of this agreement has now expired.

EPE has reduced take-or-pay payments under its GSA with TBS. EPE and Furnas are currently in arbitration. For more details, see “— Natural Gas Transportation and Services — Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS)” and “Item 5. Operating and Financial Review and Prospects — Recent Developments — Cuiabá Integrated Project.”

Operations

EPE is certified under ISO 9001, ISO 14001 and OHSAS 18001. Since August 2007, EPE has only been operating sporadically due to a shortage in gas exports from Bolivia. For additional information, see “Item 5. Operating and Financial Review and Prospects — Recent Developments — Cuiabá Integrated Project.”


	For the Year Ended December 31,
	2005		2006		2007

Availability (%)		85.04		95.61		91.92
Reliability (%)		99.51		99.00		99.76
Generation (GWh)		1,230		1,055		1,015

We own 50% of the Cuiabá Integrated Project businesses, including EPE, and Shell owns the remaining 50%. We have a higher economic interest in certain businesses due to intercompany debt structures. We, Shell and the Cuiabá Integrated Project are parties to a Master Voting Agreement which governs our voting rights and those of Shell.

We had previously entered into an agreement with Shell pursuant to which we would purchase Shell’s interest in the Cuiabá Integrated Project businesses. This agreement was terminated. The termination of this agreement resurrected a right Shell previously had to appoint the chief executive officer of all of the Cuiabá Integrated Project businesses and Shell has indicated that they have no immediate intention to exercise this right, but they reserve the right to do so. We now have the right to appoint the chief financial officer of these businesses.

The parties have agreed to vote their respective equity interests together through the implementation of a supervisory board whose affirmative vote is necessary to approve certain substantial transactions of any Cuiabá Integrated Project business, including but not limited to: (i) all expenditures in excess of $250,000, (ii) a transfer of all or a substantial part of the assets of any Cuiabá Integrated Project business, (iii) any amendment to the organizational documents of any Cuiabá Integrated Project business, (iv) any decision to incur indebtedness (except if less than $250,000 in the aggregate), (v) the appointment, removal, elimination, creation or modification of all senior managers’ positions, (vi) any decision appointing or removing the auditors of any Cuiabá Integrated Project business and (vii) any other material transaction relating to the Cuiabá Integrated Project business.

Financing

The Cuiabá Integrated Project does not have any third-party financing. However, EPE has an outstanding aggregate debt of $43 million provided by other shareholders of EPE and $158 million from affiliates of AEI as of December 31, 2007. Pursuant to credit restructuring agreements, EPE can use excess cash balances above stipulated minimum cash requirements to reduce indebtedness to affiliates.

Luoyang Sunshine Cogeneration Co., Ltd. (Luoyang)

Overview

On February 5, 2008, AEI acquired a 48% interest in Luoyang, which consists of two coal-fired circulating fluidized-bed boilers and two 135 MW steam turbine generators. On June 6, 2008, we acquired an additional 2% interest in Luoyang. Luoyang is located in the Henan Province in China. Luoyang is the sole provider of steam and heat to industrial and residential customers in the Luoyang New District, a growing area that is home to the city government, industrial zone and the new town center.

Concession and Contractual Agreements

Luoyang sells power to the Henan Provincial Power Company through a Power Purchase Agreement. The tariff is set by the Henan Provincial Pricing Bureau with the approval of the National Development and Reform Commission, or NDRC. This agreement contains an evergreen provision, pursuant to which it is automatically renewed annually unless terminated by notice. Luoyang also sells steam to the Luoyang Municipal Heating Company through a steam sales contract, and can contract for direct steam supplies to industrial users. Historically, most of the plant’s revenues have been derived from power sales. The annual

dispatch volume for power plants in Henan province is planned by 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, it has preferential dispatch of its power generated, in priority to other non-cogeneration power plants in the same grid that use gas, coal or oil as their fuel. The plant has been allocated 1,000 GWh and 1,270 GWh (about 4,700-5,300 hours annualized operating hours) of annual dispatch volume since its operation in about mid 2006.

Management and Governance

Luoyang’s affairs and the relationship among its shareholders are regulated by its articles of association. The other shareholders of Luoyang are Luoyang Hailong Power Investment & Consultancy Co., Ltd., a Chinese private enterprise, which owns 33%, and Luoyang City Gas General Company, a state-owned enterprise, which owns 17%.

The board consists of seven members appointed by the shareholders. We nominate four of the seven members. All decisions of the board require an affirmative simple majority vote. We also have the right to nominate the general manager of Luoyang.

Operations

Commercial operations of the plant began in 2006. Historically, Luoyang has been operated and maintained by third-party contractors. During 2009, we intend to move the operations and maintenance of the facility from the contractors to an AEI affiliate. The following table sets forth availability and reliability information for the periods indicated:


	For the Year Ended December 31,
	2006			2007

Availability (%)		97.08	%		97.81	%
Reliability (%)		96.06	%		97.42	%
Generation (GWh)		846			1,024

Growth

Luoyang has set aside and cleared a parcel of land which it owns adjacent to the existing 270 MW power plant for the development of a 600 MW coal-fired cogeneration facility for which it has received key regulatory approvals. The preliminary feasibility study for this project has been completed and was approved in November 2007 by the NDRC. We are developing this opportunity and need to complete several steps prior to making a final investment decision.

Financing

Luoyang is currently insolvent with negative equity and was in default on an interest payment to the China Development Bank, or the CDB. On November 19, 2008, Luoyang reached an agreement with the CDB to restructure the repayment schedule of the loan and is currently up to date on payments under this restructured repayment schedule. The next principal payment is due on May 20, 2009.

Puerto Quetzal Power LLC (PQP)

Overview

Our subsidiary PQP owns three barge-mounted, bunker fuel-fired generation facilities through its branch in Guatemala. The facilities have a combined installed capacity of 234 MW and are located on the Pacific coast at Puerto Quetzal, Guatemala, approximately 62 miles south of Guatemala City. The plant, which commenced commercial operations in 1993, consists of (i) twenty Wartsila 18V32 bunker-fired reciprocating engines commissioned in 1993 and (ii) seven MAN B&W 18V48/60 bunker-fired reciprocating engines commissioned in 2000. The plant’s combined output represented approximately 13% of the country’s effective capacity and 10% of the country’s electricity generation in 2007. AEI currently indirectly owns 100% of PQP.

In 2007, PQP recognized revenues of $168 million, operating income of $42 million and depreciation and amortization of $5 million and as of December 31, 2007 had net debt of $80 million, which derived from total debt of $90 million, less $9 million cash and cash equivalents, less $1 million of current restricted cash.

The table below provides a summary of PQP’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Capacity (MW)		234		234		234
Capacity factor (%)		33.6		8.0		21.1
Heat rate (Btu/kWh)		9,173		9,604		9,431

Concession and Contractual Agreements

PQP supplies power to Empresa Eléctrica de Guatemala S.A., or EEGSA, under a 20-year PPA which ends in 2013 for 110 MW of capacity and a 50% take-or-pay energy obligation. PQP, through its wholly-owned subsidiary Poliwatt Limitada, or Poliwatt, sells the remaining 124 MW in the Guatemalan and regional wholesale electricity market. During 2007, sales made to EEGSA under the PPA accounted for approximately 54.9% of PQP’s revenues. Since April 2006, in response to a request from the Guatemalan government, PQP agreed to unilaterally grant EEGSA a discount over the PPA energy prices. This discount program did not modify the PPA and can be terminated by PQP at PQP’s sole discretion. AEI Guatemala Limitada, a wholly owned subsidiary of AEI, conducts the day-to-day operations of the plant.

The plant utilizes bunker fuel pursuant to a long-term fuel supply agreement that expires in 2013. The fuel supply agreement includes detailed fuel specifications that have to be satisfied in order to meet equipment and environmental requirements. PQP is currently in negotiations with the supplier with respect to the commercial terms of this agreement.

Merchant Activities

PQP conducts its merchant activities through its wholly owned subsidiary Poliwatt. Poliwatt does not operate as a separate profit center, but passes through to PQP all revenues received from its power marketing activities, net of costs. Poliwatt markets the 124 MW of PQP’s merchant capacity under short- and medium-term sales agreements (typically from one to three years), spot market sales and sales of ancillary services to the market, such as secondary spinning reserve. Merchant operations represented 45.1% of PQP’s 2007 revenues and 38.2% of PQP’s 2007 total operating income.

Poliwatt’s portfolio of customers in Guatemala and the regional market (Nicaragua and El Salvador) includes wholesale customers such as local distribution companies, other generators, and large end-users authorized to directly participate in the market. Poliwatt also provides certain ancillary services to the wholesale market, mainly a “secondary spinning reserve,” which in 2007 accounted for 13.9% of merchant revenues.

Operations

Commercial operations of the plant began in 1993. The following table sets forth availability and reliability information for the periods indicated:


	For the Year Ended December 31,
	2005		2006		2007

Availability (%)		93.3		93.9		90.3
Reliability (%)		98.6		98.1		98.3
Energy Sales (GWh)		1,249		1,227		1,336

The Guatemalan tax authority, the Superintendency of Tax Administration (Superintendencia de Administración Tributaria), or SAT, has filed two claims with PQP introducing adjustments in PQP’s tax declarations, from January 1, 2001 to December 31, 2002 and from January 1, 2003 to June 30, 2005. Both claims have been vigorously opposed by PQP. SAT has withdrawn the largest adjustment from the 2003-2005 claim and has indicated it will do the same for the 2001-2002 claim. The other adjustments are still in the administrative process. We expect the judicial defense of these cases to be favorable for PQP.

Financing

In October 2007, PQP entered into a new non-recourse syndicated financing, which includes a $90 million eight-year floating rate term loan and a $25 million five-year revolving credit facility to replace its previously existing financing. Under this financing, PQP granted a security interest to its lenders over substantially all of its property. PQP has entered into interest rate swaps for a notional amount of $45 million to partially mitigate interest rate exposure.

Generadora San Felipe Limited Partnership (San Felipe)

Overview

Our subsidiary, San Felipe, owns a land-locked barge mounted with a 180 MW net nominal power combined cycle generating plant consisting of a 75 MW GE 7EA combustion turbine generator burning diesel fuel with a GE heat recovery steam generator and a land-based boiler (burning bunker fuel) both feeding steam to a 110 MW steam turbine generator. The plant is located on the Dominican Republic’s north coast in the city of Puerto Plata. San Felipe accounts for 5.8% of the Dominican Republic’s installed capacity and in 2007 provided 6.2% of the energy delivered to the country’s system. In 2007, San Felipe recognized revenues of $139 million.

We have indirectly owned 100% of San Felipe and Operadora San Felipe LLP, San Felipe’s operator, since February 2007 when we purchased from our partner its 15% interest in San Felipe and its 50% interest in the operator.

The table below provides a summary of San Felipe’s operational information for the dates indicated:


	As of and for the Year Ended
	December 31,
	2005			2006			2007
	Millions of dollars (U.S.), except MW, %
	and Btu/kWh

Capacity (MW)		180.0			180.0			180.0
Capacity factor (%)		62.7			80.3			50.1
Heat rate (Btu/kWh)		9,745.3			10,061.1			10,051.2
Operating income	$	31		$	24		$	19
Depreciation and amortization	$	4		$	2		$	6
Net debt⁽¹⁾	$	(23	)	$	(13	)	$	(16	)


(1)		See “Non-GAAP Financial Measures” and “Item 3. Key Information — A. Selected Financial Data.” Net debt as indicated in the table above is reconciled below:


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	4		$	0		$	0
Less
Cash and cash equivalents		(24	)		(13	)		(16	)
Current restricted cash		(3	)		0			0
Non-current restricted cash		0			0			0
Net debt	$	(23	)	$	(13	)	$	(16	)

Concession and Contractual Agreements

The CDEEE is the only customer of San Felipe under the terms of a power purchase agreement for the sale of 170 MW of capacity and energy under which San Felipe began delivering its full capacity in January 1996 and will terminate in January 2015. The PPA provides for an escalation formula for certain non-fuel components of the energy generated.

As of December 31, 2007, the CDEEE was in payment arrears of approximately $48.3 million, on which it is currently paying interest. 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.

Currently San Felipe has no fuel supply agreement, buying 100% of its fuel requirements on a spot, prepaid basis.

The Dominican Republic passed its environmental legislation on August 18, 2000, several years after the plant had completed its commissioning pursuant to the World Bank’s standards and regulations. On July 2, 2008 San Felipe obtained its environmental permit from the Secretary of the Environment and Natural Resources (Secretaría de Medio Ambiente y Recursos Naturales).

Operations

San Felipe is currently being dispatched as a mid-merit resource by the system administrator based on its variable costs relative to other generation facilities in the system. The following table sets forth availability and reliability information for the periods indicated:


	For the Year Ended December 31,
	2005		2006		2007

Availability (%)		90.28		77.83		83.66
Reliability (%)		96.73		83.62		94.92
Generation (GWh)		878		899		693

Work to correct high vibration levels on the steam turbine generator rotor significantly affected 2006 and 2007 availability.

Financing

On June 3, 2008, San Felipe entered into a $6.0 million credit facility, all of which was undrawn as of September 30, 2008.

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

Overview

ENS consists of a cogeneration plant with a nominal electrical capacity of 116 MW and nominal thermal capacity of 70 MW located in the city of Nowa Sarzyna, Poland. The plant consists of two General Electric Frame 6B combustion turbine generators, two HRSGs, one steam turbine generator and five auxiliary boilers. In 2007, ENS recognized revenues of $93 million.

The table below provides a summary of ENS’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007
	Millions of dollars (U.S), except MW, %
	and Btu/kWh

Capacity (MW)		116		116		116
Capacity factor (%)		79.4		74.5		77.2
Heat rate (Btu/kWh)		8,563.8		8,678.3		8,592.4
Operating income	$	15	$	15	$	16
Depreciation and amortization	$	7	$	6	$	10
Net debt⁽¹⁾	$	58	$	53	$	57


(1)		See “Non-GAAP Financial Measures” and “Item 3. Key Information — A. Selected Financial Data.” Net debt as indicated in the table above is reconciled below:


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	91		$	85		$	77
Less
Cash and cash equivalents		(12	)		(19	)		(10	)
Current restricted cash		(11	)		(13	)		(10	)
Non-current restricted cash		(10	)		0			0
Net debt	$	58		$	53		$	57

Concession and Contractual Agreements

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. Stranded costs compensation is based upon the capital expenditures incurred before May 1, 2004, which could not be recovered from future sales in the free market, and will be paid in quarterly installments of varying amounts. The first payment was received in August 2008 and totaled $10.2 million. The second payment was received in November 2008 and totaled $7.8 million. The maximum compensation attributable to ENS is 1.12 billion Polish zloty (approximately $385 million).

The European Commission, in a decision dated September 25, 2007, declared the Polish long-term power purchase contracts to be illegal state aid. In the same decision, the above-mentioned Polish legislation allowing for termination of long-term contracts with compensation was declared to be a state aid measure compatible with relevant EU legislation. In the decision, Poland was obligated to terminate the long-term contracts by the end of 2007 (such termination becoming effective as of April 1, 2008), with the entities that voluntarily terminated their contracts within that period not being obligated to return the aid already received. ENS sent notice of its termination of its long-term power purchase contract in December 2007, with such termination being effective as of April 1, 2008. In March 2008, ENS entered into a new power delivery agreement with Mercuria Energy Trading Sp. z. o.o. effective April 1, 2008. We do not expect the restructuring of ENS’ power sales agreement to have a material adverse effect on our financial condition, results of operations, or liquidity.

ENS sells 90% of its steam under a long-term Thermal Energy Supply Agreement to Zaklady Chemiczne Organika-Sarzyna S.A. under a 20-year agreement which expires in 2020. Capacity payments under this agreement are expressed and paid in Polish zlotys, but indexed to the U.S. dollar. Historically, over 90% of ENS’s revenue has been derived from the Power Delivery Agreement, with the remaining revenues coming from the Thermal Energy Supply Agreement.

Polskie Górnictwo Naftowe i Gazownictwo supplies the plant with natural gas under a 20-year Fuel Supply Agreement. The Fuel Supply Agreement contains minimum and maximum volume obligations applicable to both parties and take-or-pay provisions. Payments under this contract are made in Polish zlotys. Periodic changes in the gas tariff are passed through directly into the electrical and thermal energy (steam) prices.

Operations

Since commercial operations commenced, the plant has had no significant technical concerns or outages. ENS has been operating successfully at an availability of 98.1% and a reliability factor averaging 99.8% since the commencement of commercial operations. ENS is fully in compliance with Polish and EU environmental law requirements. The following table sets forth availability and reliability information for the periods indicated:


	For the Year Ended
	December 31,
	2005		2006		2007

Availability (%)		98.84		90.83		99.75
Reliability (%)		99.98		99.95		99.79
Generation (GWh)		754		681		754
Thermal energy produced (GJ)		581,137		584,979		606,291

Financing

As of December 31, 2007, ENS had $77 million outstanding in debt. Debt was converted from U.S. dollars to PLN on April 1, 2008.

Subic Power Corp. (Subic)

Overview

Subic owns and operates a 116 MW reciprocating engine generating facility located at the Subic Bay Freeport Zone, Olongapo City, Luzon Island, the Philippines. AEI indirectly owned a 50% interest in Subic. In 2007, AEI recognized equity earnings of $10 million from Subic.

Concession and Contractual Agreements

Subic commenced commercial operations in February 1994. Subic operates and sells the capacity and energy from the plant under a build-operate-transfer agreement (BOT) with the National Power Corporation of the Philippines, or NPC. Under the terms of the BOT, NPC supplies at its cost all fuel required for the generation of electricity by the plant and assumes the risk associated with fuel pricing and delivery.

Upon expiration of the 15-year term of the BOT on February 23, 2009, the plant was turned over to NPC without additional compensation from NPC.

Subic is operated and maintained by Subic personnel with technical supervision services provided by AEI Subic Power Corp., our wholly owned subsidiary.

Empresa Energética Corinto Ltd. (Corinto)

Overview

Corinto owns a 70 MW barge-mounted, bunker fuel-fired generation facility located at Puerto Corinto, a port city on the Pacific coast of Nicaragua (100 miles northwest of Managua). The plant consists of four MAN B&W 18V48/60 reciprocating engine generator sets. In 2007, the plant represented approximately 11% of the country’s installed capacity and 18% of the country’s electricity generation. Corinto has received ISO 9001 and ISO 14001 certifications. AEI currently indirectly owns 57.67% of Corinto. In 2007, Corinto recognized revenue of $25 million, operating income of $3 million and depreciation and amortization of $1 million and as

of December 31, 2007 had net debt of $11 million, which is derived from total debt of $21 million, less $3 million of cash and cash equivalents and less $7 million of current restricted cash.

Pursuant to an agreement with Centrans, we contributed our 50% interest in Corinto and our 100% interest in Tipitapa to Nicaragua Energy Holdings in late 2008. See “— A. History and Development of the Company — Our Recent Acquisitions” for additional information.

Concession and Contractual Agreements

Corinto supplies power to Disnorte and Dissur, two local electricity distributors which are subsidiaries of Union Fenosa, under a long-term PPA, which ends in 2014, for 50 MW of capacity and energy and is in negotiations for an additional two medium-term PPAs for 13.3 MW. The remaining energy and capacity is sold under short-term contracts with private customers and/or in the local spot market. In June 2002, Corinto entered into a 12-year agreement for the supply of bunker fuel. We are currently in negotiations with the supplier with respect to the commercial terms of this agreement.

Operations

Commercial operations of the plant began in 1999. AEI Nicaragua, S.A., our wholly owned subsidiary, conducts the day-to-day operations of Corinto. The following table sets forth availability and reliability information for the periods indicated:


	For the Year Ended December 31,
	2005		2006		2007

Availability (%)		92.30		90.13		93.30
Reliability (%)		98.20		97.60		98.28
Generation (GWh)		513		536		556

Management

We have the right to appoint four of the seven members of Corinto’s board of directors.

Tipitapa Power Company Ltd. (Tipitapa)

Overview

On June 11, 2008, we acquired a 100% interest in Tipitapa which owns a 51 MW bunker fuel-fired generation facility located in Tipitapa, Nicaragua (12 miles east of Managua). The plant consists of five Wartsila 18V38 reciprocating engine generator sets. Pursuant to an agreement with Centrans, we contributed our 50% interest in Corinto and our 100% interest in Tipitapa to Nicaragua Energy Holdings in late 2008. See “— A. History and Development of the Company — Our Recent Acquisitions” for additional information.

Concession and Contractual Agreements

Tipitapa supplies power to Disnorte and Dissur, under a long term PPA, which ends in 2014, for 51 MW of capacity and energy. Fuel is supplied under a long-term agreement with ESSO which expires in 2014.

Operations

Commercial operations of the plant began in 1999. Tipitapa is currently operated through an operations, maintenance and administrative agreement with one of our subsidiaries (also acquired on June 11, 2008). The following table sets forth availability and reliability information for the periods indicated:


	For the Year Ended
	December 31,
	2005		2006		2007

Availability (%)		97.04		96.03		95.75
Reliability (%)		98.61		98.38		97.45
Generation (GWh)		399.8		420.2		409.25

Jamaica Private Power Company Ltd. (JPPC)

Overview

In October 2007, we acquired an 84.4% interest in JPPC and a 100% interest in Private Power Operators Limited, or PPO. JPPC owns a base-load 60 MW diesel-fired generating facility located on the east side of Kingston, Jamaica. The plant consists of two MAN B&W 9K80MC-5 diesel powered generators that commenced operations in 1996. PPO operates JPPC through an operations and maintenance agreement. In 2007, we recognized from JPPC revenues of $12 million, operating income of $3 million, depreciation and amortization of less than $1 million. As of December 31, 2007, JPPC had net debt of $10 million, which is derived from total debt of $25 million, less $4 million of cash and cash equivalents, less $2 million of current restricted cash and less $9 million of non-current restricted cash.

Concession and Contractual Agreements

JPPC has a PPA with Jamaica Public Services Company Limited expiring in 2018. The PPA is for JPPC’s entire capacity. The PPA establishes: (i) a capacity payment compensating fixed expenses (foreign and local), debt service, equity return, and a quarterly working capital adjustment (foreign and local); (ii) energy payment compensating variable expenses; and (iii) supplemental payments compensating unit starts and pass through charges.

JPPC has a fuel supply agreement with Petrojam Limited that runs concurrently with the PPA.

Operations

JPPC is operated by PPO under an operations and maintenance agreement by which JPPC pays to PPO reimbursement of its costs and overhead fees adjusted annually by the U.S. consumer price index. The following table sets forth availability and reliability information for the periods indicated:


	For the Year Ended
	December 31,
	2005		2006		2007

Availability (%)		89.8		92.2		90.7
Reliability (%)⁽¹⁾		—		—		—
Generation (GWh)		444,948		460,936		436,336


(1)		Reliability was not tracked at this business prior to our purchase in October 2007.

DHA Cogen Limited (DCL)

Overview

On July 18, 2008, we acquired an approximate 48% interest in DCL through the purchase of DCL’s largest shareholder, Sacoden Investments Pte Ltd., or Sacoden, and subsequently increased our interest in DCL to 60.22% through a series of share subscriptions. DCL owns and operates a gas-fired combined-cycle power

generation and water desalination plant located in Karachi, Pakistan with a nominal capacity of 94 MW and three million gallons per day. DCL has proposed an expansion that would more than double the plant’s power and water output.

Concession and Contractual Agreements

DCL is party to a power purchase agreement, or PPA, with Karachi Electric Supply Company, or KESC, and a water purchase agreement, or WPA, with Cantonment Board Clifton, or CBC, for sale of the plant’s full output of power and water, respectively. The PPA and the WPA have 30-year terms ending in 2038. The PPA provides for KESC to pay DCL monthly capacity and energy payments at rates escalating at 2.5% per six months and includes a fuel-cost adjustment. The WPA provides for CBC to pay DCL monthly water payments at rates escalating at 5% per year.

DCL purchases its entire gas requirement from Sui Southern Gas Company Ltd., or SSGC, pursuant to a take-or-pay gas sale agreement, or GSA. Although the GSA has a 30-year term ending in 2038, the GSA guarantees gas only through 2015, after which quantities are subject to availability in SSGC’s sole determination. If gas becomes unavailable under the GSA, the PPA provides for DCL to modify the plant at its sole cost to operate on an alternative fuel and to recover the difference in cost between gas and the alternative fuel from KESC.

On December 24, 2008, KESC issued to DCL notice of default stating that it would terminate the PPA unless DCL posted a letter of credit for approximately $2 million as security under the PPA by February 7, 2009. DCL’s senior lenders invoked a right under the PPA to extend this deadline. DCL is working to put a letter of credit in place but there is no assurance that it will be able to do so.

Operations

The plant 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. Siemens identified the root cause of the problem to be a defect in the gas turbine. Siemens has agreed to repair the defect under warranty but maintains that the warranty does not cover additional repairs required to return the plant to service. The shutdown’s interruption of DCL’s revenues has delayed the repairs. DCL is seeking a loan to pay Siemens that, once implemented, may allow the plant to resume commercial operations in the second quarter of 2009.

Financing

On January 24, 2009, DCL received notice of default from one of its senior lenders. That same day two of DCL’s senior lenders filed claims against DCL and Sacoden in the courts of Sindh Province, Pakistan seeking repayment by DCL of $46.3 million. The lenders petitioned the courts to force a sale of all DCL’s assets and all Sacoden’s shares in DCL and to replace DCL’s directors and officers with a court appointed administrator. DCL and Sacoden are preparing to file responses to these claims. Concurrently, DCL has engaged its lenders in negotiations to restructure DCL’s long-term and short-term financing and for consent to take out a shareholder loan to pay Siemens and meet other urgent payment obligations. Negotiations are ongoing but a final agreement has not yet been reached.

Emgasud S.A. (Emgasud)

Overview

On November 28, 2008, we acquired through our wholly owned affiliates AEI (Luxembourg) s.à.r.l. and AEI Utilities S.L., a 28.00% equity interest in Emgasud. This transaction was effected through the capital contribution of $15 million to Emgasud and the acquisition of minority shareholder equity positions. On December 23, 2008, we made a second capital contribution to Emgasud of $10 million which increased our ownership interest in Emgasud to 31.89%.

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 61.41% in a multi-step transaction in which, subject to local anti-trust and regulatory approvals, we or our affiliates will contribute certain assets to Emgasud. This acquisition is expected to close in 2009.

Emgasud is an Argentine energy company focused on the electricity and gas industries. The company primarily operates in power generation, but also operates in the natural gas transportation and services and natural gas distribution segments, gas transportation, gas distribution, gas pipeline construction and energy commercialization.

Operations

Emgasud is currently operating and developing the following projects in the power generation segment: Energia Distribuida II, which consists of six power plants for a total of 230 MW in the Provinces of Buenos Aires, Cordoba and Entre Rios which we expect to start operating in 2009. In 2008, Emgasud started operating 30 MW in Energia Distribuida I in Pinamar, in the Province of Buenos Aires and 5.8 MW in Rio Mayo and Gobernador Costa in the Province of Chubut. Through its subsidiaries Ingentis S.A. and Ingentis Esquel S.A. it is developing Ingentis I & II, a 245 MW combined cycle power generation complex in the province of Chubut which is expected to start operating in 2010.

Since 2007, Emgasud has been transporting gas through the Patagonian Pipeline, a natural gas pipeline that runs through Argentina’s Patagonian region. The pipeline’s firm capacity is approximately 3.94 mmcfd and it runs on 329.33 miles from the gas field in Cerro Dragon, Province of Chubut to the delivery point in the city of Esquel. Emgasud has also been assigned transportation capacity of 606,955.38 cubic meters per day through the TGS system through the San Martin Pipeline and 410,104.97 cubic meters per day through the TGN system through the North Pipeline.

Emgasud also participates in the gas distribution segment with 434.96 miles in distribution lines and an annual dispatch of 164.04 million cubic feet servicing a total of 25,000 customers in various areas in the Province of Buenos Aires. Additionally, Emgasud has a business unit which specializes in the construction of gas distribution networks and high-pressure gas pipelines.

Through its subsidiary Enersud Energy, Emgasud markets gas transportation capacity in TGS/TGN and Rio Mayo and Gobernador Costa. During the first half of 2008, Enersud Energy marketed 55.77 million cubic meters of gas.

Concession and Contractual Agreements

Energia Argentina S.A., or ENARSA, an energy company managed by Argentina, has entered into an agreement with Compania Administradore del Mercado Mayorista Electrico S.A., or CAMMESA, the Argentine power pool administrator, and has ceded effective rights to payments on these contracts to Emgasud. Through its project, Energia Distribuida I & II, Emgasud has entered into a Power Purchase Agreement (PPA) with ENARSA/CAMMESA for approximately 250 MW to be generated by Emgasud in a three-year term with the option to extend for an additional two-year period held by CAMMESA. Emgasud receives a dollar-denominated capacity payment and energy payment based on a guaranteed annual dispatch on natural gas for each plant, including payments for operations and maintenance compensating leasing or operational costs contracted with third parties or Emgasud’s own operatorship.

Power generated by Emgasud in Rio Mayo and Gobernador Costa is sold to the Province of Chubut by means of a Take or Pay contract until 2025. The contract establishes a dollar-denominated capacity payment and energy payment.

Further, Emgasud has entered into interruptible gas transportation contracts with Local Gas Distribution companies. Emgasud also has a gas transportation license to use the Patagonian Pipeline until 2042. It has entered into an operations and maintenance agreement with TGS until 2014 renewable for an additional five years. Emgasud has contracted a total of 550,000 cubic meters daily of natural gas firm capacity with Camuzzi Gas del Sur S.A. until 2027.

Emgasud has been assigned transportation capacity in TGS and TGN 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 five industrial customers.

Emgasud has a gas distribution license through 2027.

Financing

In February 2009, Emgasud placed a $101.6 million bond in Argentina. Proceeds from the bond are expected to be used for various capital expenditures and to repay a $68 million bridge loan entered into in 2008.

Natural Gas Transportation and Services

Segment Overview


Natural Gas Transportation and Services
									Scheduled
		AEI Ownership							Termination
		Interest (Direct							Date of							%
		and Indirect) as of							Principal			Approximate		2007		Contracted
		December 31,			Operating	Network			Concession			Number of		Throughput		Under Firm
Business	Country	2007			Control⁽¹⁾	in Miles			Agreement			Employees		(mmcfd)⁽²⁾		Contract

Promigas			52.13	%
Promigas Pipeline	Colombia		52.13	%	Yes⁽³⁾		1,297			2026			296		305		80%
Transmetano	Colombia		50.87	%	Yes⁽³⁾		93			2043			32		35		92%
GBS	Colombia		49.17	%	Yes⁽³⁾		196			2009			11		12		N/A
Centragas	Colombia		13.03	%	Yes⁽³⁾		458			2011			24		155		N/A
PSI	Colombia		51.95	%	Yes⁽³⁾		N/A	⁽⁴⁾		N/A	⁽⁴⁾		6		305		100%
Transoccidente	Colombia		35.57	%	Yes⁽³⁾		7			N/A			3		34		42%
Transoriente	Colombia		12.76	%	No		98			2045			14		12		53%
Cuiabá
TBS	Brazil		50.00	%	Joint with Shell		N/A	⁽⁵⁾		N/A	⁽⁵⁾		0		0		N/A	⁽⁵⁾
GOM	Brazil		50.00	%	Joint with Shell		175			2027			3		20		100%
GOB	Bolivia		50.00	%	Joint with Shell		225			2024			15		20		100%
Accroven	Venezuela		49.25	%	Joint with Williams		N/A	⁽⁶⁾		2021			120		763		100%
Bolivia-to-Brazil
Pipeline
GTB	Bolivia		29.75	%⁽⁷⁾	Joint with Shell		346			2037			68		987		100%
TBG	Brazil		7.00	%⁽⁷⁾	No		1,611			2037			278		987		100%

							4,506						870		3,635


(1)		“Operating Control” means that AEI has either a controlling interest in the business, operates the business through an operating agreement or has operating control through its operating control of Promigas.

(2)		Includes both gas and liquids.

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

(4)		PSI provides services related to the drying and compression of natural gas.

(5)		TBS is a natural gas shipper which purchases natural gas in Bolivia and resells it to EPE.

(6)		Accroven operates a natural gas liquids extraction, fractionation, storage and refrigeration project.

(7)		Includes the percentages of GTB and TBG previously owned through Transredes. We currently own 17.65% of GTB and 4.27% of TBG.

The natural gas transportation and services segment accounted for 6.0% of our net revenues, 18.0% of operating income and 14.9% of our Adjusted EBITDA for 2007.

Promigas S.A., ESP (Promigas)

Overview of Promigas

AEI owns a 52.13% interest in Promigas S.A., ESP, a Colombian holding company with investments mainly in transportation and gas services, natural gas distribution and retail fuel. It is listed on the Colombian

Stock Exchange (Bolsa de Valores de Colombia) under the symbol “PROMIG:CB.” Promigas is the largest private sector natural gas transportation company in Colombia. Promigas owns a 1,297 mile pipeline extending along the Atlantic coast from Ballena to Jobo, or the Promigas Pipeline, and holds direct interests in five other companies operating gas pipelines and four companies providing gas distribution in Colombia. See “— Other Promigas Pipelines” and “— Natural Gas Distribution — Promigas.”

Promigas is a major participant across all segments of Colombia’s natural gas services chain, with assets accounting for over 62% of Colombia’s gas transportation infrastructure by volume as of December 31, 2006. Promigas’ directly and indirectly held companies transported approximately 75% of Colombia’s natural gas as of December 31, 2007.

Promigas has a regulated and contracted base of income from its natural gas transportation and distribution businesses. Natural gas transportation and services accounted for 19% of its 2007 revenues and natural gas distribution for 55%.

The table below provides a summary of Promigas’ operational information for the dates indicated:


	As of and for the Year Ended
	December 31,
	2005		2006		2007

Volume transported (mmcfd)		325		328		305
Maximum capacity (mmcfd)		468		475		475
Customers		12		12		12

During the first quarter of 2009, Promigas entered into a legal stability agreement with the Colombian government pursuant to which Promigas committed to invest approximately $28.6 million in Colombian infrastructure assets through 2014, including expenditures made in 2008. The agreement provides that Promigas will not be subject to any adverse changes in income tax laws for a 20 year period so long as Promigas complies with the terms of the agreement. If Promigas does not comply with the terms of the agreement, the agreement will be terminated and Promigas would be prohibited from entering into any contracts or agreements with any governmental entity of Colombia for a ten-year period.

Management and Governance

Promigas shares are publicly traded on the Colombian stock market, with 3.86% held by the public. As the largest single shareholder, we nominate three of five seats on the board of directors. The two other board seats are controlled by a Colombian financial investor and a Colombian industrial investor.

Promigas Transportation Businesses


			Promigas
	Pipeline		Ownership % as of
Company	Length (Miles)		December 31, 2007

Promigas Pipeline		1,297		100.00	%
Centragas		458		25.00	%
Transoriente		98		24.48	%
Transmetano		93		97.59	%
GBS		196		94.32	%
Transoccidente		7		68.23	%

Promigas Pipeline

The Promigas Pipeline transports natural gas from fields in the region of La Guajira to the Jobo terminal station in the Department of Sucre. Promigas also provides subcontracted pipeline design, construction, operation and maintenance services for government and/or third-party owned natural gas transportation customers who own pipelines. In 2007, Promigas Pipeline recognized revenues of $89 million, operating income of $32 million and depreciation and amortization of $13 million and as of December 31, 2007 had net

debt of $171 million, which is derived from total debt of $198 million, less $27 million of cash and cash equivalents.

Concession and Contractual Agreements

The Promigas Pipeline’s gas transportation concession with the Colombian Ministry of Mines and Energy, or the Colombian MME, expires in September 2026. 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, a concession has no longer been required to operate a pipeline in Colombia.

Tariffs

The current tariff structure has both fixed and variable components. As of December 31, 2007, 100% of the Promigas Pipeline’s capacity was contracted. The capacity contracted is either take-or-pay or under a fixed/variable arrangement. Where it is not take-or-pay, 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.

Customer Base

The Promigas Pipeline has 12 customers, the largest of which is Generadora y Comercializadora de Energía S.A., a leading Power Generation and commercialization company in Colombia which represents approximately 21% of the Promigas Pipeline’s 2007 revenues. Other customers include thermoelectric plants, local distribution companies, cement companies, petrochemical firms and mining operations. Approximately 42% of the Promigas Pipeline’s transported volumes in 2007 were for Power Generation, 10% for retail distribution, 6% for Gazel and the remaining 42% for industrial customers.

Operations

The Promigas Pipeline has historically experienced strong operating performance and capacity utilization close to its maximum transportation capacity of 475 mmcfd. During 2007, the Promigas Pipeline accounted for 41% of the natural gas transported throughout Colombia. There have been no interruptions since the last forced outage in February 2006. In order to achieve optimal system pressure profiles, control of the operation of the pipeline between Ballena and Cartagena is automated and centralized, including the main stations and the compression stations. The Promigas Pipeline had 296 employees as of December 31, 2007, nine of which were unionized. Relations with the union have historically been constructive and there have been no work stoppages.

Other Promigas Pipelines

Promigas — Transmetano S.A. ESP (Transmetano)

Transmetano operates a 93 mile pipeline in Antioquia in Colombia. Transmetano has a capacity of 73 mmcfd. Promigas owns 97.59% of Transmetano. Transmetano has independent administration and operations from Promigas. In 2007, Transmetano recognized revenues of $15 million, operating income of $9 million, depreciation and amortization of $2 million and had net debt of $5 million, which is derived from total debt of $7 million, less $2 million of cash and cash equivalents.

Transmetano operates under a concession agreement with the Colombian MME which expires in 2043. The Colombian government has the option to buy the original assets at fair price determined by a third party in 2042. Otherwise, the concession contemplates extensions in 20-year increments. Since 1994, a concession has no longer been required to operate a pipeline in Colombia. As of December 31, 2007, Transmetano had 32 employees, none of whom were unionized.

Ecopetrol S.A., or Ecopetrol, the Colombian state-owned 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 10 successive one-year terms. Independent of volumes transported, Ecopetrol

pays a tariff established by the contract. Transmetano’s tariff period has expired and Transmetano is awaiting response from the Colombian Regulatory Commission for Energy and Gas (Comisión de Regulación de Energía y Gas), or CREG, regarding the methodology to be applied. Transmetano is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index according to the methodology established by the regulator. If the tariff to be approved by CREG differs from the one in Ecopetrol’s contract, Transmetano will assume any discount, as applicable.

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

GBS operates a 196 mile pipeline in Boyacá and Santander in Colombia. GBS has a capacity of 62 mmcfd. Promigas currently owns 94.32% of GBS. In 2007, GBS recognized revenues of $8 million, operating income of $6 million, depreciation and amortization of less than $1 million and had net debt of $(3) million, which is comprised of $3 million of cash and cash equivalents.

GBS operates under a build, operate, maintain and transfer (BOMT) agreement with Empresa Colombiana de Gas, or Ecogas, which expires in October 2009. Under the terms of the BOMT agreement, ownership of the pipeline reverts to Transportadora de Gas del Interior, or TGI, an entity recently privatized by the Colombian government at the end of the term.

Under the terms of the BOMT agreement, GBS is paid by Ecogas a certain tariff, independent of volumes transported. GBS’s tariff is set by the terms of its BOMT agreement and is not regulated by CREG.

Promigas provides operations and maintenance services for GBS under a long-term cost-plus contract which includes incentives for shared services.

Promigas — Centragas (Centragas)

Centragas operates a 458 mile pipeline in the areas of La Guajira, Cesar and Santander in Colombia. Centragas has a capacity of 200 mmcfd. Promigas owns 25% of Centragas.

Centragas operates under a BOMT agreement with Ecogas which expires in February 2011. At the end of the term, ownership of the pipeline reverts to TGI.

Under its BOMT agreement, Centragas is paid by a tariff, independent of volumes transported. Centragas’ tariff is set by the terms of its BOMT agreement and is not regulated by CREG.

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 — 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 currently owns 99.55% of PSI. In 2007, PSI recognized revenues of $5 million, operating income of $2 million, depreciation and amortization of $1 million and had net debt of $(1) million, which is comprised of $1 million of cash and cash equivalents.

PSI dehydrates and compresses natural gas in the La Guajira fields for its sole customer, Chevron Texaco. The dehydration contract has been renegotiated with Chevron Texaco until December 31, 2011. The compression contract expires on December 31, 2008 and is in renegotiation to include the compression in series service which has the objective of maximizing the recovery of the local reserves of its customer. In addition, PSI has also entered into a backup compression contract with Chevron Texaco which expires December 31, 2008.

In 2007, PSI dehydrated an average of 307 mmcfd and compressed natural gas an average of 726 hours monthly. As of December 31, 2007, PSI had six employees, none of whom were unionized.

Promigas — Transoccidente S.A. ESP (Transoccidente)

Transoccidente operates a 7 mile pipeline in the Cauca Valley in Colombia. Transoccidente has a capacity of 69 mmcfd. Promigas currently owns 68.23% of Transoccidente. In 2007, Transoccidente recognized revenues of $1 million and operating income of $1 million.

Transoccidente was established in 1998 as a result of a spin-off overseen by CREG. Because of the spin-off and since it began to operate after the public services law was issued in 1994, Transoccidente does not have a concession agreement for its operation.

Transoccidente’s customers are Gases de Occidente, an LDC owned 56.4% by Promigas, and Cartones de America.

Promigas provides operations and maintenance services for Transoccidente under a long-term cost-plus contract which includes incentives for shared services.

Promigas — Transoriente S.A. ESP (Transoriente)

Transoriente operates a 98 mile pipeline in Bucaramanga, Colombia. Transoriente has a capacity of 50 mmcfd. Promigas currently owns 24.48% of Transoriente.

Transoriente operates under a concession agreement with the Colombian MME which expires in 2045. The Colombian government has the option to buy the original assets at fair price determined by a third party in 2044. Otherwise, the concession contemplates extensions in 20 year increments. Since 1994, a concession has no longer been required to operate a pipeline in Colombia.

Transoriente’s tariff period has expired and Transoriente is awaiting response from CREG regarding the methodology to be applied. Transoriente is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index according to the methodology established by the regulator.

Transoriente’s customers are Gases de Oriente, a natural gas LDC, and Electrificadora de Santander, an electricity LDC.

Transoriente has independent administration and operations from Promigas. As of December 31, 2007, Transoriente had 14 employees, none of whom were unionized.

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

Overview

GOM and GOB are gas transportation companies that are part of the Cuiabá Integrated Project. GOM operates an approximately 175 mile, 18-inch gas pipeline in Brazil, which is interconnected to the GOB pipeline at the Bolivia-Brazil border, transporting natural gas from the border to the EPE power plant. GOB operates an approximately 225 mile, 18-inch gas pipeline in Bolivia to transport natural gas from the pipeline interconnection with GOM to the Bolivian portion of the BBPL. We indirectly own 50% of GOM and 50% of GOB. In 2007, GOM and GOB recognized revenues of $21 million and $20 million, respectively.

Our subsidiary TBS is a gas shipper that purchases natural gas, arranges for transportation of the gas, including through GOB and GOM, and sells the gas to EPE. In 2007, TBS recognized revenues of $77 million. See also “— Power Generation — Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE).”

Contractual Agreements

The pipelines of GOM and GOB are contracted to transport gas to the EPE power plant.

In March 1999, GOM was granted a license by the Brazilian National Petroleum Agency (Agência Nacional de Petróleo), the regulator which oversees the petroleum industry and ensures free access to gas pipelines, to operate the GOM pipeline and to provide gas transportation services within Brazil. TBS and GOM have a gas transportation agreement, or GTA with a 25-year term ending in 2027.

GOB’s gas transportation business is a regulated public service in Bolivia and is governed by a number of laws, regulations and a 40-year concession ending in May 2039. The Hydrocarbon Superintendence, the administrative body responsible for ensuring compliance with the laws governing gas transportation on pipelines, has granted GOB a license to operate and approved the GTA between GOB and TBS. This GTA has a 25-year term ending in 2027.

In Bolivia, a Supreme Decree was issued to transfer the gas transportation contracts of the internal market to YPFB. In accordance with this decree, the original deadline to conclude these transfers was September 16, 2008, however this deadline was postponed to November 30, 2008. GOB is negotiating the terms and conditions of this transfer with YPFB.

As a result of the Bolivian nationalization process, Cuiabá management decided to reduce the payment obligation under the gas transportation agreements between EPE and TBS, TBS and GOB and TBS and GOM. Cuiabá management continues to negotiate the terms and conditions of such payment reduction.

To fulfill its obligation under the Gas Supply Agreement with EPE, TBS is party to a Provisional Gas Supply Agreement with YPFB, the Bolivian state-owned energy company, which expired on June 30, 2008. Negotiations regarding an extension to this agreement, as well as a permanent GSA, are currently on hold. See “— Power Generation — Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE)” and “Item 5. Operating and Financial Review and Prospects — Recent Developments.”

Operations

Both GOB and GOM sub-contract the operations and maintenance of their pipelines to third parties, one of whom is Transredes. GOB and GOM each maintain a small number of employees to handle administrative matters. Because GOM and GOB pipelines run through environmentally sensitive parts of Brazil and Bolivia, GOM, GOB and affiliates of AEI have agreed to contribute $20.0 million over a 15-year period to the Chiquitano Forest Conservation Project in Bolivia.

The table below provides a summary of GOM’s and GOB’s operational information for the periods indicated:


	As of and for the Year Ended December 31,
	2005			2006			2007
	Millions of dollars (U.S.), except mmcfd and %

GOM
Average monthly throughput (mmcfd)		23.3			20.6			20.1
Maximum capacity (%)		23.3	%		20.6	%		20.1	%
Operating income	$	12		$	14		$	15
Depreciation and amortization	$	4		$	4		$	3
Net debt⁽¹⁾⁽²⁾	$	27		$	25		$	15
GOB
Average monthly throughput (mmcfd)		24.1			23.6			20.9
Maximum capacity (%)		24.1	%		23.6	%		20.9	%
Operating income	$	11		$	11		$	13
Depreciation and amortization	$	4		$	3		$	2
Net debt⁽¹⁾⁽²⁾	$	35		$	36		$	32


(1)		Attributable to notes owed to shareholder affiliates.


(2)		See “Non-GAAP Financial Measures” and “Item 3. Key Information — A. Selected Financial Data.” Net debt for GOM as indicated in the table above is reconciled below:


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	29		$	26		$	23
Less
Cash and cash equivalents		(2	)		(1	)		(8	)
Current restricted cash		0			0			0
Non-current restricted cash		0			0			0
Net debt	$	27		$	25		$	15

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


	As of December 31,
	2005			2006			2007
	Millions of dollars (U.S.)

Total debt	$	42		$	37		$	33
Less
Cash and cash equivalents		(7	)		(1	)		(1	)
Current restricted cash		0			0			0
Non-current restricted cash		0			0			0
Net debt	$	35		$	36		$	32

Financing

The Cuiabá Integrated Project does not have any third-party financing. However, GOM and GOB have aggregate debt outstanding of $84 million and $38 million, respectively, from affiliates of AEI as of December 31, 2007. In addition, GOM and GOB have aggregate debt outstanding of $23 million and $33 million, respectively, provided by a third party shareholder as of December 31, 2007. Pursuant to credit agreements, GOM and GOB can use excess cash balances above stipulated minimum cash requirements to reduce indebtedness to affiliates.

Accroven S.R.L. (Accroven)

Overview

Accroven owns and operates a Venezuelan natural gas liquids (NGL) extraction, fractionation, storage and refrigeration project. PDVSA Gas, a wholly owned subsidiary of the Venezuelan government-owned PDVSA, is Accroven’s sole customer, under primarily U.S. dollar denominated contracts expiring in 2021. 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. Accroven processes raw natural gas supplied by and for PDVSA Gas to extract NGL, consisting primarily of propane, butanes, pentanes and natural gasoline (naphtha). The project commenced commercial operations in July 2001. We indirectly own a 49.25% interest in Accroven. In 2007, we recognized equity earnings of $12 million from Accroven.

Currently, PDVSA Gas payments are delayed and such delays constitute an event of default under certain of Accroven’s finance agreements. Accroven’s lenders had granted Accroven waivers, which have since expired, and have been substituted by a standstill agreement whereby the lenders have agreed to forbear from exercising certain default rights and remedies for a specified time. The amount currently outstanding owed by PDVSA Gas is approximately $43 million and because PDVSA Gas is in default under the service agreements, Accroven is entitled to enforce its rights under those agreements, which include terminating the agreements. Negotiations to resolve this situation are ongoing.

The table below provides a summary of Accroven’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Throughput (mmcfd)		715		773		763
Maximum capacity (%)		89.4		96.6		95.4

Operations

Since the commencement of commercial operations, Accroven has exceeded the required contractual levels in terms of availability, efficiency and throughput. Safety and environmental incidents have been minimal and minor in nature. Major maintenance, including the overhaul of the turbines at the extraction plants, has been successfully carried out and preventive and corrective maintenance levels are currently 96% and 4%, respectively.

Bolivia-to-Brazil Pipeline (BBPL)

Gas Transboliviano S.A. (GTB)

Overview

Our affiliate GTB owns and operates the 346 mile Bolivian portion of the BBPL, which is a pipeline that transports natural gas from Station Rio Grande, Bolivia, to Station Mutun, Bolivia, at the Brazilian border, where it interconnects to Transportadora Brasileira Gasoduto Bolivia-Brasil S.A., or TBG, the Brazilian portion of the BBPL. AEI owns 17.65% of GTB.

The table below provides a summary of GTB’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005			2006			2007

Average monthly throughput (mmcfd)		840			905			987.4
Capacity factor (%)		100	%		100	%		100	%

Concession and Contractual Agreements

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, the Brazilian state-owned oil and gas company, are paid for directly by Petrobras, under direct payment agreements with GTB. GTB is a regulated public service in Bolivia since it operates under a concession granted by the Bolivian Hydrocarbons Superintendency. 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. GTB’s pipeline presently is flowing at approximately 98% of capacity.

Transredes provides maintenance and engineering services to GTB under a 20-year agreement.

Further to the nationalization of the hydrocarbons sector on May 1, 2006, pursuant to which YPFB became the sole authorized shipper to act in Bolivia, the government of Bolivia established a transitioning period for YPFB to enter into new transportation contracts with all transportation companies operating in Bolivia, including GTB. The deadline for YPFB to enter into such new contracts was November 30, 2008. GTB and YPFB executed new transportation contracts for the internal market prior to such deadline.

Management and Governance

AEI owns a 17.65% equity interest in GTB. The remaining equity is owned by Transredes with 51%, an affiliate of Shell with 17%, an affiliate of Petrobras with 11% and 2% by each of El Paso and an affiliate of BG

Group, respectively. Transredes, our affiliates and affiliates of Shell were parties to the Joint Venture and Shareholders’ Agreement, or JVSHA, under which the parties agree, among other things, to vote their interests in GTB and TBG jointly, as determined by majority vote. Due to the nationalization of Transredes by the Bolivian government, this agreement was terminated through a termination letter signed by an affiliate of Shell and an affiliate of AEI. Notwithstanding, there is still a separate voting agreement between us and Shell that would require a unanimous vote. All matters outside the ordinary course of business and matters with a value greater than $250,000 would be reviewed by and agreed to by such parties. Furthermore, we had previously entered into an agreement with Shell pursuant to which we would purchase Shell’s interest in GTB. This agreement was terminated. The termination of this agreement reinstated a right Shell previously had to appoint the chief executive officer of GTB and Shell has indicated that they have no immediate intention to exercise this right, but they reserve the right to do so. We now have the right to appoint the chief financial officer of GTB.

After the nationalization and the termination of the JVSHA, the right that AEI and Shell had pursuant to their voting agreement to designate the chief executive officer and the chief financial officer have been compromised to the extent that they no longer control GTB’s board of directors. On November 14, 2008, Transredes made a motion at the GTB shareholders meeting to deny the validity of the currently existing shareholder’s agreement. As a result, Transredes voted for the dissolution of the board of directors and appointed four directors out of five pursuant to the rules of the Bolivian Code of Commerce. AEI protested this measure and is evaluating the legal actions available.

As established in the GTB shareholders agreement, AEI has the right to appoint one director to the board. The remaining directors should be appointed by Transredes with two seats, Petrobras with one seat and an affiliate of Shell with one seat.

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

TBG owns and operates the 1,611 mile Brazilian portion of the BBPL, from the interconnection with the GTB pipeline at the Bolivian border to southeastern Brazil. We own 4.27%, Shell owns 4.00% and Transredes owns 12.00%. AEI, Shell and Transredes are collectively called the Bolt Group. Under the TBG shareholder agreement, affiliates of the Bolt Group have the right to appoint one director to the board, by majority vote among themselves.

However, due to the nationalization of Transredes by the Bolivian government, it is possible that this director may be appointed by Transredes since the JVSHA is terminated and Transredes has the highest ownership percentage of TBG in the Bolt Group.

Petrobras, the Brazilian state-owned oil and gas company, accounts for over 98% 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. TBG’s transportation tariffs are intended to provide its shareholders with an 18.5% return on equity.

We own a 4.27% interest in TBG. Petrobras indirectly owns 51%, Shell owns 4%, Transredes owns 12% and a joint venture among Total, British Gas and El Paso owns 29%.

Natural Gas Distribution

Segment Overview

regulated and typically operate under long-term concessions giving them an exclusive right to deliver gas in a designated service area. Our businesses in this segment are summarized in the table shown below:


Natural Gas Distribution
			AE
			Ownership								Scheduled
			Interest						2007		Termination
			(Direct and						Average		Date of		Approximate
			Indirect) as of						Sales		Principal		Number			Approximate			Network
			December 31,			Operating			Volume		Concession		of Customers			Number of			Size
Business	Country		2007			Control⁽¹⁾			(mmcfd)		Agreement		(Thousands)			Employees			(Miles)

Promigas				52.13	%
Surtigas		Colombia		49.85	%		Yes	⁽²⁾		29		2034		427			338			4,740
Gases de Occidente		Colombia		41.46	%		Yes	⁽²⁾		46		2014		573			312			3,798
Gases del Caribe		Colombia		16.16	%		No			113		2028		858	⁽³⁾		406	⁽³⁾		6,120
Cálidda		Peru		80.85	%		Yes			176		2033		8			141			310
BMG⁽⁴⁾		China		10.23	%		Yes			5		2018		101			691			1,118
Tongda		China		100.00	%		Yes			5		2026		114			615			1,223

										374				2,083			2,503			17,309


(1)		“Operating Control” means that AEI either has a controlling interest in the business, control of the business through a majority owned subsidiary or operates the business through an operating agreement.

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

(3)		Includes its consolidated subsidiaries, Gases de la Guajira, Gases del Quinido, Gases del Risaralda and Gas Natural del Centro. Promigas owns a small direct interest in Gases de la Guajira.

(4)		On January 30, 2008, we acquired an additional 59.77% interest in BMG, which increased our ownership to 70.00%.

The natural gas distribution segment accounted for 10.6% of our net revenues, 12.0% of our operating income and 9.5% of our Adjusted EBITDA in 2007.

Promigas

Promigas is a Colombian holding company with investments mainly in transportation and gas services, natural gas distribution and retail fuel. See “— Natural Gas Transportation and Services — Promigas S.A., ESP (Promigas)” and “— Retail Fuel — Promigas.”

Promigas holds interests in three of our businesses providing natural gas distribution services to over 1.9 million customers throughout Colombia, representing 40% of the total market as of December 31, 2007. Each distribution company has limited competition in its area and competes only with alternative energy sources.

Each of Surtigas, Gases de Occidente and Gases del Caribe provide non-bank financing to lower income customers for the initial fees associated with the gas connections to the network. They also provide additional non-bank financing to customers with good payment records to finance additional gas-related items, such as gas appliances 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. The loans are unregulated and cannot exceed the usury rate.

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

Overview

Surtigas is a natural gas distribution and commercialization company serving towns in the areas of Bolívar, Sucre and Cordoba, located on Colombia’s north coast. As of 2007, Surtigas’ network covered 83% of its service area and connected 89% of its connectable households and businesses to natural gas services. Promigas currently owns 99.89% of Surtigas. In 2007, Surtigas recognized revenues of $90 million, operating income of $25 million, depreciation and amortization of $2 million and had a net debt of $64 million, which is derived from total debt of $68 million, less $4 million of cash and cash equivalents.

The table below provides a summary of Surtigas’ operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Customers (thousands)		373		404		427
Annual growth		6%		8%		6%
Volume transported (Bcf)		11.6		11.6		10.5
Network penetration⁽¹⁾		91%		95%		83%
Percent connected⁽²⁾		82%		86%		89%


(1)		“Network penetration” refers to the covered service area.

(2)		“Percent connected” refers to the percentage of the covered service area which is connected to the network.

Concession and Contractual Agreements

Surtigas operates under a concession agreement with the Colombian MME which expires in 2034 and has a 20-year renewal option. Since 1994, a concession has no longer been required to provide gas distribution as a public service in Colombia.

Customer Base

Of the approximately 427,300 natural gas users served by Surtigas, 99% are residential customers and 1% are commercial and industrial customers. During 2007, 63% of Surtigas’ volumes were distributed to industrial customers.

Operations

Surtigas had no service interruption between 2004 and 2007.

Surtigas has certifications under ISO 9001 and NTC ISO/IEC 17025. As of December 31, 2007, Surtigas had 338 employees.

Financing

As of December 31, 2007, Surtigas had outstanding debt of $68 million.

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

Overview

Gases de Occidente is a natural gas distribution and commercialization company serving 24 towns in the area of Valle del Cauca, located on Colombia’s west coast. As of 2007, Gases de Occidente’s network covered 97% of the potential market and connected 71% of its connectable households and businesses to natural gas services. Promigas currently owns 90.12% of Gases de Occidente. In 2007, Gases de Occidente recognized revenues of $141 million, operating income of $40 million, depreciation and amortization of $2 million and had a net debt of $55 million, which is derived from $60 million of total debt, less $5 million of cash and cash equivalents.

The table below provides a summary of Gases de Occidente’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Customers (thousands)		464		521		573
Annual growth		15%		12%		10%
Volume transported (Bcf)		13.8		15.0		17.0
Network penetration⁽¹⁾		85%		97%		97%
Percent connected⁽²⁾		69%		67%		71%


(1)		“Network penetration” refers to the covered service area.

(2)		“Percent connected” refers to the percentage of the covered service area which is connected to the network.

Concession and Contractual Agreements

Gases de Occidente operates under a concession agreement with the Colombian MME, for exclusive service areas which expires in 2014 (when the term ends this area will change to being regulated by CREG) and for non-exclusive service areas in 2047. Since 1994, a concession has no longer been required to provide gas distribution as a public service in Colombia.

Customer Base

Of the approximately 573,000 natural gas users served by Gases de Occidente, 99% are residential customers and 1% are commercial and industrial customers. During 2007, Gases de Occidente distributed 17 billion cubic feet, 75% of which was distributed to industrial customers.

Operations

Gases de Occidente had system losses of (0.30%) in 2005, (0.10%) in 2006 and a gain of 0.1% in 2007. Gases de Occidente had 611 hours of service interruption in 2005, 364 hours in 2006 and 290 hours in 2007.

Gases de Occidente has certifications under ISO 9001. As of December 31, 2007, Gases de Occidente had 312 direct employees.

Financing

As of December 31, 2007, Gases de Occidente had outstanding debt of $60 million.

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

Overview

Gases del Caribe is a natural gas distribution and commercialization company serving 60 municipalities in the states of Magdalena, Cesar and Atlántico, located on Colombia’s north coast. As of December 31, 2007, Gases del Caribe’s network covered 95% of the potential market and connected 79% of its connectable households and businesses to natural gas service. Promigas owns 30.99% of Gases del Caribe and has an option to acquire control of Gases del Caribe (which option has not been exercised).

The table below provides a summary of Gases del Caribe’s operational information for the dates indicated:


	As of and for the Year Ended December 31,
	2005		2006		2007

Customers (thousands)⁽¹⁾		733		794		858
Annual growth		5%		8%		8%
Volume transported (Bcf)⁽¹⁾		33.7		36.0		40.6
Network penetration⁽²⁾		91%		94%		95%
Percent connected⁽³⁾		79%		81%		79%


(1)		Includes its consolidated subsidiaries, Gases de la Guajira, Gases del Quinido, Gases del Risaralda and Gas Natural del Centro.

(2)		“Network penetration” refers to the covered service area.

(3)		“Percent connected” refers to the percentage of the covered service area which is connected to the network.

Concession and Contractual Agreements

Gases del Caribe operates under concession agreement with the Colombian MME, which expires in 2028. Since 1994, a concession has no longer been required to provide gas distribution as a public service in Colombia.

Customer Base

Of the approximately 570,000 natural gas users served directly by Gases del Caribe, 98% are residential customers and 2% are commercial and industrial customers. During 2007, Gases del Caribe distributed 34 mmcf, 85% of which was distributed to industrial customers.

Operations

Gases del Caribe had 2.93 hours of service interruption in 2005, 46.45 hours in 2006 and 33.03 hours in 2007.

Gases del Caribe has certifications under ISO 9001 and NTC ISO/IEC 17025. As of December 31, 2007, Gases del Caribe had 406 employees.

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

Overview

Our subsidiary Cálidda is a Peruvian natural gas distribution company that owns the concession to operate in the Department of Lima and Callao province. In June 2007, we jointly, with our subsidiary Promigas, acquired a 100% interest in Cálidda. AEI has a 80.85% indirect interest in Cálidda. In 2007, we recognized from Cálidda revenues of $37 million, operating income of $4 million and depreciation and amortization of $3 million. As of December 31, 2007, Cálidda had net debt of $32 million, which is derived from total debt of $82 million, less $14 million of cash and cash equivalents and less $36 million of current restricted cash.

Concession and Contractual Agreements

Cálidda has a 33-year build, own, operate and transfer concession agreement with the Peruvian Government, which was assigned to Cálidda in 2002 and is extendable for up to 60 years. Cálidda’s commercial operations under the concession began in August 2004. Having met the initial conditions of the concession, Cálidda receives a minimum capacity payment equivalent to a capacity of 225 mmcfd through 2011 and equivalent to 255 mmcfd thereafter. Cálidda is obligated to build a secondary distribution network able to connect 30,000 and 70,000 customers in the fourth and sixth year of commercial operations, respectively. To date, Cálidda met its obligations under the concession in 2008.

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. Under this agreement, Cálidda has contracted a fixed capacity per day for the 2004-2009 period for volumes between 1.9 mmcfd to 123.6 mmcfd. An amendment to the natural gas supply contract to synchronize the supply and transportation contracts has been proposed by Cálidda to the Camisea Consortium (this amendment is still pending). In December 2007, Cálidda increased the firm and interruptible transportation capacity contracted with Transportadora de Gas del Perú S.A. through June 2012 and August 2011, respectively.

Customer Base

Cálidda’s customers fall into two categories: non-regulated customers (users that consume more than 1 mmcfd) and regulated customers (predominantly residential and small commercial users). As of December 2007, 74% of Cálidda’s demand was generated by non-regulated customers, which include seven industrial customers and two electricity generation facilities. As of December 2007, Cálidda had approximately 8,000

residential and commercial customers, 207 industrial customers, 22 CNG service station customers and had capacity to connect approximately 66,000 regulated customers.

Operations

As of December 2007, Cálidda operated and maintained 310 miles of pipelines which consisted of a 20-inch main trunkline and six-inch lines to clusters connecting industrial customers and nearby residential and commercial customers. In order to facilitate conversion costs for new customers, Cálidda offers financing to cover the cost of connection fees. As of December 2007, over 75% of its residential customers have utilized this financing.

Cálidda has contracted with affiliates to provide operational and maintenance service, and commercial and administration support.

Financing

As of December 31, 2007, Cálidda had outstanding debt of $82 million.

Beijing Macrolink Gas Co., Ltd. (BMG)

Overview

In December 2007, we acquired a 10.23% interest in BMG and in January 2008, an additional 59.77% interest. BMG builds city gas pipelines, sells and distributes piped gas, and also operates auto-filling stations in China. BMG has successfully pursued and developed new city gas businesses through franchise acquisitions and privatizations. BMG holds controlling interests in 14 city gas companies, servicing a total of approximately 123,600 connected users out of a total of approximately 1,128,000 connectable users, out of a population of approximately 3.9 million.

Concession and Contractual Agreements

BMG’s subsidiary companies 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. BMG has the right to build out its franchise area but is not obligated to do so.

Customer Base

In 2007, BMG distributed approximately 199,000 mmcf of gas, 76% of which went to industrial and commercial customers and 24% to residential customers.

Operations

In five of the 14 cities currently serviced by BMG, BMG distributes natural gas supplied from domestic gas fields by way of compressed or liquefied natural gas trucks. Four cities are supplied with natural gas by domestic long-distance pipelines, four cities distribute re-gasified LPG supplied from domestic LPG station by way of LPG trucks and one city is served by coal gas from domestic production. BMG’s distribution network is under construction in one city.

Tongda Energy Private Limited (Tongda)

Overview

In August 2007, we acquired a 100% equity interest in Tongda. Tongda builds city gas pipelines, sells and distributes piped gas, and also operates auto-filling stations in China. Tongda has successfully pursued and developed new city gas businesses through franchise acquisitions and privatizations. Tongda holds controlling interests in ten city gas companies, servicing a total of approximately 177,000 connected users out of a total of approximately 621,000 connectable users, out of a population of approximately 2.2 million. Tongda is in

the process of obtaining certain approvals to build an 88-mile long, high-pressure gas transportation pipeline between Baoying and Dafeng city in Jiangsu province, a pipeline connected to the China West-East Gas Pipeline. In 2007, we recognized from Tongda revenues of $8 million, operating loss of $6 million, and depreciation and amortization of $1 million. As of December 31, 2007, Tongda had net debt of $(1) million, which is derived from total debt of $9 million, less $10 million of cash and cash equivalents.

Concession and Contractual Agreements

Tongda’s subsidiary companies 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. Tongda has the right to build out its franchise area but is not obligated to do so.

Customer Base

In 2007, Tongda distributed approximately 1,800 mmcf of gas, 80% of which went to industrial and commercial customers and 20% to residential customers.

Operations

In six of the ten cities serviced by Tongda, Tongda distributes natural gas supplied from domestic gas fields by way of compressed or liquefied natural gas trucks while the other three are supplied with natural gas by domestic long-distance pipelines. One company distributes LPG by way of trucks. Tongda’s prominent position in more affluent regions of China increases its ability to expand its gas distribution portfolio and to generate new business opportunities in other gas-related business activities.

Retail Fuel

Segment Overview

Our Retail Fuel businesses primarily distribute and sell liquid fuels and compressed natural gas (CNG) to retail customers. In addition to owning, licensing and operating outlets, these businesses own fleets of bulk-fuel distribution vehicles. The businesses in this segment are listed in the table below:

Retail Fuel

AEI Ownership

Interest

(Direct and

Indirect) as of

Approximate

December 31,

Operating

2007

Number of

Business

Country

2007

Control⁽¹⁾

Product Sold

Volume Sold

Employees

Promigas

52.13

Gazel⁽²⁾

Colombia, Chile, Mexico, Peru

51.93

Yes

Compressed
Natural Gas

11,758 million
cubic feet

621

SIE

37.19

Terpel⁽²⁾

Colombia, Ecuador, Panama, Chile

15.07

Gasoline,
Diesel, Jet
Fuel,
Lubricants

1,683 million
gallons

3,037

3,658


(1)		“Operating Control” means that AEI either has a controlling interest in the business or operates the business through an operating agreement or through control of Promigas.

(2)		On January 2, 2008, Promigas contributed its ownership interests in its wholly-owned subsidiary Gazel to SIE in exchange for additional shares of SIE. SIE subsequently transferred Gazel to its subsidiary Terpel. We currently own 24.95% of Terpel and 24.95% of Gazel.

The retail fuel segment, including Vengas, accounted for 4.8% of our net revenues, 6.9% of our operating income and 5.3% of our Adjusted EBITDA for 2007. On November 15, 2007, we sold our interests in Vengas to PDVSA Gas.

Promigas

Overview

Promigas is a Colombian holding company with investments mainly in natural gas transportation and services, natural gas distribution and retail fuel. See “— Natural Gas Transportation and Services — Promigas” and “— Natural Gas Distribution — Promigas.”

Promigas’ retail fuel businesses have 1,759 service stations (1,596 gasoline and 163 CNG) as of December 31, 2007 and a market share in Colombia by volume of 39% for gasoline, 12% for lubricants and 41% for aviation fuel. Its CNG business for vehicles has 40% market share by volume.

Promigas — Sociedad de Inversiones en Energia (SIE)

SIE is the holding company of Terpel. Promigas owns 37.19% of SIE as of December 31, 2007, which indirectly owns 77.75% of Terpel. See “Item 5. Operating and Financial Review and Prospects — Recent Developments.”

Organización Terpel Inversiones S.A. (Terpel)

Terpel’s main business units are wholesale, retail, aviation gasoline distribution and lubricant sales. The wholesale business currently has a 39% national market share. In 2007, we recognized equity earnings of $12 million from Terpel. Terpel is a non-core business for us.

The table below provides a summary of Terpel’s operational information for the dates indicated:


	As of and for the Year Ended
	December 31,
	2005		2006		2007

Number of owned stations		162		160		418
Number of affiliate stations		1,105		1,119		1,178
Gallons of sales per day
Wholesale		2,766,929		2,749,854		2,698,455
Retail		420,823		418,232		422,096
Aviation		117,600		166,536		336,114
Lubricants		15,868		15,569		13,222
Fuel margin per gallon ($)
Wholesale	$	0.09	$	0.09	$	0.13
Retail	$	0.13	$	0.13	$	0.22
Aviation	$	0.28	$	0.24	$	0.29
Lubricants	$	2.71	$	2.58	$	3.53

Gasoline is a highly competitive market operating under conditions characterized by an oligopoly. Terpel has positioned itself mostly in medium and small cities, while multinationals such as Exxon-Mobil, Petrobras, and Texaco are leaders in large cities. Terpel has been able to increase its market share in gasoline distribution from 28% to 39% (and is the Colombian market leader by volume) in the past five years by marketing and opening new gasoline stations.

Tariffs and margins to gasoline retailers are regulated by the Colombian MME and have been fairly stable due to a strong lobbying effort. In past years, the Colombian MME has been decreasing subsidies on gasoline prices which are currently indexed (generally with a lag) to international oil prices. With gross margins between 5% and 7%, cost management is the key to maintaining attractive returns.

In August 2007, the Colombian MME issued a new resolution modifying the wholesale margins applicable to gasoline and diesel. Both of these products are regulated by the government, which establishes the price structure for liquid fuels, including margins. The new resolution approved an increment of $0.04 per gallon

margin increase, resulting in a $0.125 margin for gasoline and a $0.13 margin for diesel. The new margins were applicable from September 1, 2007 and the change has been implemented gradually through April 2008, increasing by $0.005 per month.

Terpel is also expanding outside of Colombia, and has recently completed the following transactions:


	•	In 2006, the acquisition of 65 service stations from Chevron of its distribution and retail business in Ecuador representing 8% of the market;

	•	In February 2007 the acquisition of Petrolera Nacional in Panama with 53 service stations marketing under the brand name Accel and holding a 12% market share of Panama’s gasoline and lubricant business; and,

	•	The acquisition at the end of 2007 of Repsol retail gasoline and industrial sales business in Chile, with 206 services stations and a 10% market share.

Operations

Terpel is a retail gasoline chain and operates a retail and gasoline distribution business, and sells petroleum lubricants. In Colombia, the gasoline distribution business operates in 46 cities, through 156 company-owned service stations, 1,117 affiliated stations and 28 supply centers. Terpel has certifications under ISO 14001 and ISO 9001 (lubricants facility), and ISO 14001, ISO 9001 and OHSAS 18001 (Gualanday-Nieve pipeline).

Terpel is active in the aviation fuel market and services 19 airports nationwide, including Colombia’s largest airport, El Dorado in Bogotá. Market share in the aviation business as of 2007 was 41% and amounted to 110 million gallons sold.

Gas Natural Comprimido S.A. (Gazel)

Overview

Gazel sells compressed natural gas, or CNG, as an automotive fuel in Colombia. Gazel operates 163 service stations under the brand name Gazel throughout Colombia. In 2007, Gazel recognized revenues of $160 million, operating income of $34 million and depreciation and amortization of $2 million and as of December 31, 2007 had net debt of $65 million, which is derived from total debt of $69 million, less $4 million of cash and cash equivalents.

The CNG business has tax benefits for alternative fuels, as the Colombian government imposes heavy tax burdens on gasoline and diesel fuels, but no tax on CNG. In Colombia, Gazel is the largest CNG distributor, with a 40% share of the market, and is also looking at growth opportunities outside of Colombia. Gazel has entered the Peruvian, Mexican and Chilean markets, with six operating stations in Lima, Peru, three in Mexico City, Mexico and one in Santiago, Chile

The table below provides a summary of Gazel’s operational information for the dates indicated:


	As of and for the Year Ended
	December 31,
	2005		2006		2007

Number of stations		82		114		163
Sales per day per station (cubic feet)		227,000		231,000		188,876
Converted vehicles (cumulative)		96,276		168,523		235,058
Fuel margin per cubic foot ($)	$	0.005	$	0.005	$	0.007

Operations

The Colombian government promotes vehicle conversions to CNG, with the aim of increasing the use of natural gas, an ample resource in Colombia, and to reduce consumption of foreign-sourced oil and oil products.

CNG competes with the regulated price of gasoline by maintaining a targeted discount. Together with the conversion costs associated with making vehicles capable of running on CNG, the price differential between gasoline and natural gas drives the competitiveness of CNG. Gasoline prices have been increasing due to higher crude oil prices and the gradual removal of Colombian government subsidies on gasoline. This has increased conversions to CNG in the past.

The competitive advantage of CNG over gasoline is measured by a payback period based on the customer’s initial investment in a conversion kit versus resulting lower cost of fuel. Analysis indicates that users generally recover their investment within six to ten months. Gazel must maintain a price 40% to 50% lower than gasoline to maintain the current payback time. Currently, Gazel’s price is 49% lower than the price of gasoline.

Conversion kits are fully financed by Promigas’ LDCs. This additional source of revenues has significantly increased due to a substantial increase in conversions in recent years. Gazel has a competitive advantage due to its technical expertise in the business.

Operations in Chile began in January 2008 with one service station in Santiago.

Gazel has certifications under ISO 9001.

C. Organizational Structure

Our Segments and Businesses

The following summary tables set forth our interests in the businesses comprising our segments.


			AEI Ownership % as
			of
Business	Full Legal Name	Country	September 30, 2008

*Power Distribution*
Chilquinta	Chilquinta Energía S.A.	Chile		50.00	%
Delsur	Distribuidora de Electricidad Del Sur, S.A. de C.V.	El Salvador		86.41	%
EDEN⁽¹⁾	Empresa Distribuidora de Energía Norte S.A.	Argentina		90.00	%
Elektra	Elektra Noreste, S.A.	Panama		51.00	%
Elektro	Elektro Eletricidade e Serviços S.A.	Brazil		99.68	%
Luz del Sur⁽²⁾	Luz del Sur S.A.A.	Peru		37.94	%

*Power Generation*
Corinto	Empresa Energética Corinto Ltd.	Nicaragua		50.00	%
DCL	DHA Cogen Limited	Pakistan		57.13	%
ENS	Elektrocieplownia Nowa Sarzyna Sp. z o.o.	Poland		100.00	%
EPE	EPE — Empresa Produtora de Energia Ltda. (Cuiabá Integrated Project)	Brazil		50.00	%
Emgasud⁽³⁾	Emgasud S.A.	Argentina		31.89	%
JPPC	Jamaica Private Power Company Ltd.	Jamaica		84.40	%
Luoyang	Luoyang Sunshine Cogeneration Co., Ltd.	China		50.00	%
PQP	Puerto Quetzal Power LLC	Guatemala		100.00	%
San Felipe	Generadora San Felipe Limited Partnership	Dominican Republic		100.00	%
Subic	Subic Power Corp.	Philippines		50.00	%


			AEI Ownership % as
			of
Business	Full Legal Name	Country	September 30, 2008

Trakya	Trakya Elektrik Uretim ve Ticaret A.S.	Turkey		59.00	%
Tipitapa	Tipitapa Power Company Ltd.	Nicaragua		100.00	%

*Natural Gas Transportation and Services*
Accroven	Accroven S.R.L.	Venezuela		49.25	%
Centragas	Centragas (Promigas S.A., ESP)	Colombia		13.03	%
GBS	Gases de Boyacá y Santander, GBS S.A. (Promigas S.A., ESP)	Colombia		49.37	%
GOB	GasOriente Boliviano Ltda. (Cuiabá Integrated Project)	Bolivia		50.00	%
GOM	GasOcidente do Mato Grosso Ltda. (Cuiabá Integrated Project)	Brazil		50.00	%
GTB	Gas Transboliviano S.A. (Bolivia-to-Brazil Pipeline)	Bolivia		17.65	%
Promigas Pipeline	Promigas Pipeline (Promigas S.A., ESP)	Colombia		52.13	%
PSI	Promigas Servicios Integrados S.A. (Promigas S.A., ESP)	Colombia		49.11	%
TBG	Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (Bolivia-to-Brazil Pipeline)	Brazil		4.27	%
TBS	Transborder Gas Services Ltd. (Cuiabá Integrated Project)	Brazil		50.00	%
Transmetano	Transmetano S.A. ESP (Promigas S.A., ESP)	Colombia		49.78	%
Transoccidente	Transoccidente S.A. ESP (Promigas S.A., ESP)	Colombia		35.96	%
Transoriente	Transoriente S.A. ESP (Promigas S.A., ESP)	Colombia		13.73	%

*Natural Gas Distribution*
BMG	Beijing Macrolink Gas Co., Ltd	China		70.00	%
Cálidda	Gas Natural de Lima y Callao S.A.	Peru		80.85	%
Gases de Occidente	Gases de Occidente S.A. E.S.P. (Promigas S.A., ESP)	Colombia		46.97	%
Gases del Caribe	Gases del Caribe S.A. E.S.P. (Promigas S.A., ESP)	Colombia		16.16	%
Surtigas	Surtigas S.A. E.S.P. (Promigas S.A., ESP)	Colombia		52.07	%
Tongda	Tongda Energy Private Limited	China		100.00	%

*Retail Fuel*
SIE — Terpel⁽⁴⁾	Sociedad de Inversiones en Energia (Promigas S.A., ESP) and Organización Terpel Inversiones S.A. (SIE)	Colombia, Ecuador, Panama, Chile		24.95	%
SIE — Gazel⁽⁴⁾	Sociedad de Inversiones en Energia (Promigas S.A., ESP) and Gas Natural Comprimido S.A. (Promigas S.A., ESP)	Chile, Colombia, Mexico, Peru		24.95	%


D.	Property, Plant and Equipment

Properties by each business segment are presented below, as of December 31, 2007, unless otherwise noted.

Power Distribution


Business	Location	Description

Elektro	Brazil	approximately 64,500 miles of power distribution and transmission lines
Elektra	Panama	approximately 5,200 miles of power distribution and transmission lines
Luz del Sur	Peru	approximately 11,200 miles of power distribution and transmission lines
Chilquinta	Chile	approximately 4,900 miles of power distribution and transmission lines
Delsur	El Salvador	approximately 4,000 miles of power distribution and transmission lines
EDEN⁽¹⁾	Argentina	approximately 10,700 miles of power distribution and transmission lines


(1)		Pending local anti-trust approval.

Power Generation


		Generating
Business	Power Plant Location	Capacity (MW)	Fuel Type

Trakya	Turkey	478	Natural gas
Cuiabá — EPE	Brazil	480	Natural gas and fuel oil⁽¹⁾
Luoyang⁽²⁾	China	270	Coal
PQP	Guatemala	234	Bunker fuel
San Felipe	Dominican Republic	180	Diesel oil/bunker fuel
		116 electrical
ENS	Poland	70 thermal	Natural gas
Subic	Philippines	116	Bunker fuel
Corinto	Nicaragua	70	Bunker fuel
Tipitapa⁽³⁾	Nicaragua	51	Bunker fuel
JPPC	Jamaica	60	Bunker fuel
DCL⁽⁴⁾	Pakistan	94	Natural gas
Emgasud⁽⁵⁾	Argentina	66	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)		On February 5, 2008, we acquired a 48% interest in Luoyang and an additional 2% interest on June 6, 2008.
(3)		On June 11, 2008, we acquired a 100% interest in Tipitapa.
(4)		On July 18, 2008, we acquired a 48% interest in DCL. Since the additional acquisition, we have executed additional share subscription agreements that have resulted in an increase in our ownership to 60.22%.

(5)		On November 28, 2008, we acquired a 28.00% equity interest in Emgasud. On December 23, 2008 we made a second capital contribution, thereby increasing our ownership interest to 31.89%.

Natural Gas Transportation and Services


Business	Location	Description

Promigas
Promigas Pipeline	Colombia	1,297 miles pipeline system in La Guajira region, to Jobo station in Department of Sucre
Transmetano	Colombia	93 mile pipeline in the Cauca Valley
GBS	Colombia	196 mile pipeline in Boyacá and Santander
Centragas	Colombia	458 mile pipeline in the regions of La Guajira, Cesar and Santander
PSI	Colombia	natural gas drying and compression facility at Ballena station
Transoccidente	Colombia	7 mile pipeline in the Cauca Valley
Transoriente	Colombia	98 mile pipeline in Bucaramaga
Cuiabá
GOB	Bolivia	225 mile pipeline connecting to GOM pipeline
GOM	Brazil	175 mile pipeline in Mato Grosso connecting to GOB pipeline
Accroven	Venezuela	NGL extraction facilities at San Joaquín and Santa Bárbara gas fields
		NGL fractionation, storage and refrigeration facilities in Jose petrochemical complex on Northeastern coast
BBPL
GTB	Bolivia	346 mile pipeline from Station Rio Grande to Station Mutun and connecting to TBG pipeline
TBG	Brazil	1,611 mile pipeline from GTB pipeline at Station Mutun, Bolivia to southeastern Brazil

Natural Gas Distribution


Business	Location	Description

Promigas
Surtigas	Colombia	4,740 miles of mains in Bolívar, Sucre and Cordoba
Gases de Occidente	Colombia	3,798 miles of mains in Valle del Cauca
Gases del Caribe	Colombia	6,120 miles of mains in Magdalena, Cesar, Atlántico and La Guajira
Cálidda	Peru	310 miles of mains in Lima and Callao provinces
BMG⁽¹⁾	China	1,118 miles of mains in 14 service areas
Tongda	China	1,223 miles of mains in 10 service areas in Jiangsu province

(1) In December 2007, we acquired a 10.23% interest in BMG and an additional 59.77% interest in January 2008.

Retail Fuel


Business	Location	Description

Promigas
Gazel	Colombia	153 service stations
	Mexico	3 service stations
	Peru	6 service stations
	Chile	1 service station
Terpel	Colombia	1,276 service stations, including 28 supply stations
	Chile	206 service stations
	Ecuador	65 service stations
	Panama	53 service stations

Item 5. Operating and Financial Review and Prospects

This discussion should be read together with the “Item 3. Key Information — A. Selected Financial Data,” the consolidated financial statements and PEI’s consolidated financial statements included elsewhere in this registration statement. Unless otherwise indicated, the financial data contained in this registration statement has been prepared in accordance with 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 10 to the unaudited condensed consolidated financial statements for the nine months ended September 30, 2008 and Note 12 to the consolidated financial statements for the year ended December 31, 2007. The consolidated financial statements for the year ended December 31, 2007 account for Accroven, Chilquinta, GTB, Luz del Sur, Promigas’ equity method investments, Subic, and Transredes under the equity method of accounting and for BMG and TBG under the cost method. In 2008, BMG is consolidated and beginning in May 2008, GTB is accounted for using the cost method. Promigas was consolidated as of December 31, 2006 and for the full year ended December 31, 2007. During the year ended December 31, 2006, Promigas was accounted for under the equity method. All intercompany transactions and balances have been eliminated in consolidation. From May 25, 2006 to September 6, 2006, PEI was accounted for using the equity method of accounting and consolidated thereafter.

Overview

Our Business

We manage, operate and own interests in essential energy infrastructure businesses in emerging markets across multiple segments of the energy industry. Our company consists of 39 businesses which we aggregate into the following reportable segments: Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel. For the year ended December 31, 2007, we generated consolidated revenues of $3.2 billion, consolidated operating income of $577 million, and consolidated net income of $131 million. For the nine months ended September 30, 2008, we generated consolidated revenues of $7.2 billion, consolidated operating income of $653 million, and consolidated net income of $125 million.

Recent Developments

Acquisitions

It is our strategy to own and operate essential energy infrastructure assets in emerging markets and grow our business through a combination of greenfield development and acquisitions. In 2007, we acquired interests in eight new businesses and increased our ownership in four of our existing businesses. In total, in 2007, we invested $1.4 billion in acquisitions. In 2008, we acquired interests in five new businesses and increased our ownership in four of our existing businesses, investing a total of approximately $319 million.

The following transactions have been completed in 2008:


	•	Promigas contributed its ownership interests in its wholly owned subsidiary Gazel to SIE, in exchange for additional shares of SIE on January 2, 2008. Promigas’ ownership in SIE increased from 37.19% to 54%. SIE now owns 88.7% of Gazel through its subsidiary Terpel. We currently own 24.95% of Terpel and 24.95% of Gazel.

	•	Acquisition of an additional 59.77% interest in BMG and its subsidiaries, which was completed on January 30, 2008.

	•	Acquisition of a 50.00% interest in Luoyang. The acquisition of a 48.00% interest was completed on February 5, 2008 and an additional 2.00% interest was acquired on June 6, 2008.


	•	Promigas purchased additional interests in its affiliates Surtigas and Gases de Occidente on March 7, 2008 for $9 million and $40 million, respectively. Promigas’ ownership in these businesses has increased to 99.89% and 90.10%, respectively.

	•	Acquisition of a 100.0% interest in Tipitapa for $18 million on June 11, 2008. Tipitapa owns a 50.9 MW diesel electric generation facility located approximately 12 miles east of Managua, Nicaragua, which began operations in 1999.

	•	Acquisition of a 60.22% interest in DCL for approximately $29 million in a series of transactions from July through January of 2009. DCL owns a 94 MW combined cycle electric generation plant and a 3 million gallons per day water desalination facility located in Karachi, Pakistan, which began operations in 2008.

	•	A subsidiary of the Company was awarded, on May 5, 2008, 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-fixed generating facility. A subsidiary of the Company also executed power purchase agreements to sell capacity and energy for 15 year terms.

	•	Acquisition of an 85% interest in Fenix, a Peruvian company developing a 544 MW combined cycle power plant in Chilca, Peru on June 26, 2008. The interest was acquired for $100 million cash paid at the closing.

	•	Acquisition of a 28.00% equity interest in Emgasud S.A., an Argentine energy corporation focused on the electricity and gas industries on November 28, 2008. On December 23, 2008, we made a second capital contribution to Emgasud of $10 million which increased our ownership interest in Emgasud to 31.89%.

	•	On December 8, 2008, we signed an agreement with Centrans to contribute our respective interests in various Nicaragua power companies to a common holding company, Nicaragua Energy Holdings, a Cayman Islands company. This transaction closed on January 1, 2009, and currently we own 57.67% and Centrans owns 42.33% of Nicaragua Energy Holdings, which indirectly owns 100% of Corinto and Tipitapa and an interest in the Amayo wind project. In addition, we gave Centrans a call option that may be exercised at any time prior to December 8, 2013 to increase its interest in Nicaragua Energy Holdings up to 50%.

Disposals

On March 14, 2007, we disposed of our 51.00% indirect interest in BLM for $47.5 million.

On November 15, 2007, we disposed of our 98.13% interest in Vengas to PDVSA Gas for $73 million.

On December 12, 2007, we sold 0.75% of our interest in Promigas, S.A. for $19 million. This resulted in a reduction of our ownership interest in Promigas from 52.88% to 52.13% and in Cálidda from 81.15% to 80.85%.

On May 20, 2008, we sold our debt interests in Gas Argentino S.A. for $38 million.

On November 26, 2008, Chilquinta, which we hold a 50.00% equity interest in sold an 89% equity interest in its subsidiary ENERGAS S.A. for $41 million.

Bolivia Hydrocarbons Nationalization

2.62% ownership interest) from TR Holdings at a price of $48 per share. The Expropriation Decree provided that YPFB would make the purchase price available for immediate collection and that YPFB would adopt necessary measures to control and manage Transredes. It further provided that TR Holdings would guarantee the continuity and validity of all service contracts, insurance and other contracts of Transredes and that Transredes was prohibited from disposing of assets, goods or taking other actions that could make its operations more costly or prevent operations of affiliates. The Decree also stated that YPFB would not assume any contingent liability of the former administration of Transredes for actions or decisions taken by the controlling shareholders before May 1, 2008. Finally, the Decree stated that within 30 days from the date of publication of the decree, the executive president of YPFB would take all corporate measures necessary to guarantee the exercise of the majority shareholding in accordance with the articles of Transredes, among them the appointment of a new board of directors, management positions and change of company’s name. 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. The government subsequently registered these shares in YPFB’s name. At that time, TR Holdings had not been compensated for these shares and we filed an arbitration claim against the Bolivian government, among other things, demanding full compensation. On October 17, 2008, we entered into an agreement with YPFB, recognized by the Bolivian government, pursuant to which YPFB agreed to pay us $120 million in two equal installments and we withdrew the arbitration proceeding against the Republic of Bolivia. The first payment of $60 million was made on October 22, 2008 and the second payment of $60 million was made on March 2, 2009.

Elektro 2007 Tariff Review

Prior to 2007, Elektro’s tariff was last reset in accordance with local regulations in August 2003. Following the 2003 tariff reset, Elektro recorded increased margins primarily due to faster growth in electricity consumption in its concession area in the years following that review. To return Elektro to its regulated rate of return, during the August 2007 review, Elektro’s tariff for residential and small commercial customers was reduced by 20.65% and the tariffs for large customers were reduced between 13.57% and 21.62% depending on their load modulation. The tariff reduction negatively impacted our results starting in the fourth quarter of 2007, and will have further negative impacts in 2008 as the tariff reduction will have been in place for a full year (compared to approximately three months in 2007). Our gross margin in the first nine months of 2008 compared to the same period in 2007 was reduced by $6 million, offset by a significant appreciation of the real against the US dollar. Elektro’s next tariff review is scheduled to occur in August 2011. The tariff reduction observed in the 2007 tariff review reflects the high returns that Elektro had been able to achieve during the four years since the 2003 tariff review, as a result of its efficient operations, overall market growth and changes in its customer mix. Elektro received a tariff adjustment in August 2008 and increased the average tariff by 11.63%. See “Item 4. Information on the Company — B. Business Overview — Elektro Electridade e Serviços S.A. (Elektro) — Tariffs” for details on Elektro’s tariff review process.

Cuiabá Integrated Project

In early 2007, under the terms of the nationalization of the Bolivian gas industry, the state-owned entity Yacimientos Petrolíferos Fiscales Bolivianos, or YPFB, became the only authorized seller of natural gas in Bolivia. Delivery of gas under existing gas supply agreements from other upstream producers, including one with TBS, the supplier of gas to EPE, have been suspended.

In June 2007, TBS and YPFB entered into a provisional gas supply agreement pursuant to which the gas price increased to $4.20 per MMBtu. The provisional gas supply agreement contemplated that the parties would enter into a definitive gas supply agreement which would provide for guaranteed volumes of 38.8 mmcfd from July 2007 through December 2009, which would be sufficient to run EPE under a 50% capacity factor, and 77.9 mmcfd afterwards, which would be enough to run the plant at 100% capacity factor, through May 2019. TBS and YPFB have periodically extended the provisional gas supply agreement. The latest provisional agreement expired on June 30, 2008 and negotiations regarding an extension to this agreement, as well as a permanent GSA, are currently on hold. See “Item 4. Information on the Company — B. Business

Overview — Power Generation — Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE) — Concession and Contractual Agreements” and “Item 4. Information on the Company — B. Business Overview — Natural Gas Transportation and Services “Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS) — Concession and Contractual Agreements.”

Increasing demand for natural gas, force majeure issues, operational issues at the gas fields in Bolivia and the adverse effects on production of natural gas resulting from the nationalization of the Bolivian hydrocarbon industry, have significantly reduced the gas supply from Bolivia to our Cuiabá Integrated Project. EPE has experienced periods of no gas supply resulting in periodic shutdowns and has generally not been operational since August 2007. Furnas, EPE’s sole offtaker, has been refusing to make capacity payments. EPE disagrees with Furnas’ position and initiated an arbitration proceeding against Furnas in December 2007. The Bolivian government has indicated that gas availability may continue to be limited in the short- and medium-term. As a result of a Brazilian government order, EPE entered into an agreement on March 31, 2008 with Furnas to operate on diesel fuel for a maximum of 120 days. EPE operated for approximately one month under this agreement and its term has now expired.

On October 1, 2007, we received a notice from Furnas purporting to terminate the power purchase agreement as a result of the current lack of gas supply. We strongly disagree with Furnas’ position and we have initiated an arbitration proceeding in accordance with the power purchase agreement. We expect a decision in this arbitration in mid 2009.

If we are unable to secure an adequate supply of gas from Bolivia to EPE or find acceptable alternative sources of fuel supply, or we are unable to satisfactorily resolve our dispute with Furnas, the operations of the Cuiabá Integrated Project will be materially adversely effected. Under these circumstances, there will be a corresponding impact on our financial performance and cash flows which could be material. We are unable at the current time to predict the ultimate impact or duration of the current issues at the Cuiabá Integrated Project. We recognized $68 million of revenues related to EPE in 2007 (see Note 4 to the consolidated financial statements for the year ended December 31, 2007). We recognized $16 million of revenues related to EPE in the three months ended September 30, 2008.

GIC Investment

On May 9, 2008, GIC Special Investments Pte Ltd., or GIC, purchased from us in a private placement 12.5 million of our ordinary shares at a subscription price of $16 per share. 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. We received gross proceeds from this issuance to GIC of $200 million which we intend to use for general corporate purposes. On May 9, 2008, GIC also purchased 12.5 million of our ordinary shares from certain of our shareholders. Simultaneous with the closing of these transactions, George P. Kay, a nominee of GIC, was appointed to our board of directors. Following these transactions, GIC held approximately an 11% ownership interest in us.

Subsequently, in a series of transactions that took place during the fourth quarter of 2008 and the first quarter of 2009, GIC purchased approximately 29.5 million additional ordinary shares of ours from certain of our shareholders, which increased their ownership interest in us to 24.30%.

Legal Proceedings

In January 2009, CIESA filed a complaint against AEI in New York state court seeking a judgment declaring that any claim by AEI against CIESA under the CIESA debt held by AEI is time-barred because the statute of limitations pertaining to any such claim has expired. AEI does not believe that there is any merit to the suit and has filed a motion to dismiss the complaint in its entirety. In February 2009, AEI, as the sole holder of CIESA’s outstanding notes, filed a petition in Argentina for the involuntary bankruptcy liquidation of CIESA. The Argentine court granted our petition, which permits us to initiate bankruptcy proceedings against CIESA at any time prior to late May 2009. If we pursue this action, we will request the enforcement of our debt before the bankruptcy court at the proof of claims stage.

Our businesses 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. Our management evaluates the merit of each claim and assesses the likely outcome. Based on management’s assessment and the advice of counsel, it is not anticipated that the ultimate resolution of existing litigation will result in amounts in excess of recorded provisions that would have a material adverse effect on our financial position or results of operations. See Notes 4, 15, 18 and 26 to our consolidated financial statements for the year ended December 31, 2007 and Note 21 to our unaudited condensed consolidated financial statements for the nine months ended September 30, 2008 for more information on the status of our legal proceedings.

Elektro

Elektro is a party to approximately 5,000 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 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, 2008, we have accrued approximately $13 million (based on the exchange rate on December 31, 2008) related to these cases, excluding those described below.

In August 2001 Elektro filed two lawsuits against the State Highway Department — DER (the State of São 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 or under the control of the State Highway Department and such concessionaires. The lower court and the State Court ruled in favor of the State Highway Department. 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 a VAT assessment of approximately $7 million (based on the exchange rate on December 31, 2008) from the São Paulo State Treasury. Elektro believes that it has a strong basis on which to contest this assessment. It has presented an administrative defense and is awaiting an administrative decision.

In December 2008, Elektro received an additional VAT assessment of approximately $19 million (based on the exchange rate of December 31, 2008) from the São Paulo State Treasury. Elektro believes that it has a strong basis on which to contest this assessment. It has presented an administrative defense and is awaiting an administrative decision.

In December 2007, Elektro received two tax assessments issued by the Brazilian Internal Revenue Service (IRS), one alleging 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 $199 million (based on the exchange rate as of December 31, 2008) 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 IRS appealed this ruling to the Taxpayer Counsel, but Elektro believes that it is likely that the ruling will be confirmed.

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 we, 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 has accrued approximately $40 million (based on the exchange rate as of December 31, 2008) and made a judicial deposit of approximately $17 million (based on the exchange rate as of December 31, 2008) related to this issue and does not believe that the currently expected outcome under these lawsuits will exceed this amount or will have a material adverse effect on its financial condition, results of operations, or liquidity.

Promigas

A class action suit is pending against Promigas pursuant to which the plaintiffs seek to recover $5 million in damages resulting from a pipeline explosion caused by terrorists in October 2001. A reserve with respect to this claim has been established in the amount of $1.3 million. While the matter is still in the initial stages, we do not believe that the currently expected outcome will have a material adverse effect on our financial condition, results of operations, or liquidity.

EPE

On October 1, 2007, EPE received a notice from Furnas purporting to terminate the power purchase agreement with EPE as a result of the current lack of gas supply from Bolivia described elsewhere in this document. EPE notified Furnas that EPE believes Furnas had no contractual basis to terminate the power purchase agreement and initiated an arbitration proceeding in accordance with the power purchase agreement. If EPE is unable to satisfactorily resolve the dispute with Furnas, the operations of Cuiabá will be materially adversely affected with a corresponding impact on our financial performance and cash flows. We expect a decision in this arbitration in mid 2009.

San Felipe

In 1995, a demand for arbitration was filed against San Felipe in connection with San Felipe’s alleged breach of a settlement agreement arising from a nuisance dispute over San Felipe’s power plant in Puerto Plata, Dominican Republic, which was decided in favor of the plaintiff. In August 2006, a Dominican Republic appeals court ruled against San Felipe, upholding the award of approximately $11 million, including accrued interest and in March 2009 the Dominican Republic Supreme Court rejected San Felipe’s appeal and upheld the lower court’s ruling. The final amount of the award is currently being determined. The Company has accrued $10 million for this claim and does not believe the currently expected outcome will have a material adverse effect on its financial condition, results of operations, or liquidity.

Under San Felipe’s Power Purchase Agreement, 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, 2008, 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 $.0.3 million at the exchange rates as of December 31, 2008) 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. We have accrued approximately $65.6 million (based on the exchange rate as of December 31, 2008) with respect to the period from January 1998 through September 2008 which we believe is adequate. In addition, San Felipe has a contractual right under its Power Purchase Agreement to claim indemnification from CDEEE for taxes paid by San Felipe although we cannot be assured that any such amounts will be collected.

EDEN

In June 2003, during an audit of EDEN, the Argentine tax authorities asserted that there were deficiencies for the tax years 1997 to 1999 with respect to compliance with the Argentine Technical Services Act. In 1997, EDEN had entered into a management fee agreement with a non-resident related party, but only filed the agreement in accordance with the Technical Services Act in 1999 with retroactive effect since 1997. EDEN has challenged the results of the audit in the Fiscal Court (Tribunal Fiscal de la Nación). The case is currently pending. If EDEN does not prevail, it may be obligated to pay approximately $8 million, which represents the potential withholding tax and disallowed deduction of the management fees plus interest and penalties.

Elektra

In April 2006, Elektra was ordered by a local regulatory authority to reimburse $4 million to its customers in connection with alleged overcharging from July 2002 through June 2006. Elektra appealed this order and on December 22, 2008, Resolution No. 2269 was issued by the regulatory entity pursuant to which this order was revoked thereby relieving Elektra of any obligations to make this reimbursement.

TBS

TBS is currently assessing whether it may have some claims against a former supplier of gas. If TBS decides to initiate any such claims, it is possible that the supplier may file certain claims that it believes it may have against TBS.

Critical Accounting Policies and Estimates

This “Operating and Financial Review and Prospects” is based upon AEI’s, Elektra’s and PEI’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States, or 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, measurement of share-based compensation, accruals for income taxes, accruals for long-term employee benefit costs such as pension and other postretirement costs 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 the consolidated financial statements for the year ended December 31, 2007.

Basis of Presentation

The consolidated financial statements include the accounts of all wholly-owned companies, majority-owned subsidiaries and controlled affiliates. Furthermore, we consolidate variable interest entities where we are determined to be the primary beneficiary under Financial Accounting Standards Board, or FASB, Interpretation, or FIN 46 (revised December 2003), or FIN 46(R), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. Investments in entities where we hold an ownership interest of at least 20%, but not more than 50%, and which we neither control nor are the primary beneficiary, 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. Our ownership in PEI was accounted for using the equity method of accounting for the period from May 25, 2006 to

September 6, 2006. PEI’s financial position, results of operations, and cash flows are consolidated in our consolidated financial statements prospectively from September 7, 2006.

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 were 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, for significant acquisitions, we utilize valuations based on information available at the acquisition date.

Significant judgments and assumptions made regarding the purchase price allocation for the acquisition of PEI, Promigas and other entities included the following:

For entities with regulated operations, primarily Elektro and Promigas, management determined the fair values which reflected the regulatory framework of the specific country in which the assets reside. For non-regulated facilities, which do not conform to a regulatory framework, management utilized appraisals, in part, to determine asset and liability fair values. These appraisals were 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 considered the replacement value taking into consideration market reports and technology, as well as, adjusting for an estimated remaining useful life considering new construction. These appraisals used an indirect cost approach considering replacement costs. These replacement costs were 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 was 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 five to 50 years. Depreciation and amortization expense of these assets under the straight-line method over their estimated useful lives totaled $217 million in 2007. 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.

Revenue Recognition

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 sales from providing administrative, operations, and maintenance services to unconsolidated affiliates.

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. 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.

Power Distribution sales to final customers are recognized when power is provided. Billings for these sales are made on a monthly basis. Revenues that have been earned but not yet billed are accrued based upon the estimated amount of energy delivered during the unbilled period and the approved or contractual billing rates for each category of customer. Revenues received from other power distribution companies for use of the basic transmission and distribution network are recognized in the month that the network services are provided.

Revenue on net investments in direct financing leases is recognized over the term of the power purchase agreement based on a constant periodic rate of return. Contingent rentals are recognized as received. Further information on the accounting for the aforementioned direct financing lease can be found in Note 15 to the consolidated financial statements for the year ended December 31, 2007. 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 AEI’s allowance for doubtful accounts totaled $46 million at December 31, 2007.

Regulatory Assets and Liabilities

Assets and liabilities that result from the regulator 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 there is a probable expectation that future revenue 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 expense. Regulatory liabilities are recorded for amounts expected to be passed to the customer as refunds or reductions on future billings. Regulatory assets totaled $40 million and regulatory liabilities totaled $364 million at December 31, 2007.

Share-Based Compensation

Share-based compensation cost is measured at the grant date based on the value of the award at that time and is recognized as expense over the vesting period. Determining the fair value of share-based awards at the grant date requires judgment, including estimation of the expected term of stock options, the expected volatility, yields, and interest rates. The fair value of each option award is estimated, based on several assumptions, on the date of grant using a Black-Scholes option valuation model. If actual results differ significantly from these estimates, share-based compensation expense and results of operations could be materially impacted. Stock based compensation expenses under the 2007 Equity Incentive Plan for restricted stock and stock options totaled $2 million in 2007. A one-year change in the expected term or a one percentage point change in the expected volatility, yield or interest rate assumptions would not change the amount of expense recognized by more than $1 million.

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.

On January 1, 2007, we adopted the provisions of the FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of SFAS No. 109, Accounting for Income Taxes, or FIN 48. Pursuant to FIN 48, 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 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.

AEI and certain 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. Tax reserves 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 plan actuary conducts an independent valuation of the fair value of pension plan assets.

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, 2007 funded status. A one percentage point reduction in the assumed discount rates would increase AEI’s benefit obligation for pensions and other postretirement benefits by approximately $61 million, and would reduce our net income by approximately $2 million. Based on the market value of plan assets at December 31, 2007, a one percentage point decrease in the expected rate of return on plan assets assumption would decrease AEI’s net income by approximately $2 million.

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. Further information related to contingencies can be found in Note 26 to the consolidated financial statements for the year ended December 31, 2007.

Accounting Changes

In February 2007, the FASB issued FASB Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, or SFAS No. 159, effective for fiscal years beginning after November 15, 2007. SFAS No. 159 includes an amendment of FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities. SFAS No. 159 permits entities to choose, at specified election dates, to measure eligible items at fair value and requires unrealized gains and losses on items for which the fair value option has been elected to be reported in earnings. We adopted SFAS No. 159 on January 1, 2008 and elected to not record any eligible items at fair value though earnings. Therefore, there was no impact on our consolidated financial statements from the adoption of SFAS No. 159.

Recent Accounting Policies Not Yet Adopted

In December 2007, the FASB issued FASB Statement No. 141 (Revised 2007), Business Combinations, or SFAS No. 141(R), effective 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. SFAS No. 141(R) 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, SFAS No. 141(R) determines what information must be disclosed to enable users of the financial statements to evaluate the nature and financial effects of the business combination. We will adopt SFAS No. 141(R) upon its effective date in 2009 as appropriate for any future business combinations.

In September 2006, the FASB issued FASB Statement No. 157, Fair Value Measurements, or SFAS No. 157. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Certain requirements of SFAS No. 157 are effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of SFAS No. 157 has been deferred for one year by the FASB. We adopted the sections of SFAS No. 157 which are effective for fiscal years beginning after November 15, 2007 and there was no impact on our consolidated financial statements. We adopted the remaining requirements of

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SFAS No. 157 on January 1, 2009 and are currently evaluating the effect to our consolidated financial statements of prospectively applying the provisions of SFAS No. 157 to those assets and liabilities.

In December 2007, the FASB issued FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, or SFAS No. 160. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We adopted SFAS No. 160 on January 1, 2009 and will incorporate the additional disclosures in financial statements for fiscal year end 2009.

Although past transactions would have been accounted for differently under SFAS No. 160 and SFAS No. 141R, application of these statements in 2009 will not affect historical amounts.

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”), which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). SFAS No. 161 requires enhanced disclosures about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. It is effective for financial statements issued for fiscal years beginning after November 15, 2008, and early adoption is encouraged. The Company will incorporate the additional disclosures in financial statements for fiscal year 2009.

A. Operating results

As discussed in “Item 4. Information on the Company — A. History and Development of the Company,” AEI was formed by a series of transactions that began with the contribution of Elektra shares to AEI in March 2006. Subsequently, in 2006, PEI and an interest in Promigas was acquired. In addition, in 2007, we completed a series of acquisitions and divestitures, discussed elsewhere in this registration statement.

Due to the sequence of our 2006 acquisitions, the duration of time between these transactions, and the relative significance of the operations of Elektra and PEI compared to AEI, both Elektra and PEI are considered predecessors for purposes of the consolidated financial statements.

As a result of these activities and circumstances, our historical consolidated financial statements are not directly comparable because:


	•	the 2005 results include primarily only the results of our predecessor Elektra;

	•	there are two predecessor entities overlapping a year-end period in 2006;

	•	the timing of AEI’s step acquisitions of PEI resulted in AEI accounting for PEI on an equity basis from May 25, 2006 to September 6, 2006 and on a consolidated basis thereafter; and

	•	we completed additional acquisitions throughout 2007 and 2008.

We have included in this registration statement a discussion comparing AEI’s 2007 and 2006 audited results, as well as a discussion comparing nine months ended September 30, 2008 and 2007 unaudited results. For the reasons discussed above, prior period comparisons are not included. The AEI results for the year ended December 31, 2006 reflect PEI on an equity basis for the period of May 25, 2006 to September 6, 2006 and on a consolidated basis thereafter. The AEI results for the year ended December 31, 2007 reflect PEI on a consolidated basis for the entire year.

Management reviews the results of operations using a variety of measurements including an analysis of the statement of operations, and more specifically, revenues, cost 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

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		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 cost 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. These contracts contemplate a future decrease from $27.33/kWh per month in 2008, declining annually through 2011 to $20.81/kWh per month, then declining to $12.63/kWh per month in 2012 through the end of the contract, in the case of JPPC; $0.0316/kWh to $0.0005/kWh starting July 1, 2010 in the case of Trakya; and from $16.69/kWh per month to $4.55/kWh per month starting January 15, 2011 in the case of San Felipe.

	•	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. For GTB, the tariff is determined in accordance with its gas transportation agreement, which includes an annual tariff increase of 0.5% and negotiations regarding an extension to this agreement, as well as a permanent GSA, are currently on hold. See “Item 4. Information on the Company — B. Business Overview — Power Generation — Cuiabá — EPE — Empresa Produtora de Energia Ltda. (EPE) — Concession and Contractual Agreements,” “Item 4. Information on the Company — B. Business Overview — Natural Gas Transportation and Services — Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS) — Concession and Contractual Agreements” and “Item 5. Operating Financial Review and Prospects — Recent Developments — Cuiabá Integrated Project.”

	•	Natural Gas Distribution revenues are primarily generated from service 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. There are no upcoming tariff reviews expected for this segment in 2008.

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

Cost of sales

Power Distribution cost of sales relates 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 cost of sales directly impact Power Distribution revenues. The Power Generation segment cost of sales consists primarily of purchases of natural gas and other fuels for generation. Natural Gas Distribution and Retail Fuel cost of sales represents the cost of wholesale purchasing of the natural gas and other fuels that are resold to the final customers. Generally, cost of sales are not recorded in the Natural Gas Transportation and Services businesses, except in TBS, which purchases natural gas in Bolivia for resale to EPE.

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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.

AEI Results of Operations

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


	For the Nine	For the Nine
	Months Ended	Months Ended	For the Year Ended	For the Year Ended
	September 30, 2008	September 30, 2007	December 31, 2007	December 31, 2006

Power Distribution
Chilquinta	Equity Method⁽⁷⁾	—	Equity Method	—
Delsur	Consolidated	Consolidated⁽⁸⁾	Consolidated	—
EDEN	Consolidated	Consolidated⁽⁸⁾	Consolidated	—
Elektra	Consolidated	Consolidated	Consolidated	Consolidated
Elektro	Consolidated	Consolidated	Consolidated	Consolidated⁽¹⁾
Luz del Sur	Equity Method⁽⁷⁾	—	Equity Method	—
Power Generation
BLM⁽²⁾	—	—	—	Consolidated⁽¹⁾
Corinto	Consolidated⁽³⁾	Consolidated⁽³⁾	Consolidated⁽³⁾	Equity Method
Cuiabá — EPE	Consolidated	Consolidated	Consolidated	Consolidated⁽¹⁾
DCL	Consolidated⁽⁷⁾	—	—	—
ENS	Consolidated	Consolidated	Consolidated	Consolidated⁽¹⁾
Fenix	Consolidated⁽⁷⁾	—	—	—
Jaguar	Consolidated⁽⁷⁾	—	—	—
JPPC	Consolidated⁽⁷⁾	—	Consolidated	—
Luoyang	Consolidated⁽⁷⁾	—	—	—
PQP	Consolidated	Consolidated	Consolidated	Consolidated⁽¹⁾
San Felipe	Consolidated	Consolidated	Consolidated	Consolidated⁽¹⁾
Subic	Equity Method	Equity Method	Equity Method	Equity Method
Tipitapa	Consolidated⁽⁷⁾	—	—	—
Trakya	Consolidated	Consolidated	Consolidated	Consolidated⁽¹⁾
Natural Gas Transportation and Services
Accroven	Equity Method	Equity Method	Equity Method	Equity Method
Centragas	Equity Method	Equity Method	Equity Method	Equity Method⁽⁴⁾
Cuiabá — GOB/GOM/TBS.	Consolidated	Consolidated⁽¹⁾	Consolidated	Consolidated⁽¹⁾
GBS⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
GTB	Cost Method⁽⁶⁾	Equity Method	Equity Method	Equity Method
Promigas	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
PSI⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
TBG	Cost Method	Cost Method	Cost Method	Cost Method
Transmetano⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
Transoccidente⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
Transoriente⁽⁵⁾	Equity Method	Equity Method	Equity Method	Equity Method⁽⁴⁾
Transredes	Cost Method⁽⁶⁾	Equity Method	Equity Method	Equity Method

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	For the Nine	For the Nine
	Months Ended	Months Ended	For the Year Ended	For the Year Ended
	September 30, 2008	September 30, 2007	December 31, 2007	December 31, 2006

Natural Gas Distribution
BMG	Consolidated⁽⁷⁾	—	Cost Method	—
Cálidda	Consolidated	Consolidated⁽⁸⁾	Consolidated	—
Gases de Occidente⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
Gases del Caribe⁽⁵⁾	Equity Method	Equity Method	Equity Method	Equity Method⁽⁴⁾
Surtigas⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
Tongda	Consolidated⁽⁷⁾	Consolidated⁽⁸⁾	Consolidated	—
Retail Fuel
Gazel⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾
SIE⁽⁵⁾	Consolidated	Equity Method	Equity Method	Equity Method⁽⁴⁾
Other
Promitel⁽⁵⁾	Consolidated	Consolidated	Consolidated	Equity Method⁽⁴⁾


(1)		Acquired in 2006 as part of the step acquisition of PEI.

(2)		AEI divested its interests in BLM on March 14, 2007.

(3)		In August and September 2007, through a series of transactions, AEI acquired an additional net 15% interest in Corinto and began consolidating Corinto’s results as of September 2007.

(4)		Acquired as part of the 2006 step acquisition of PEI. Promigas is reflected in AEI’s results under the equity method during 2006. A controlling interest in Promigas was purchased on December 27, 2006 and as a result, only its balance sheet is consolidated with AEI at December 31, 2006. These entities were accounted for under the equity method for the year ended December 31, 2006.

(5)		AEI ownership interest is held through its ownership in Promigas.

(6)		The Company’s ownership in Transredes, and therefore GTB, changed during June 2008 as explained further in Note 21 to the unaudited condensed consolidated financial statements as of and for the nine months ended September 30, 2008.

(7)		The Company’s initial interest was purchased during the fourth quarter of 2007 or during 2008.

(8)		The Company’s initial interest was purchased during the second quarter or third quarter of 2007.

These historical consolidated financial statements are not directly comparable due to the timing of the acquisition of PEI in 2006. The AEI results for the year ended December 31, 2006 reflect PEI on an equity basis for the period of May 25, 2006 to September 6, 2006 and on a consolidated basis thereafter. The AEI results for the year ended December 31, 2007 reflect PEI on a consolidated basis for the entire year. The AEI results for the three and nine months ended September 30, 2008 reflect SIE on a consolidated basis. 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 US GAAP. This is intended to provide information on the performance of the underlying business, regardless of when it was acquired by AEI and whether the business is accounted for using the equity method or is consolidated.

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

The following discussion compares AEI’s results of continuing operations for the three months ended September 30, 2008 to the three months ended September 30, 2007.

104

Revenues

The table below presents revenues of our consolidated subsidiaries by significant geographical location for the three months ended September 30, 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.


	For the
	Three Months
	Ended
	September 30,
	2008		2007
	Millions of dollars (U.S.)

Colombia	$	1,525	$	125
Brazil		452		341
Panama		142		94
Turkey		123		85
Guatemala		63		46
Dominican Republic		48		51
Argentina		31		24
China		23		2
Other		141		62

Total	$	2,548	$	830

The following table reflects revenues by segment:


	For the
	Three Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	644		$	480
Power Generation		343			206
Natural Gas Transportation and Services		51			52
Natural Gas Distribution		150			82
Retail Fuel		1,386			32
Headquarters/Other/Eliminations		(26	)		(22	)

Total revenues	$	2,548		$	830

Revenues increased by $1,718 million to $2,548 million for the three months ended September 30, 2008 compared to $830 million for the three months ended September 30, 2007. The increase was primarily due to the consolidation of SIE ($1,337 million) during 2008, the acquisitions made during or after the third quarter of 2007 ($76 million), and the increase in revenues at Elektro ($105 million), Elektra ($48 million), Trakya ($38 million) and Promigas’ subsidiaries ($68 million) as described below, partially offset by the decrease in revenues at TBS ($7 million) as described below.

Power Distribution

Revenues from the Power Distribution segment increased by $164 million to $644 million for the three months ended September 30, 2008 compared to $480 million for the three months ended September 30, 2007. The increase was primarily due to the increased revenues at Elektro ($105 million) and Elektra ($48 million). For the three month comparison period, the increase in revenues at Elektro was primarily due to the appreciation of the Brazilian real relative to the U.S. dollar ($49 million), higher sales volumes ($4 million), and additional revenue recognition ($60 million) as a result of recent regulatory determinations made by ANEEL, partially offset by lower prices ($7 million) as a result of a tariff reduction that occurred in August

105

2007. The increase in revenue due to regulatory rulings related to a tariff adjustment ($13 million) as a result of the 2007 tariff review performed by ANEEL in August 2008, the modification of a regulation for low income customers, by ANEEL in July 2008, reversing the accrual previously realized in 2007 ($28 million), and 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. The increased revenues at Elektra were primarily due to higher pricing ($45 million) as a result of the bi-annual tariff adjustment driven by higher fuel cost, and increased usage ($3 million) resulting from an expanding customer base. EDEN received a tariff increase effective August 25, 2008, resulting in $5 million of increased revenues.

Power Generation

Revenues from the Power Generation segment increased by $137 million to $343 million for the three months ended September 30, 2008 compared to $206 million for the three months ended September 30, 2007. The increase was primarily due to additional revenues from the acquisition of interests in JPPC ($21 million), Luoyang ($7 million), Corinto ($16 million) and Tipitapa ($16 million), and increased revenues at PQP ($17 million), Trakya ($38 million) and ENS ($7 million). For the three month comparison period, the increased revenues at PQP were primarily due to higher fuel costs which were passed on to its customers and higher usage of the plant’s capacity; increased revenues at Trakya were primarily due to higher fuel costs which were passed on to its customers; increased revenues at ENS were primarily due to accrued revenue from gas-related compensation from the Polish government and the sale of cogeneration certificates.

Natural Gas Transportation and Services

Revenues from the Natural Gas Transportation and Services segment decreased by $1 million to $51 million for the three months ended September 30, 2008 compared to $52 million for the three months ended September 30, 2007. The decrease was primarily due to decreased revenues at TBS as a result of gas curtailments occurring during the last quarter of 2007 that continued through the third quarter of 2008, partially offset by higher revenues generated at Promigas and its subsidiaries as a result of new contracts obtained in 2008 and the appreciation of the Colombian peso relative to the U.S. dollar for the three months ended September 30, 2008 compared to the same period of 2007.

Natural Gas Distribution

Revenues from the Natural Gas Distribution segment increased by $68 million to $150 million for the three months ended September 30, 2008 compared to $82 million for the three months ended September 30, 2007. The increase was primarily due to the acquisitions of Tongda in August 2007 and BMG in January 2008 ($16 million), the increased revenues at Cálidda ($5 million) primarily due to higher distribution volumes as a result of higher customer demand, and increased revenues at Promigas’ subsidiaries ($47 million) as a result of higher distribution volumes due to higher customer demand and higher wellhead prices which were passed on to customers.

Retail Fuel

Revenues from the Retail Fuel segment increased by $1,354 million to $1,386 million for the three months ended September 30, 2008 compared to $32 million for the three months ended September 30, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($1,337 million).

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Cost of Sales

The following table reflects cost of sales by segment:


	For the
	Three Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	406		$	272
Power Generation		287			163
Natural Gas Transportation and Services		3			14
Natural Gas Distribution		101			50
Retail Fuel		1,268			12
Headquarters/Other/Eliminations		(28	)		(39	)

Total cost of sales	$	2,037		$	472

Cost of sales increased by $1,565 million to $2,037 million for the three months ended September 30, 2008 compared to $472 million for the three months ended September 30, 2007. The increase was primarily due to the consolidation of SIE ($1,241 million) during 2008, the acquisitions ($69 million) made during or after the third quarter of 2007, and the increases in cost of sales at Elektro ($79 million), Elektra ($47 million), Trakya ($38 million) and Promigas subsidiaries ($50 million) as described below, partially offset by the decrease in cost of sales at EPE ($8 million) and TBS ($10 million) as described below.

Power Distribution

Cost of sales for the Power Distribution segment increased by $134 million to $406 million for the three months ended September 30, 2008 compared to $272 million for the three months ended September 30, 2007. The increase was primarily due to the increased cost of sales at Elektro ($79 million) and Elektra ($47 million). For the three month comparison period, the increased cost of sales at Elektro was primarily due to an increase in the average price of purchased electricity as a result of the appreciation of the Brazilian real ($23 million) and the overall increases in energy prices ($18 million), an increase in volumes purchased ($2 million), and additional recognition of cost of sales ($40 million) which were related to a tariff adjustment ($22 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 cost of sales at Elektra was a result of higher fuel costs ($44 million) and an increase in volumes purchased ($3 million).

Power Generation

Cost of sales for the Power Generation segment increased by $124 million to $287 million for the three months ended September 30, 2008 compared to $163 million for the three months ended September 30, 2007. Cost of sales for the Power Generation business primarily consists of fuel purchases and transmission charges. The increase was primarily due to the acquisition of interests in Corinto ($15 million), JPPC ($19 million), Luoyang ($8 million) and Tipitapa ($14 million), and the increased cost of sales at San Felipe ($11 million), Trakya ($38 million) and PQP ($19 million), partially offset by the decreased cost of sales at EPE ($8 million). For the three month comparison period, the increased cost of sales at San Felipe was primarily due to higher fuel prices, partially offset by lower generation volumes as a result of planned major plant maintenance during the third quarter of 2008; the increased cost of sales at Trakya was primarily due to higher fuel prices; the increased cost of sales at PQP was primarily due to higher fuel prices and higher usage of plant capacity; the decreased cost of sales at EPE was a result of gas curtailments that the plant experienced during the last quarter of 2007 that continued through the third quarter of 2008.

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Natural Gas Transportation and Services

Cost of sales for the Natural Gas Transportation and Services segment decreased by $11 million to $3 million for the three months ended September 30, 2008 compared to $14 million for the three months ended September 30, 2007. The decrease was primarily due to a decrease of $10 million in cost of sales at TBS as a result of gas supply curtailments that occurred during the last quarter of 2007 and continued through the third quarter of 2008.

Natural Gas Distribution

Cost of sales for the Natural Gas Distribution segment increased by $51 million to $101 million for the three months ended September 30, 2008 compared to $50 million for the three months ended September 30, 2007. The increase was primarily due to the acquisitions of Tongda in August 2007 and BMG in January 2008 ($11 million) and the increased cost of sales at Promigas’ subsidiaries ($36 million) as a result of higher customer demand, market growth, and higher natural gas wellhead prices with the appreciation of the Colombia Peso relative to the U.S. dollar for the three months ended September 30, 2008 compared to the same period of 2007.

Retail Fuel

Cost of sales for the Retail Fuel segment increased by $1,256 million to $1,268 million for the three months ended September 30, 2008 compared to $12 million for the three months ended September 30, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($1,241 million).

Operating Expenses

Operations, Maintenance and General and Administrative Expenses

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


	For the
	Three Months
	Ended
	September 30,
	2008		2007
	Millions of dollars (U.S.)

Power Distribution	$	87	$	72
Power Generation		35		22
Natural Gas Transportation and Services		17		11
Natural Gas Distribution		20		22
Retail Fuel		52		10
Headquarters/Other/Eliminations		21		27

Total operations, maintenance and general and administrative expenses	$	232	$	164

Operations, maintenance and general and administrative expenses increased by $68 million to $232 million for the three months ended September 30, 2008 compared to $164 million for the three months ended September 30, 2007. The increase was primarily due to the consolidation of SIE during 2008 ($41 million), the acquisitions made during or after the third quarter of 2007 ($15 million), and the increased operations, maintenance and general and administrative expenses at Elektro ($12 million) and San Felipe ($7 million), partially offset by the decreased operations, maintenance and general and administrative expenses at headquarters ($6 million) as a result of decreased professional services fees and decreased stock compensation expense due to the 2004 stock incentive and long term incentive grant plans that fully vested in 2007.

Power Distribution

Operations, maintenance and general and administrative expenses for the Power Distribution segment increased by $15 million to $87 million for the three months ended September 30, 2008 compared to

108

$72 million for the three months ended September 30, 2007. The increase was primarily due to the increased operations, maintenance and general and administrative expenses at Elektro ($12 million). For the three month comparison period, these expenses at Elektro increased by $12 million due primarily to the appreciation of the Brazilian real relative to the U.S. dollar ($8 million) and increased payroll expenses ($3 million) as a result of the recently finalized union agreement effective in June 2008.

Power Generation

Operations, maintenance and general and administrative expenses for the Power Generation segment increased by $13 million to $35 million for the three months ended September 30, 2008 compared to $22 million for the three months ended September 30, 2007. The increase was primarily due to the acquisitions of JPPC, Tipitapa, Fenix, Jaguar and DCL ($9 million total), and the increased operations, maintenance and general and administrative expenses at San Felipe ($7 million), partially offset by the decreased operations, maintenance and general and administrative expenses at EPE ($2 million). For the three month comparison period, these expenses at San Felipe increased by $7 million primarily due to a planned major plant maintenance during the third quarter of 2008; these expenses at EPE decreased by $2 million primarily due to gas curtailments that the plant experienced during the last quarter of 2007 that continued through the third quarter of 2008.

Natural Gas Transportation and Services

Operations, maintenance and general and administrative expenses for the Natural Gas Transportation and Services segment increased by $6 million to $17 million for the three months ended September 30, 2008 compared to $11 million for the three months ended September 30, 2007. The increase was primarily due to the increased operations, maintenance and general and administrative expenses at Promigas ($5 million) as a result of higher pipeline maintenance costs and the expenses associated with new services provided to customers commencing in July 2007.

Natural Gas Distribution

Operations, maintenance and general and administrative expenses for the Natural Gas Distribution segment decreased by $2 million to $20 million for the three months ended September 30, 2008 compared to $22 million for the three months ended September 30, 2007. The decrease was primarily due to the decreased operations, maintenance and general and administrative expenses at one of Promigas’ subsidiaries ($7 million) partially offset by the acquisitions of Tongda in August 2007 and BMG in January 2008 ($6 million).

Retail Fuel

Operations, maintenance and general and administrative expenses for the Retail Fuel segment increased by $42 million to $52 million for the three months ended September 30, 2008 compared to $10 million for the three months ended September 30, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($41 million).

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Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the
	Three Months
	Ended
	September 30,
	2008		2007
	Millions of dollars (U.S.)

Power Distribution	$	37	$	35
Power Generation		8		10
Natural Gas Transportation and Services		6		4
Natural Gas Distribution		5		2
Retail Fuel		15		1
Headquarters/Other/Eliminations		—		1

Total depreciation and amortization expenses	$	71	$	53

Total depreciation and amortization expense increased by $18 million to $71 million for the three months ended September 30, 2008 compared to $53 million for the three months ended September 30, 2007. The increase was primarily due to the acquisitions made during or after the third quarter of 2007 ($5 million), the consolidation of SIE in 2008 ($9 million), and the increased depreciation and amortization expense at Promigas’ subsidiary Gazel ($4 million) as a result of an increased number of retail fuel service stations, partially offset by an increase in amortization to income at San Felipe due to the unfavorable power purchase agreement which is amortized based on the generated volumes produced by the plant ($5 million).

(Gain) Loss on Disposition of Assets

During the three months ended September 30, 2008, AEI recorded net losses on disposition of assets totaling $13 million compared to net losses of $2 million for the three months ended September 30, 2007. In the third quarter of 2008, AEI revised the SIE purchase price allocation and related valuations and recorded adjustments for the foreign exchange impact based on current information resulting in a $6 million reduction in the gain on this transaction (see Note 3).

Equity Income from Unconsolidated Affiliates

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


	For the
	Three Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	17		$	—
Power Generation		3			3
Natural Gas Transportation and Services		10			13
Natural Gas Distribution		2			5
Retail Fuel		3			1
Headquarters/Other/Eliminations		(1	)		(1	)

Total equity income from unconsolidated affiliates	$	34		$	21

Equity income from unconsolidated affiliates increased by $13 million to $34 million for the three months ended September 30, 2008 compared to $21 million for the three months ended September 30, 2007. The increase was primarily due to $17 million of equity income from the investments in Chilquinta and Luz del Sur acquired in the fourth quarter of 2007.

110

Operating Income

As a result of the factors discussed above, AEI’s operating income for the three months ended September 30, 2008 increased by $27 million to $177 million compared to $150 million for the three months ended September 30, 2007. The following table reflects the contribution of each segment to operating income in both periods:


	For the
	Three Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	126		$	98
Power Generation		(25	)		10
Natural Gas Transportation and Services		32			32
Natural Gas Distribution		24			14
Retail Fuel		45			8
Headquarters/Other/Eliminations		(25	)		(12	)

Total operating income	$	177		$	150

Interest Income

Interest income increased by $3 million to $27 million for the three months ended September 30, 2008 compared to $24 million for the three months ended September 30, 2007. Of the interest income earned during 2008 and 2007, 59% and 63%, 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.

Interest Expense

Interest expense increased by $18 million to $99 million for the three months ended September 30, 2008 compared to $81 million for the three months ended September 30, 2007. The increase was primarily due to the additional interest expense at the operating companies as a result of acquisitions made during or after the third quarter of 2007 ($9 million) and the consolidation of SIE ($12 million).

Foreign Currency Transaction Gain (Loss), Net

Total foreign currency transaction losses were $47 million for the three months ended September 30, 2008 compared to $4 million of foreign currency gains for the three months ended September 30, 2007. Of this amount, $32 million of foreign currency transaction losses was primarily associated with the effects of the devaluation of the Colombian peso relative to the U.S. dollar in the third quarter of 2008 on a U.S. dollar denominated debt instrument held by one of Promigas’ subsidiaries; $15 million of foreign currency losses at EPE were due primarily 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.

Provision for 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. The provision for income taxes for the three months ended September 30, 2008 and 2007 was $50 million and $49 million, respectively. The estimated effective income tax rate for the three months ended September 30, 2008 and 2007 was 77% and 49%, respectively, which was higher than the statutory rate primarily due to losses generated by the Company in its Cayman Island and other holding companies jurisdictions for which no tax benefit has been provided. For the three month period ended September 30, 2008, the write-down related to EPE which could not be benefited for tax purposes and other miscellaneous discrete items.

111

Minority Interests

Minority interest expense decreased by $17 million to $4 million of income for the three months ended September 30, 2008 compared to $13 million of expense for the three months ended September 30, 2007. The decrease was primarily due to lower income before taxes and the impact of gas curtailments at the EPE plant during the last quarter of 2007 that continued through the third quarter of 2008.

Net Income

As a result of the factors discussed above, net income for the three months ended September 30, 2008 was $19 million compared to net income of $38 million for the three months ended September 30, 2007.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

The following discussion compares AEI’s results of continuing operations for the nine months ended September 30, 2008 to the nine months ended September 30, 2007.

Revenues

The table below presents revenues of our consolidated subsidiaries by significant geographical location for the nine months ended September 30, 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.


	For the
	Nine Months
	Ended
	September 30,
	2008		2007
	Millions of dollars (U.S.)

Colombia	$	4,443	$	392
Brazil		1,184		1,057
Panama		377		298
Turkey		284		248
Guatemala		173		122
Dominican Republic		170		89
Argentina		87		24
China		69		2
Other		365		55

Total	$	7,152	$	2,287

The following table reflects revenues by segment:


	For the
	Nine Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	1,699		$	1,258
Power Generation		900			630
Natural Gas Transportation and Services		153			147
Natural Gas Distribution		421			247
Retail Fuel		4,049			100
Headquarters/Other/Eliminations		(70	)		(95	)

Total revenues	$	7,152		$	2,287

112

Revenues increased by $4,865 million to $7,152 million for the nine months ended September 30, 2008 compared to $2,287 million for the nine months ended September 30, 2007. The increase was primarily due to the consolidation of SIE ($3,918 million) during 2008, the acquisitions made during 2007 and 2008 ($367 million), and the increase in revenues at Elektro ($196 million), Elektra ($110 million), San Felipe ($81 million), and Promigas’ subsidiaries ($136 million) as described below, partially offset by the decrease in revenues at EPE ($50 million) and TBS ($21 million), and the sale of BLM ($31 million) as described below.

Power Distribution

Revenues from the Power Distribution segment increased by $441 million to $1,699 million for the nine months ended September 30, 2008 compared to $1,258 million for the nine months ended September 30, 2007. The increase was primarily due to the increased revenues at Elektro ($196 million) and Elektra ($110 million) and the acquisitions of Delsur ($68 million) and EDEN ($56 million) during the second quarter of 2007. The increased revenues at Elektro were primarily due to the appreciation of the Brazilian real relative to the U.S. dollar ($170 million), higher sales volumes ($32 million) as a result of an increased customer base, and additional revenue recognition ($48 million) as a result of recent regulatory determinations made by ANEEL, partially offset by lower prices ($51 million) as a result of a tariff reduction that occurred in August 2007 and lower additional charges related to excess demand of energy by industrial customers. The increase in revenue due to regulatory rulings related to a tariff adjustment ($13 million) as a result of the 2007 tariff review performed by ANEEL in August 2008, the modification of a regulation for low income customers, by ANEEL in July 2008, reversing the accrual previously fully realized in 2007 ($16 million), and 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. The increased revenues at Elektra were primarily due to higher pricing ($100 million) as a result of the bi-annual tariff adjustment driven by higher fuel cost and increased usage ($10 million) resulting from an expanding customer base.

Power Generation

Revenues from the Power Generation segment increased by $270 million to $900 million for the nine months ended September 30, 2008 compared to $630 million for the nine months ended September 30, 2007. The increase was primarily due to additional revenues from the acquisition of interests in JPPC ($60 million), Luoyang ($21 million), Corinto ($53 million) and Tipitapa ($20 million), and the increased revenues at San Felipe ($81 million), Trakya ($36 million), PQP ($51 million) and ENS ($24 million), partially offset by a decrease of $31 million as a result of the sale of BLM in March 2007 and decreased revenues at EPE ($50 million). 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 plants’ capacity. Increased revenues at Trakya were primarily due to higher fuel costs which were passed on to its customers and a reduction of the revenues being deferred due to the recalculation of the Cost Increase Protocol provision, 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 accrued revenue from gas-related compensation from the Polish government and the sale of cogeneration certificates, and the appreciation of the Polish Zloty relative to the U.S. dollar. Revenues at EPE decreased by $50 million as a result of gas curtailments that the plant experienced during the last quarter of 2007 that continued through the third quarter of 2008.

Natural Gas Transportation and Services

Revenues from the Natural Gas Transportation and Services segment increased by $6 million to $153 million for the nine months ended September 30, 2008 compared to $147 million for the nine months ended September 30, 2007. The increase was primarily due to higher revenues generated at Promigas and its subsidiaries as a result of new contracts obtained in 2008 and the appreciation of the Colombian peso relative to the U.S. dollar for the nine months ended September 30, 2008 compared to the same period of 2007, partially offset by the decreased revenues at TBS as a result of gas curtailments that occurred during the last quarter of 2007 and continued through the third quarter of 2008.

113

Natural Gas Distribution

Revenues from the Natural Gas Distribution segment increased by $174 million to $421 million for the nine months ended September 30, 2008 compared to $247 million for the nine months ended September 30, 2007. The increase was due to the acquisitions of Cálidda in June 2007 ($41 million), the acquisitions of Tongda in August 2007 and BMG in January 2008 ($48 million), and the increased revenues ($80 million) at Promigas’ subsidiaries as a result of higher distribution volumes due to higher customer demand and higher wellhead prices which were passed on to customers.

Retail Fuel

Revenues from the Retail Fuel segment increased by $3,949 million to $4,049 million for the nine months ended September 30, 2008 compared to $100 million for the nine months ended September 30, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($3,918 million). The remaining increase of $31 million was due to the increased revenues at Promigas’ subsidiary Gazel as a result of the increased cost of gas passed on to its customers and the appreciation of the Colombian peso relative to the U.S. dollar for the nine months ended September 30, 2008 compared to the same period of 2007.

Cost of Sales

The following table reflects cost of sales by segment:


	For the
	Nine Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	1,054		$	682
Power Generation		725			430
Natural Gas Transportation and Services		10			28
Natural Gas Distribution		274			140
Retail Fuel		3,696			50
Headquarters/Other/Eliminations		(80	)		(103	)

Total cost of sales	$	5,679		$	1,227

Cost of sales increased by $4,452 million to $5,679 million for the nine months ended September 30, 2008 compared to $1,227 million for the nine months ended September 30, 2007. The increase was primarily due to the consolidation of SIE ($3,630 million) during 2008, the acquisitions ($270 million) made during 2007 and 2008, and the increase in cost of sales at Elektro ($180 million), Elektra ($104 million), PQP ($54 million), Trakya ($50 million), San Felipe ($94 million) and Promigas subsidiaries ($89 million) as described below, partially offset by the decrease in cost of sales at EPE ($24 million) and TBS ($19 million) and the sale of BLM ($26 million) as described below.

Power Distribution

Cost of sales for the Power Distribution segment increased by $372 million to $1,054 million for the nine months ended September 30, 2008 compared to $682 million for the nine months ended September 30, 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 cost of sales at Elektro ($180 million) and Elektra ($104 million). The increased cost of sales at Elektro was primarily due to an increase in the average price of purchased electricity as a result of the appreciation of the Brazilian real ($77 million) and the overall increase in energy prices ($65 million), an increase in volumes purchased ($7 million) as a result of higher sales volumes, and retroactive adjustments of cost of sales ($36 million), which were related to a tariff adjustment ($18 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

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the determination made by ANEEL. The increased cost of sales at Elektra was a result of higher fuel costs ($98 million) and an increase in volumes purchased ($6 million).

Power Generation

Cost of sales for the Power Generation segment increased by $295 million to $725 million for the nine months ended September 30, 2008 compared to $430 million for the nine months ended September 30, 2007. The increase was primarily due to the acquisition of interests in Corinto ($46 million), JPPC ($43 million), Luoyang ($24 million) and Tipitapa ($17 million), and the increased cost of sales at San Felipe ($94 million), Trakya ($50 million) and PQP ($54 million), partially offset by the decreased cost of sales at EPE ($24 million) and the sale of BLM ($26 million) in March 2007. The increased cost of sales at San Felipe and PQP was primarily due to higher fuel prices and higher usage of plant capacity; the increased cost of sales at Trakya was primarily due to higher 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 cost of sales at EPE was a result of gas curtailments that the plant experienced during the last quarter of 2007 that continued through the third quarter of 2008.

Natural Gas Transportation and Services

Cost of sales for the Natural Gas Transportation and Services segment decreased by $18 million to $10 million for the nine months ended September 30, 2008 compared to $28 million for the nine months ended September 30, 2007. The decrease was primarily due to a decrease of $19 million in cost of sales at TBS as a result of gas supply curtailments that occurred during the last quarter of 2007 and continued through the third quarter of 2008.

Natural Gas Distribution

Cost of sales for the Natural Gas Distribution segment increased by $134 million to $274 million for the nine months ended September 30, 2008 compared to $140 million for the nine months ended September 30, 2007. The increase was due to the acquisition of Cálidda in June 2007 ($26 million), the acquisitions of Tongda in August 2007 and BMG in January 2008 ($32 million), and the increased cost of sales ($72 million) at Promigas’ subsidiaries as a result of higher customer demand, market growth, and higher natural gas wellhead prices with the appreciation of the Colombian peso relative to the U.S. dollar for the nine months ended September 30, 2008 compared to the same period of 2007.

Retail Fuel

Cost of sales for the Retail Fuel segment increased by $3,646 million to $3,696 million for the nine months ended September 30, 2008 compared to $50 million for the nine months ended September 30, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($3,630 million). The remaining increase of $16 million was due to the increased cost of sales at Promigas’ subsidiary Gazel as a result of the increased cost of gas and the appreciation of the Colombian peso relative to the U.S. dollar for the nine months ended September 30, 2008 compared to the same period of 2007.

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Operating Expenses

Operations, Maintenance and General and Administrative Expenses

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


	For the
	Nine Months
	Ended
	September 30,
	2008		2007
	Millions of dollars (U.S.)

Power Distribution	$	247	$	180
Power Generation		102		77
Natural Gas Transportation and Services		49		38
Natural Gas Distribution		55		35
Retail Fuel		161		23
Headquarters/Other/Eliminations		67		92

Total operations, maintenance and general and administrative expenses	$	681	$	445

Operations, maintenance and general and administrative expenses increased by $236 million to $681 million for the nine months ended September 30, 2008 compared to $445 million for the nine months ended September 30, 2007. The increase was primarily due to the consolidation of SIE during 2008 ($130 million), the acquisitions made during 2007 and 2008 ($64 million), and the increased operations, maintenance and general and administrative expenses at Elektro ($35 million) and Trakya ($24 million) as described below, partially offset by the decreased operations, maintenance and general and administrative expenses at EPE ($13 million) due to reduced generation activity as a result of curtailment of gas supply and headquarters ($25 million) as a result of decreased professional services fees and decreased stock compensation expenses related to the 2004 stock incentive and long term incentive grant plans that fully vested in 2007.

Power Distribution

Operations, maintenance and general and administrative expenses for the Power Distribution segment increased by $67 million to $247 million for the nine months ended September 30, 2008 compared to $180 million for the nine months ended September 30, 2007. The increase was primarily due to the acquisitions of Delsur ($9 million) and EDEN ($17 million) and the increased operations, maintenance and general and administrative expenses at Elektro ($35 million). These expenses at Elektro increased by $35 million due primarily to the appreciation of the Brazilian real relative to the U.S. dollar ($26 million), increased professional services ($4 million), and increased payroll expenses ($2 million) as a result of the recently finalized union agreement effective in June 2008.

Power Generation

Operations, maintenance and general and administrative expenses for the Power Generation segment increased by $25 million to $102 million for the nine months ended September 30, 2008 compared to $77 million for the nine months ended September 30, 2007. The increase was primarily due to the acquisitions of JPPC, Luoyang, Corinto, Tipitapa, Fenix, Jaguar and DCL ($19 million total), and the increased operations, maintenance and general and administrative expenses at Trakya ($24 million), partially offset by the sale of BLM ($2 million) in March 2007 and the decreased operations, maintenance and general and administrative expenses at EPE ($13 million). These expenses at Trakya increased by $24 million due primarily to planned major plant maintenance during the second quarter of 2008; these expenses at EPE decreased by $13 million primarily due to gas curtailments that the plant experienced during the last quarter of 2007 that continued through the third quarter of 2008.

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Natural Gas Transportation and Services

Operations, maintenance and general and administrative expenses for the Natural Gas Transportation and Services segment increased by $11 million to $49 million for the nine months ended September 30, 2008 compared to $38 million for the nine months ended September 30, 2007. The increase was primarily due to the increased operations, maintenance and general and administrative expenses at Promigas ($8 million) as a result of higher pipeline maintenance cost and the expenses associated with new services provided to customers commencing in July 2007.

Natural Gas Distribution

Operations, maintenance and general and administrative expenses for the Natural Gas Distribution segment increased by $20 million to $55 million for the nine months ended September 30, 2008 compared to $35 million for the nine months ended September 30, 2007. The increase was primarily due to the acquisition of Cálidda ($6 million) in June 2007 and the acquisitions of Tongda in August 2007 and BMG in January 2008 ($13 million).

Retail Fuel

Operations, maintenance and general and administrative expenses for the Retail Fuel segment increased by $138 million to $161 million for the nine months ended September 30, 2008 compared to $23 million for the nine months ended September 30, 2007. The increase was primarily due to the consolidation of SIE in 2008 ($130 million) and the increased operations, maintenance and general and administrative expenses at Promigas’ subsidiary Gazel ($8 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
	Nine Months
	Ended
	September 30,
	2008		2007
	Millions of dollars (U.S.)

Power Distribution	$	109	$	98
Power Generation		19		28
Natural Gas Transportation and Services		17		15
Natural Gas Distribution		14		5
Retail Fuel		41		4
Headquarters/Other/Eliminations		3		3

Total depreciation and amortization expenses	$	203	$	153

Total depreciation and amortization expenses increased by $50 million to $203 million for the nine months ended September 30, 2008 compared to $153 million for the nine months ended September 30, 2007. The increase was primarily due to the acquisitions made during 2007 and 2008 ($21 million), the consolidation of SIE ($28 million), and the increased depreciation and amortization expense at Promigas’ subsidiary Gazel ($8 million) as a result of an increased number of retail fuel service stations, partially offset by the sale of BLM in March 2007 ($1 million) and an increase in amortization to income at San Felipe due to the unfavorable power purchase agreement which is amortized based on the generated volumes produced by the plant ($12 million).

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(Gain) Loss on Disposition of Assets

During the nine months ended September 30, 2008 and 2007, AEI recorded net gains on disposition of assets totaling $40 million and $13 million, respectively. In the first nine months of 2008, AEI recognized a gain of $68 million on the sale of 46% of Gazel to minority shareholders of SIE when exchanged for additional interest in SIE which was partially offset by a loss of $14 million on the sale of debt securities of Gas Argentina S.A. See Notes 3 and 12 to the unaudited condensed consolidated financial statements for the nine months ended September 30, 2008. In the first nine months of 2007, AEI recognized a gain of $21 million on the sale of the 51% interest in BLM in March 2007.

Equity Income from Unconsolidated Affiliates

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


	For the
	Nine Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	55		$	—
Power Generation		8			8
Natural Gas Transportation and Services		27			33
Natural Gas Distribution		10			10
Retail Fuel		3			4
Headquarters/Other/Eliminations		(1	)		—

Total equity income from unconsolidated affiliates	$	102		$	55

Equity income from unconsolidated affiliates increased by $47 million to $102 million for the nine months ended September 30, 2008 compared to $55 million for the nine months ended September 30, 2007. The increase was primarily due to $55 million of equity income from the investments in Chilquinta and Luz del Sur acquired in the fourth quarter of 2007.

Operating Income

As a result of the factors discussed above, AEI’s operating income for the nine months ended September 30, 2008 increased by $147 million to $653 million compared to $506 million for the nine months ended September 30, 2007. The following table reflects the contribution of each segment to operating income in both periods:


	For the
	Nine Months
	Ended
	September 30,
	2008			2007
	Millions of dollars (U.S.)

Power Distribution	$	326		$	281
Power Generation		15			117
Natural Gas Transportation and Services		99			95
Natural Gas Distribution		85			76
Retail Fuel		211			25
Headquarters/Other/Eliminations		(83	)		(88	)

Total operating income	$	653		$	506

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Interest Income

Interest income decreased by $16 million to $68 million for the nine months ended September 30, 2008 compared to $84 million for the nine months ended September 30, 2007. Of the interest income earned during 2008 and 2007, 54% and 55%, 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 $64 million to $292 million for the nine months ended September 30, 2008 compared to $228 million for the nine months ended September 30, 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 ($27 million), the consolidation of SIE ($34 million), and the increased interest expense at Elektro, partially offset by the decreased interest expense at the parent level. For the nine months comparison period, interest expense at Elektro increased by $8 million to $60 million due primarily to the appreciation of the Brazilian real relative to the U.S. dollar. Interest expense at the parent level decreased by $12 million to $100 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 $24 million for the nine months ended September 30, 2008 compared to foreign currency transaction gains of $12 million for the nine months ended September 30, 2007. Of this amount, $19 million in foreign currency transaction losses was primarily associated with the effects of the devaluation of the Colombian peso relative to the U.S. dollar for the nine months ended September 30, 2008 on a U.S. dollar denominated debt instrument held by one of Promigas’ subsidiaries; $6 million of foreign currency transaction losses 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.

Loss on Early Retirement of Debt

Loss on early retirement of debt was $33 million for the nine months ended September 30, 2007 as a result of the refinancing of the senior credit facility, including additional revolving credit facilities, and the redemption of payment in kind, or PIK Notes, at the parent level.

Provision for 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. The provision for income taxes for the nine months ended September 30, 2008 and 2007 was $169 million and $164 million, respectively. The estimated effective income tax rate for the nine months ended September 30, 2008 and 2007 was 41% and 49%, respectively, which was higher than the statutory rate primarily due to losses generated by the Company in its Cayman Island and other holding companies jurisdictions for which no tax benefit has been provided. For the nine month period ended September 30, 2008, the write-down related to EPE which could not be benefited for tax purposes and other miscellaneous discrete items.

Minority Interests

Minority interest expense increased by $41 million to $120 million for the nine months ended September 30, 2008 compared to $79 million for the nine months ended September 30, 2007. The increase was primarily due to higher income before taxes and the impact of the minority interest share ($55 million) of the Promigas gain on its sale of 46% of Gazel to minority shareholders of SIE.

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Net Income

As a result of the factors discussed above, net income for the nine months ended September 30, 2008 was $125 million compared to net income of $93 million for the nine months ended September 30, 2007.

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006

The following discussion compares AEI’s results of continuing operations for the year ended December 31, 2007 to the year ended December 31, 2006.

Revenues

The table below presents revenues of our consolidated subsidiaries by significant geographical location for the years ended December 31, 2007 and 2006. 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.


	For the Year Ended December 31,
	2007		2006
	Millions of dollars (U.S.)

Brazil	$	1,406	$	390
Colombia		563		—
Guatemala		168		48
Panama		389		371
Turkey		337		116
Other		353		21

Total	$	3,216	$	946

The following table reflects revenues by segment:


	For the Year Ended December 31,
	2007			2006
	Millions of dollars (U.S.)

Power Distribution	$	1,746		$	685
Power Generation		874			278
Natural Gas Transportation and Services		199			24
Natural Gas Distribution		352			—
Retail Fuel		160			—
Headquarters/Other/Eliminations		(115	)		(41	)

Total revenues	$	3,216		$	946

Revenues for the year ended December 31, 2007 increased $2,270 million to $3,216 million in 2007 from $946 million in 2006, primarily as a result of the consolidation of PEI for the full year during 2007.

Power Distribution

Revenues from the Power Distribution segment increased $1,061 million to $1,746 million for the year ended December 31, 2007 from $685 million in the prior year. Of the increase, $735 million is due to the fact that Elektro, our largest power distribution business, was consolidated for the entirety of 2007, versus only four months in 2006. On a stand-alone basis, revenues at Elektro increased by $159 million in 2007 of which

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$128 million was due to the appreciation of the Brazilian real relative to the U.S. dollar. The remaining increase was the result of higher tariffs during the first eight months of 2007 as compared to the first eight months of 2006 as well as higher sales volumes at Elektro, partially offset by the impact of a 17.2% tariff reduction that occurred in August 2007. The tariff reduction caused an estimated decline of approximately $52 million in revenues over the remainder of the year, as compared to estimated revenues assuming a constant tariff rate throughout 2007. AEI’s consolidated Power Distribution revenues were further increased by $97 million and $52 million as a result of the inclusion of the results of Delsur and EDEN, respectively, which acquisitions were completed during May and June 2007.

Power Generation

Revenues from the Power Generation segment increased $596 million to $874 million for the year ended December 31, 2007 from $278 million for the 2006 period. Power Generation revenues increased by $640 million as a result of the full year consolidation of PEI in 2007, which was offset by a decline of $77 million caused by the sale of BLM in March 2007. Our Power Generation subsidiaries with the largest stand-alone changes in revenue were PQP and EPE. In 2007, stand-alone revenues at PQP increased by $23 million as compared to 2006. This increase was primarily the result of a 14% volume increase in merchant sales ($8 million) and a 12% increase in PQP’s average merchant price ($8 million). Revenues at EPE, on a stand-alone basis, declined by $19 million in 2007. The decrease was a result of gas curtailments that the plant experienced during the second half of 2007. Our availability within the segment was comparable in 2007 and 2006.

Natural Gas Transportation and Services

Revenues from the Natural Gas Transportation and Services segment increased $175 million to $199 million for the year ended December 31, 2007 from $24 million in the prior year. In 2007, the results of Promigas and certain of its subsidiaries were consolidated, which resulted in an increase of $124 million in revenues in comparison to 2006. Promigas’ revenues on a stand-alone basis in this segment increased $14 million during 2007 compared to 2006. In addition to the impact of the consolidation of Promigas, 2007 revenues increased by $53 million in comparison to 2006 as a result of the full-year consolidation of PEI.

Natural Gas Distribution

The businesses in the Natural Gas Distribution segment were not consolidated during 2006. The $352 million in revenues in this segment during the year ended December 31, 2007 correspond primarily to subsidiaries of Promigas, including Gases de Occidente and Surtigas. On a stand-alone basis, revenues from Gases de Occidente increased $45 million in 2007 compared to 2006. This increase was due to the pass-through of a 10% increase in both natural gas prices and volumes purchased, as well as an increase in tariffs charged to non-regulated customers of 11% and on tariffs for natural gas for vehicles of 28%. Stand-alone revenues from Surtigas increased $36 million in 2007 compared to 2006. The increase resulted from a 20% volume increase in gas marketed to LDC’s. Additional Natural Gas Distribution revenues of $37 million and $8 million were generated by Cálidda and Tongda, which were acquired during June and August 2007, respectively.

Retail Fuel

The businesses in the Retail Fuel segment were not consolidated during 2006. The Retail Fuel segment revenues for the year ended December 31, 2007, amounting to $160 million, include revenue generated by Promigas’ subsidiary Gazel. Gazel’s revenues on a stand-alone basis increased in 2007, primarily due to a 16% increase in average sales prices, as well as sales volume growth of 10% from new service stations and an appreciation of the Colombian peso relative to the U.S. dollar of 12% during 2007.

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Cost of Sales

The following table reflects cost of sales by segment:


	For the Year Ended December 31,
	2007			2006
	Millions of dollars (U.S.)

Power Distribution	$	963		$	410
Power Generation		610			193
Natural Gas Transportation and Services		36			4
Natural Gas Distribution		224			—
Retail Fuel		90			—
Headquarters/Other/Eliminations		(127	)		(41	)

Total cost of sales	$	1,796		$	566

Cost of sales increased $1,230 million in year ended December 31, 2007 to $1,796 million from $566 million in the prior year.

Power Distribution

Cost of sales for the Power Distribution segment increased $553 million to $963 million for the year ended December 31, 2007 from $410 million for the year ended December 31, 2006. During the 2007 period, our cost of sales, which primarily represents Elektro’s purchases of energy and capacity from generation companies, increased by $358 million as a result of the impact of full-year consolidation in 2007. Elektro’s stand-alone cost of sales increased $86 million, primarily due to a 20.8% increase in the average price of purchased electricity as a result of the appreciation of the Brazilian real, as well as overall increases in energy prices. Power Distribution cost of sales also increased in 2007 by $63 million and $27 million as a result of the acquisitions of Delsur and EDEN, respectively.

Power Generation

For the year ended December 31, 2007, cost of sales for the Power Generation segment increased $417 million to $610 million from $193 million in the prior year. Cost of sales for the Power Generation businesses primarily consists of fuel purchases and transmission charges. Power Generation cost of sales increased by $432 million related to the full-year consolidation of PEI during 2007, which was partially offset by a decline of $61 million resulting from the sale of BLM in March 2007. Our Power Generation subsidiaries with the largest stand-alone changes in cost of sales were PQP and San Felipe. Stand-alone cost of sales at PQP increased $15 million in 2007. This increase was primarily a result of a 42% increase in fuel volumes used to service the plant’s increased generation ($16 million), as well as a 12% increase in average fuel prices ($6 million). Cost of sales at San Felipe decreased by $13 million in 2007 as compared to 2006 on a stand-alone basis. This was due to decreased fuel consumption during 2007 due to outages associated with non-routine repairs experienced during the year, partially offset by higher average cost of fuel.

Natural Gas Transportation and Services

For the year ended December 31, 2007, the Natural Gas Transportation and Services segment incurred cost of sales of $36 million, as compared to $4 million in the 2006 period. In 2006, cost of sales was attributable entirely to TBS. The $36 million in 2007 cost of sales for the Natural Gas Transportation and Services segment is primarily related to TBS, whose contribution to consolidated cost of sales increased by $12 million as a result of the full-year consolidation in 2007 and whose stand-alone cost of sales increased by a further $11 million in 2007 as compared to 2006. The Promigas pipeline, whose results were recorded as equity income in 2006, contributed $9 million to cost of sales in 2007.

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Natural Gas Distribution

The businesses in the Natural Gas Distribution segment were not consolidated during 2006. The $224 million in cost of sales for this segment during the year ended December 31, 2007 correspond primarily to subsidiaries of Promigas, including Surtigas and Gases de Occidente. On a stand-alone basis, cost of sales at Surtigas increased $10 million in 2007 as compared to 2006. This was due to a 20% volume increase in gas marketed to LDC’s. Additional expenses of $23 million and $7 million were contributed by Cálidda and Tongda, respectively, which were acquired during 2007.

Retail Fuel

The businesses in the Retail Fuel segment were not consolidated during 2006. The Retail Fuel segment cost of sales for the year ended December 31, 2007 represent natural gas purchases made by the Promigas subsidiary Gazel, which increased by $20 million on a stand-alone basis as a result of increased gas purchases to meet higher sales volumes, as well as a 10% increase in average gas prices.

Operating Expenses

Operations, Maintenance and General and Administrative Expenses

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


	For the Year Ended
	December 31,
	2007		2006
	Millions of dollars
	(U.S.)

Power Distribution	$	241	$	91
Power Generation		118		37
Natural Gas Transportation and Services		57		6
Natural Gas Distribution		49		—
Retail Fuel		33		—
Headquarters/Other/Eliminations		132		59

Total operations, maintenance and general and administrative expenses	$	630	$	193

Operations, maintenance and general and administrative expenses increased $437 million to $630 million from $193 million in 2006. The increase is primarily the result of the consolidation of PEI for the full year in 2007 and the consolidation of Promigas in 2007.

For 2007, operations, maintenance and general and administrative expenses in the Power Distribution segment increased $150 million to $241 million from $91 million in 2006. Of this increase $109 million was due to Elektro’s results being consolidated for the entirety of 2007. Elektro’s operations, maintenance and general and administrative expenses include principally repair and maintenance, labor, administrative and other expenses and provisions for doubtful accounts and were comparable from 2007 to 2006. Additional operations, maintenance and general and administrative expenses totaling $16 million and $15 million were contributed in 2007 by Delsur and EDEN, respectively, which were acquired during 2007 and therefore were not included in the results reported for 2006.

For the year ended December 31, 2007, total operations, maintenance and general and administrative expenses of the Power Generation segment increased $81 million to $118 million from $37 million in the prior year. Of this increase, $51 million was related to the full-year consolidation of PEI during 2007. Our Power Generation subsidiaries with the largest stand-alone total operations, maintenance and general administrative expenses were Trakya and EPE. On a stand-alone basis, operations, maintenance and general and administrative expenses increased $17 million at Trakya due to certain year-end purchases of replacement equipment and parts made in 2007 in preparation for a major maintenance cycle scheduled for 2008, while they increased $14 million at EPE due to maintenance performed during the first quarter of 2007.

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During 2007, the Natural Gas Transportation and Services segment recorded $57 million in operations, maintenance and general and administrative expenses, as compared to $6 million in 2006. Of the $51 million increase, $44 million is related to the consolidation of Promigas and certain of its subsidiaries, which were recorded as equity-method investments during 2006. On a stand-alone basis, operations, maintenance and general and administrative expenses at Promigas were comparable in 2007 and 2006.

We did not consolidate any of the businesses in the Natural Gas Distribution segment during 2006. The $49 million in operations, maintenance and general and administrative expenses incurred in this segment during 2007 correspond primarily to subsidiaries of Promigas, including Gases de Occidente and Surtigas. On a stand-alone basis, operations, maintenance and general and administrative expenses at Gases de Occidente increased $16 million in 2007 as compared to 2006. This increase was due to increased collection commissions associated with changes in its sale policies, as well as increased marketing costs. Stand-alone operations, maintenance and general and administrative expenses at Surtigas increased $10 million due to the addition of a non-banking finance business and related personnel, as well as increased marketing expenses. Additional expenses were contributed by Cálidda and Tongda, which were acquired during 2007.

We did not consolidate any of the businesses in the Retail Fuel segment during 2006. The Retail Fuel segment operations, maintenance and general and administrative expenses for the year ended December 31, 2007, amounting to $33 million, include expenses incurred by the Promigas subsidiary Gazel.

Headquarters’ operations, maintenance and general and administrative expenses, which totaled $132 million in 2007, increased by $73 million during the year from $59 million in 2006. The full-year consolidation of PEI during 2007 contributed $42 million to the increase. In addition, in 2007 we recognized approximately $12 million in previously-capitalized development costs related to the cancelled acquisition of Shell’s interest in certain joint venture businesses in Bolivia, along with approximately $13 million in costs associated with a proposed securities offering that did not occur during the year.

Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the Year Ended December 31,
	2007		2006
	Millions of dollars
	(U.S.)

Power Distribution	$	139	$	47
Power Generation		42		9
Natural Gas Transportation and Services		20		2
Natural Gas Distribution		8		—
Retail Fuel		3		1
Headquarters/Other/Eliminations		5		—

Total depreciation and amortization expenses	$	217	$	59

Total depreciation and amortization expenses increased $158 million for the year ended December 31, 2007 as compared to the 2006 period. This increase is primarily related to the full-year consolidation of PEI ($77 million) and Promigas ($26 million) results during 2007, as well as new acquisitions completed during the year.

Taxes other than Income

Total taxes other than income amounted to $43 million for 2007, compared to $7 million in taxes other than income for 2006. Of the increase, $20 million is primarily due to the fact that PEI was consolidated for all of 2007, compared to only four months in 2006. Of the amount recognized in 2007, the largest component is from Elektro, primarily related to taxes charged by the Brazilian government on, among other things, cash

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outlays. On a stand-alone basis, Elektro’s taxes other than income increased $7 million in 2007 as compared to 2006.

Other Charges

During 2007, AEI recorded an allowance charge of $50 million against its lease investment receivable balance associated with the EPE power purchase agreement. On October 1, 2007, we received a notice from EPE’s sole customer, Furnas, purporting to terminate its agreement with EPE as a result of the current lack of gas supply from Bolivia. EPE contested Furnas’ position and is vigorously opposing Furnas’ efforts to terminate the agreement. The discussions are currently in arbitration. EPE determined that it is probable that it will be unable to collect all minimum lease payment amounts due according to the contractual terms of the lease. Accordingly, the allowance was recorded against the total minimum lease receivable.

(Gain) Loss on Disposition of Assets

During the year ended December 31, 2007, AEI recorded net gains on disposition of assets totaling $21 million. Of this amount, $21 million is attributable to the sale of our 51.00% interest in BLM to Suez Energy Luxembourg in March 2007, and $10 million is associated with the sale of a 0.75% interest in Promigas in December 2007. These gains were partially offset by $10 million of losses recognized by Elektro during 2007, which were recorded in connection with the repair or disposal of damaged equipment as required by the regulator. On a stand-alone basis, the Elektro losses in 2007 are comparable to those incurred in 2006.

Equity Income from Unconsolidated Affiliates

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


	For the Year Ended December 31,
	2007		2006
	Millions of dollars (U.S.)

Power Distribution	$	2	$	26
Power Generation		11		21
Natural Gas Transportation and Services		39		10
Natural Gas Distribution		13		1
Retail Fuel		11		3
Headquarters/Other/Eliminations		—		(24	)

Total equity income from unconsolidated affiliates	$	76	$	37

Equity income from unconsolidated affiliates increased $39 million during the year ended December 31, 2007 to $76 million from $37 million in the prior year. Equity income from unconsolidated affiliates in 2006 included the results of PEI from May 25 to September 6, 2006. Subsequent to that date, the results of PEI were consolidated. During 2007, equity income reported for the Power Distribution and Power Generation segments declined by $24 million and $10 million, respectively. The decline was due to the consolidation of most of the PEI businesses for all of 2007 (as compared to four months in 2006), therefore not contributing to equity income in 2007. In Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel, equity income increased due to the timing and percentage ownership of Promigas in 2007 as compared to 2006.

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Operating Income

As a result of the factors discussed above, AEI’s operating income for the year ended December 31, 2007 increased by $426 million to $577 million, from $151 million in the 2006 period. The following table reflects the contribution of each segment to operating income in both periods:


	For the Year Ended December 31,
	2007			2006
	Millions of dollars (U.S.)

Power Distribution	$	373		$	151
Power Generation		76			60
Natural Gas Transportation and Services		128			21
Natural Gas Distribution		85			1
Retail Fuel		49			2
Headquarters/Other/Eliminations		(134	)		(84	)

Total operating income	$	577		$	151

Interest Income

Interest income for the year ended December 31, 2007 increased by $39 million, to $110 million from $71 million in 2006. Of the interest income earned during 2007, 53% 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 increase is primarily due to the fact that Elektro was consolidated for all of 2007 compared to only four months in 2006. On a stand-alone basis, Elektro’s interest income decreased in 2007 due to lower monetary indexation income, which is a form of interest earned on its net balance of regulatory assets and liabilities, which amortize over time. Interest income earned by the Headquarters/Other segment decreased $26 million during 2007 as 2006 includes $26 million of interest income earned by AEIL on a loan to PEI, which was recorded during the period for which PEI was treated as an equity method investment.

Interest Expense

Interest expense increased by $168 million in 2007 to $306 million from $138 million in 2006. Most of the increase is due to the full-year consolidation of PEI in 2007 versus four months in 2006. In addition, interest expense at the parent level increased from $86 million in 2006 to $107 million in 2007. The 2006 expenses were primarily incurred by AEIL as part of the PEI acquisition financing, whereas the 2007 expenses were primarily associated with servicing the $1 billion senior credit facility and $300 million 10% Subordinated PIK Notes due May 25, 2018.

Foreign Currency Transaction Gain (Loss), Net

Total foreign currency transaction gains amounted to $19 million for the year ended December 31, 2007. Of this amount, $21 million is related to foreign currency transaction gains relating to EPE, primarily associated with a lease investment receivable balance and customer receivable balances that were denominated in Brazilian reais. These gains were partially offset by foreign currency transaction losses with respect to other companies, primarily Trakya and TBG. Total foreign currency transaction losses in 2006 amounted to $5 million.

Other Income (Expense), Net

The $22 million other expense recognized in 2007 includes a loss of $14 million associated with hedging of reais for Elektro’s dividends recorded at the Headquarters/Other/Eliminations level. Other income was $7 million in 2006 and included gains from various insurance settlements, partially offset by a litigation reserve at San Felipe.

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Provision for Income Taxes

AEI is a Cayman Islands company, and there is no corporate income tax in the Cayman Islands. Provisions for taxes have been made based on the tax laws and rates of the countries in which operations are conducted and income is earned. The 2007 effective tax rate on continuing operations was 56.0% in comparison to 97.6% in 2006. The 2006 effective tax rate takes into account losses of $88 million which do not generate a tax benefit by virtue of the 0% statutory tax rate in the Cayman Islands, and an increase in valuation allowances of $29 million which resulted for the most part from changes in tax laws.

Minority Interests

The 2007 minority interest expense of $65 million increased $45 million as compared to $20 million in minority interest recognized in the prior year primarily due to the full-year consolidation of PEI and Promigas during 2007, each of which contain certain subsidiary businesses with minority shareholders for whom minority interest is now recorded in the AEI consolidated financial statements.

Discontinued Operations

On November 15, 2007, the interest in Vengas was divested, and as such, AEI reported the operating results of Vengas as discontinued operations for 2006 and 2007. See “— Recent Developments — Disposals” for more information on the sale of Vengas.

Net Income

As a result of the factors discussed above, we recorded a net income of $131 million in 2007, compared to a net loss of $11 million in 2006.

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 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 our electricity, fuels 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 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 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. We have also raised local currency denominated debt, to match the cash flow of each business.

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.

At September 30, 2008, we had $1,785 million of recourse debt and $2,196 million of non-recourse debt outstanding. For more information on our long-term debt, see Note 14 to the unaudited condensed consolidated financial statements for the nine months ended September 30, 2008 and Note 13 to the consolidated financial statements for the year ended December 31, 2007 included elsewhere in this registration statement.

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

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on market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms. 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.

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 September 30, 2008, AEI and certain of its subsidiaries had entered into letters of credit, bank guarantees and performance bonds that had outstanding balances of $27 million and $175 million in unused letter of credit availability, of which $67 million of the total facility balances were fully cash collateralized. Additionally, as of September 30, 2008, lines of credit of $1,629 million were outstanding, with an additional $187 million available. We are current on all debt payments at all of our controlled operating companies.

As of September 30, 2008, we had approximately $588 million of total cash and cash equivalents on a consolidated basis, of which $201 million was at the parent company level, $333 million was at our consolidated operating businesses, and the remaining $54 million was at consolidated holding and service companies. See Note 6 to the unaudited condensed consolidated financial statements for the nine months ended September 30, 2008 included elsewhere in this registration statement for further information.

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, $495 million of which was drawn as of September 30, 2008;

	•	future debt and subordinated debt offerings;

	•	issuance of additional equity; and

	•	fees from management contracts.

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 projects; and

	•	parent company overhead and development costs.

The amount of cash generated by our businesses may be affected by, among other things, changes in tariff rates. The tariffs of our regulated businesses, particularly those in the Power Distribution 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. 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 electricity or natural gas consumption. As a result, the tariff reviews may result in tariff reductions to reset the business’ returns back

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to the regulated return levels. Following its tariff reset in August 2003, Elektro had increased margins primarily due to faster growth in electricity consumption in its concession area in the years following that review. During its August 2007 review, Elektro’s average tariff across all customer segments was reduced by 17.2%. This reduction reflects the high returns that Elektro had been able to achieve during the last four years since the 2003 tariff review. A decrease is also expected in Elektro’s results in the future, as well as in the dividends to be paid to AEI related to those years, as a result of the tariff review.

Further, the amount of cash generated by our businesses may be affected by changes in working capital availability. For example, due to force majeure events, the primary fuel supply to Trakya may be impeded or curtailed. Trakya’s ability to operate using alternate fuel (gasoil) may be limited by its current inventory of gasoil and/or by working capital constraints. The market price of gasoil is currently significantly above the price of gas under Trakya’s gas supply agreement, and sourcing the alternate fuel could create liquidity concerns if Trakya were to experience delays in reimbursement of the higher fuel costs from its customer.

Capital Expenditures

Capital expenditures were $249 million and $76 million in 2007 and 2006, respectively, of which $137 million and $52 million, in 2007 and 2006, respectively, correspond to capital expenditures at Elektro. Capital expenditures for 2007 also include $50 million associated with Promigas and its consolidated subsidiaries. For 2008, capital expenditure spending is expected to total $378 million, of which $136 million and $125 million correspond to capital expenditures at Promigas (including its consolidated subsidiaries) and Elektro, respectively. Capital expenditures were $240 million and $155 million for the nine months ended September 30, 2008 and 2007, respectively. Planned capital expenditures for 2008 also include expansions in the asset base and new project construction costs in the Power Distribution, Natural Gas Distribution, Natural Gas Transportation and Services and Retail Fuel segments and expenditures related to existing assets to increase their useful lives. These capital expenditures are expected to be financed using cash provided by the businesses’ operations and business level financing.

Our Cash Flows for the Nine Months ended September 30, 2008 and September 30, 2007

Cash Flows from Operating Activities

Cash provided by operating activities decreased by $328 million to $182 million in the nine months ended September 30, 2008 from $510 million for the same period in 2007. The decrease in cash flows from operating activities is the combined result of an increased cash outflow of $384 million in operating assets and liabilities and an increase of $56 million in net income after removing non-cash items, including equity income from unconsolidated affiliates that was not distributed and the gain on the SIE transaction. See Note 3 to the unaudited condensed consolidated financial statements for the nine months ended September 30, 2008. The increased cash outflow of $384 million in operating assets and liabilities was primarily due to the acquisition of SIE and the related increases in accounts receivable and inventory, partially offset by increases in accounts payable. Additionally, Elektro’s increased payments of accrued income taxes due to timing and its increase in its regulatory asset balance resulted in increased cash outflows during 2008.

Cash Flows from Investing Activities

Cash used in investing activities decreased by $172 million to $289 million in the nine month period ended September 30, 2008 from $461 million for the same period in 2007. Capital expenditures increased by $85 million in the nine month period ended September 30, 2008 due to expansion in the asset base and new project construction during the first nine months of 2008. Cash paid for acquisitions was $228 million in the first nine months of 2008 for the interests in BMG, Luoyang, Fenix, Tipitapa, DCL and Promigas’ additional interests in certain subsidiaries. This is compared to $400 million in the same period of 2007 for the acquisitions of Cálidda, EDEN, Delsur, Tongda, Corinto and the additional interests in San Felipe and PQP. Additionally, in the first nine months of 2008, cash and cash equivalents of $77 million were acquired compared to $22 million in the same period of 2007. Restricted cash decreased by $57 million for the nine months ended September 30, 2008 compared to a $22 million decrease for the same period of 2007 due

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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 interests in debt securities of Gas Argentino S.A. and proceeds of $48 million from the sale of BLM, respectively.

Cash Flows from Financing Activities

Cash provided by financing activities in the nine months ended September 30, 2008 was $182 million compared to $281 million of cash used in financing activities in the nine months ended September 30, 2007. In May 2008, the Company sold 12.5 million of its ordinary shares to GIC and received $200 million in proceeds. Additionally, Elektro had decreased scheduled repayments of its long term debt, Delsur increased borrowings and Promigas refinanced various credit facilities for the financing of capital expenditures, while the Company used a portion of the stock issuance proceeds previously mentioned to repay a portion of its revolving credit facility and to make dividend payments to minority interest holders, and Trakya paid off all of its long term debt. See Note 14 to the unaudited condensed consolidated financial statements as of and for the nine months ended September 30, 2008.

Our Cash Flows for the Years ended December 31, 2006 and December 31, 2007

Cash Flows from Operating Activities

Cash provided by operating activities increased by $531 million to $686 million in 2007 from $155 million in 2006. The increase in cash flow from operations is primarily due to cash flow from operations of consolidated subsidiaries acquired in 2006 and 2007. Of the $531 million increase, $428 million was related to increased net income after adding back non-cash items including the $50 million charge for the lease receivable balance associated with the EPE power purchase agreement and increased depreciation and amortization as described above. In addition, there was $92 million increase in deferred revenue resulting from billing to customers in advance of recognition of revenue associated primarily with Trakya and Gases de Occidente.

Cash Flows from Investing Activities

Cash used in investing activities declined from $1,729 million in 2006 to $1,151 million in 2007. Activity in 2006 was primarily related to the acquisitions of PEI and Promigas, net of cash acquired. The 2007 activity was primarily related to the acquisitions of new businesses and of interests in existing businesses, as discussed elsewhere in this registration statement. In addition, 2007 cash used in investing activities included $249 million of capital expenditures, which increased from $76 million in 2006 primarily due to the full-year consolidation of PEI during 2007. Activity in 2007 also includes proceeds of $162 million from sales of investments, including the sale of our interests in Vengas and BLM and a portion of our interests in Promigas, which increased from $24 million in 2006.

Cash Flows from Financing Activities

Cash provided by financing activities was $88 million in 2007, as compared to $2,395 million in 2006. During 2006, we entered into a $1 billion senior credit facility and received $527 million from the issuance of PIK notes. These proceeds, along with $920 million proceeds from the issuance of common shares as part of the initial capitalization of the company, were used for the acquisition of PEI. In 2007, the senior credit facility and PIK notes were refinanced. In addition, we borrowed $100 million to fund a portion of the acquisition of an 86.4% interest in Delsur. Also during 2007, PQP refinanced its debt and Elektro repaid $170 million of debentures.

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 $1 billion term loan facility that matures on March 30, 2014 and a $395 million revolving

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credit facility and a $105 million synthetic revolving credit facility that both mature on March 30, 2012. 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 1.5%. 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% per annum. The funding of the term loan and access to the revolving credit facility and the synthetic revolving credit facility took place on March 31, 2007, with an amendment for implementation of Letter of Credit sub-facilities entered into on June 6, 2008. 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 that will provide us with additional liquidity. As of September 30, 2008, $390 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 notes under a note purchase agreement dated May 24, 2007, which were listed on the Luxembourg Stock Exchange on May 19, 2008. The proceeds 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 September 30, 2008, the aggregate principal and interest amount of the notes was $343 million. The notes mature on May 25, 2018.

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 note purchase agreement, the occurrence of any one of which entitles any note holder to declare its note immediately due and payable, include: (a) a failure to timely repay note principal, interest, and any applicable redemption premium, (b) a failure to perform any other obligation under the note purchase agreement and related documents if not cured within 10 business days, (c) 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 (d) certain bankruptcy events.

The PIK Notes are expressly subordinated to our senior loans and up to $500 million of additional senior loans. The note holders 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 loan facilities.

We may, upon notice to the note holders, 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 price is: (a) year 1: 100%, (b) year 2: 102%, (c) year 3: 104%, (d) year 4: 106% and (e) year 5 and thereafter: 108%.

We recently obtained the consent of the note holders to make certain amendments to the note purchase agreement which would enable us to issue to note holders an option to exchange their notes for ordinary shares for up to one year, beginning March 2009, and as a result of which we can now purchase PIK Notes in the open market, subject to certain conditions. The initial exchange rate for the option to exchange notes for our ordinary shares is 63 ordinary shares per $1,000 of each principal amount of notes exchanged and adjusts downward on a daily basis through the end of the option period. On March 13, 2009, Ashmore Funds converted approximately $104 million principal amount of PIK Notes to equity in exchange for 7,412,142 ordinary shares.

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Subsidiaries’ Financing Activities

Elektra revolving credit facility — In the third quarter of 2008, Elektra obtained a $82 million revolving line of credit to finance working capital and energy purchases from suppliers. The line of credit is unsecured and has a variable interest rate of 1 to 3 month LIBOR plus 1.2% to 1.5%, which is payable monthly. The facility matures 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 to EBITDA ratios and interest coverage ratios.

Delsur refinancing — 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 difference between the original bridge loan and the senior secured term loan was primarily repaid with cash received from capital contributions made by the Company. The loan bears interest at 3 month 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 leverage ratios, debt service coverage ratios and interest service coverage ratios.

Luoyang — Luoyang obtained a 751 million Renminbi ($110 million) long-term bank loan in 2004 to finance construction and equipment costs of a power generation facility. The loan bears interest at the 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 September 30, 2008 is 658 million Renminbi ($96 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. As of September 30, 2008, $2 million in interest on the loan was past due. According to the loan agreement, the lender has the right to accelerate the loan repayment if Luoyang defaults on either interest or principal payments. The lender has not notified Luoyang of any intent to accelerate. However, the Company has reclassified the $96 million debt to current. In addition, a principal payment is due in November 2008. Luoyang is in negotiations with the China Development Bank to restructure the loan and has requested the local government to assist in the negotiation process.

Luoyang also has short-term bank loans of 213 million Renminbi ($31 million) for general working capital purposes. The loans bear interest at 1.1 to 1.3 times the PBOC rate. Interest is payable monthly and principal payments are due at maturities ranging from 2008 to 2009. The loans are secured by fixed assets and the land use rights of Luoyang.

Trakya — In March 2008, Trakya entered into an agreement with Bayerische Landesbank, or BLB, for a counter-guarantee to enable a new letter of guarantee for $54 million related to Trakya’s supply of gas. This new letter of guarantee is valid until March 6, 2009 and replaces Trakya’s previous letter of guarantee that expired earlier in 2008. The BLB counter-guarantee has been restructured and is now only partially cash collateralized. Accordingly, $27 million of Trakya’s cash balances have been reserved in a restricted account with BLB. If, however, certain material adverse conditions relating to Trakya’s Implementation Contract and its Energy Sales Agreement are triggered, there is an obligation for Trakya to fully cash collateralize the counter-guarantee.

Additionally, in September 2008, Trakya made the final payment on all long term debt. In conclusion with the final repayment, all restricted cash and pledges of assets as collateral related to the long term debt have been released.

ENS — In April 2008, ENS amended and converted its $77 million U.S. dollar denominated loan into an equivalent Polish zloty, or PLN, loan concurrent with the change from its U.S. dollar-linked 20-year power purchase agreement 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. The long-term stability of the new arrangement has allowed ENS to amend its existing credit facility to extend the tenor, reduce the interest rate and change the currency, and to establish a new 40 million Polish zloty ($17 million), three-year

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revolving working capital facility. 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.

Subsidiaries’ Long-Term Debt Schedule

The following table summarizes our consolidated subsidiaries’ credit facilities as of September 30, 2008:


		Balance as of
	Currency of	September 30,	Maturity
Business	Borrowing	2008	Profile	Collateral	Summary of Distribution Restrictions
		Millions of
		dollars (U.S.)

BMG	Chinese Renminbi	$13	2010-2014	Guarantees from group companies and minority shareholder	None
Cálidda	U.S.$	86	2015	Security includes the gas distribution concession, income trust and SBLC of US$47 million	No restrictions, but must meet leverage and debt service coverage ratios, among others.
Corinto	U.S.$	18	2010	Security includes mortgage on assets, DSRA	No default
Cuiabá — EPE⁽¹⁾	U.S.$	43	2015-2016	Shareholder loan with Shell (no security)	N/A
Cuiabá — GOB⁽¹⁾	U.S.$	31	2015-2016	Shareholder loan with Shell (no security)	N/A
Cuiabá — GOM⁽¹⁾	U.S.$	23	2015-2016	Shareholder loan with Shell (no security)	N/A
DCL	Pakistani rupees	81	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.$	75	2015	Security includes subsidiary guarantees and pledges of shares	No default/must meet distribution ratios/local laws
EDEN⁽²⁾	U.S.$	39	2013	Unsecured	No default/limited to % of excess cash
Elektra	U.S.$	128	2009-2021	Unsecured	None
Elektro	R$	423	2009-2020	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 e Social, or BNDES
					— Dividends/Shareholder Interest less than 110% of the Net Profit
ENS	U.S.$	73	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

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		Balance as of
	Currency of	September 30,	Maturity
Business	Borrowing	2008	Profile	Collateral	Summary of Distribution Restrictions
		Millions of
		dollars (U.S.)

JPPC	U.S.$	20	2011	Security includes mortgage on assets	No default/must meet distribution ratios/local laws
Luoyang.	Chinese Renminbi	127	2016	Security includes assignment of rights to collection of revenues	None
PQP	U.S.$	82	2015	Security includes mortgage on assets, assignment of contracts, pledge of shares etc.	No default/must meet distribution ratios/local laws
Promigas⁽³⁾	Colombian pesos	629	2008-2014	Unsecured	None
Promigas⁽⁴⁾	U.S.$	295	2007-2012	Security includes Gazel, Lutexsa, Chile	— Dividends Depending on the leverage ratio <=2.5 X 50% of the Net Income <2.5 X 100% of the Net Income
Tongda	Chinese Renminbi	10	2010	Guarantees from a company related to ex-shareholders	None
Trakya..	U.S.$	0	2008	Security includes mortgage on assets, assignment of contracts, pledge of shares etc.	No default/must meet distribution ratios/local laws
Total		$2,196


(1)		The Cuiabá entities have only shareholder loans. We recognize those loans with Shell as third party loans. We do not include in this table those shareholder loans with AEI or AEI subsidiaries. The Shell loans will be held by us upon the consummation of our acquisition of Shell’s interests in the Cuiabá entities.

(2)		EDEN is in non-payment default, however it remains current in all of its payment obligations under the credit agreement and, to date, has not been notified by the lenders of the acceleration of its obligations under the credit agreement. See Note 17 to the consolidated financial statements for the year ended December 31, 2007.

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

(4)		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 affected by and we expect our business to continue to be affected by the following key trends:

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. In recent years, emerging markets have generally experienced significant macroeconomic and fiscal improvements. We expect these macroeconomic improvements, which tend to be closely related to economic growth, to increase energy consumption by new industries and households as industrialization increases and standards of living improve.

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Foreign Currency Changes. The local currencies in many emerging markets in which we operate have depreciated 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. Between January 2, 2008 and September 30, 2008, the Brazilian real depreciated by 8.7% against the U.S. dollar, according to the European Central Bank. Future fluctuations in exchange rates relative to the U.S. dollar may have a material effect on our earnings and cash flows.

Energy Demand Growth in Our Markets. Increases in energy demand are a primary source of growth in our businesses. According to the U.S. Department of Energy’s International Energy Outlook 2008, published in June 2008, total energy demand in non OECD economies is expected to grow by 85% from 2005 through 2030 (3.4% average annual growth rate), or 187 quadrillion BTU. Power generation capacity in non OECD countries is expected to increase from 2,152 GW in 2010 to 2,611 GW in 2015, an average annual growth rate of 4.3%. The following table summarizes the electricity consumption growth rate in some of our principal markets:


	2005				2006				2007
			Electricity				Electricity				Electricity
			Consumption				Consumption				Consumption
	Real GDP		Growth		Real GDP		Growth		Real GDP		Growth
	Growth		Rate		Growth		Rate⁽¹⁾		Growth⁽²⁾		Rate

Brazil		2.9%		2.9%		3.7%		5.1%		5.4%		N/A
Colombia		4.7%		4.0%		6.8%		3.2%		7.0%		N/A
Turkey		7.4%		0.4%		6.1%		4.0%		5.0%		N/A
Argentina		9.2%		6.0%		8.5%		5.9%		8.7%		N/A
Bolivia		4.0%		6.8%		4.6%		3.6%		4.2%		N/A
Dominican Republic		9.3%		10.8%		10.7%		12.4%		8.5%		N/A
Guatemala		3.5%		2.2%		4.9%		13.5%		5.7%		N/A
Panama		6.9%		0.7%		8.1%		2.8%		11.2%		N/A


(1)		Global Insight; Coordinating Body of the National Interconnected Electric System of the Dominican Republic (Organismo Coordinador del Sistema Eléctrico Nacional Interconectado de la República Dominicana); Ministry of Energy and Mines of Guatemala (Ministerio de Energía y Minas de Guatemala); and National Dispatch Center of Panamá (Centro Nacional de Despacho de Panamá).

(2)		International Monetary Fund World Economic Outlook Database, April 2008

Acquisitions and Future Greenfield Development. We have experienced growth through acquisitions. 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 makes it difficult to track the financial performance and trends in our overall operations. We intend to continue growing our business through additional acquisitions as well as through greenfield development. As a result of these growth initiatives, our future financial results will continue to reflect substantive changes compared to historical results. Due to the significant costs incurred to develop greenfield energy projects and the fact that revenues are not generated until commercial operations begin, our financial ratios may also be adversely affected due to time mismatches between our investments and the incremental revenues and cash flows generated by them.

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

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growth pattern of energy consumption. We believe that this trend will continue in most of the markets that we serve.

Tariff Reviews. The tariffs of our regulated businesses, particularly those in the Power Distribution and Natural Gas Distribution segments, are periodically reviewed by regulators. These tariffs are reset periodically and are generally based on 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 regulation depending on the business’ performance following a tariff review, as well as on factors out of the business’ control, such as the level of electricity or natural gas consumption. As a result, tariff reviews may result in tariff reductions to reset the business’ returns back to the regulated return levels.

Commodity Price Increases. 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. These commodity price changes also affect our operations in several other ways, such as steel and copper prices which affect the costs of our capital investments.

Political Developments. Political events in the markets in which we operate now or in the future could significantly impact our business and results of operations. For example, as energy demand in many emerging markets continues to grow, we may be presented with increased opportunities to expand and diversify our business as governments seek to encourage investment in the energy sector. Conversely, the political trends in certain countries, notably Venezuela and Bolivia, have resulted in the nationalization of certain infrastructure assets and businesses, particularly in the energy sector.

Environmental Concerns. Many areas of the world are becoming more environmentally conscious, and in many emerging markets, environmental concerns are an important element in the definition of energy infrastructure policies and goals. We attach great importance to being environmentally and socially responsible in the markets in which we operate, identifying within the available and practical alternatives, energy solutions that have the least negative impact on the community.

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 September 30, 2008, $27 million in letters of credit, bank guarantees, and performance bonds were outstanding. In addition, we had $175 million in unused letter of credit availability at our disposal, of which $67 million was cash collateralized.

See Note 21 of the unaudited condensed consolidated financial statements for the nine months ended September 30, 2008 and Note 26 of the consolidated financial statements for the year ended December 31, 2007 included elsewhere in this registration statement for further information on letters of credit, litigation and other contingent issues.

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F. Tabular Disclosure of Contractual Obligations

A summary of contractual obligations, commitments and other liabilities as of December 31, 2007 is presented in the table below:


			Less Than						After
	Total		1 Year		1-3 Years		3-5 Years		5 Years		Other
	Millions of dollars (U.S.)

Debt obligations⁽¹⁾	$	3,264	$	749	$	621	$	552	$	1,342		—
Interest payments on long-term debt⁽²⁾		1,393		314		518		396		165		—
Pension obligations		132		14		26		29		63		—
Capital lease obligations⁽³⁾		51		11		26		6		8		—
Power commitments⁽⁴⁾		13,829		873		1,903		2,009		9,044		—
Fuel commitments⁽⁵⁾		2,793		332		532		477		1,452		—
Transportation commitments⁽⁶⁾		714		82		170		166		296		—
Equipment commitments⁽⁷⁾		142		12		21		20		89
FIN 48 obligations, including interest and penalties		125		—		—		—		—		125
Other commitments⁽⁸⁾		252		134		113		4		1		—

Total	$	22,695	$	2,521	$	3,930	$	3,659	$	12,460		125


(1)		Debt obligations includes 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.

(2)		Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2007 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, 2007.

(3)		Capital lease obligations include the future obligations related to certain sale and leaseback obligations for pipelines and related equipment in which Promigas is the lessee. The leases are all nonrecourse. The net value of the assets held under capital lease totals $26 million. Imputed interest for these obligations totals $14 million. In addition, several of our businesses have entered into non-material operating leases for offices and office equipment and vehicles.

(4)		Represents long-term contracts for the purchase of electricity by electricity distributors from third parties in order to supply their customers.

(5)		Represents contracts for the purchase of fuel subject to termination only in certain limited circumstances.

(6)		Represents a commitment to purchase gas transportation services from an unconsolidated affiliate through 2027.

(7)		Represents commitments of various duration for parts and maintenance services provided by third parties, which are expensed during the year of service.

(8)		Includes certain contractual financing obligations payable to affiliates.

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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
Brent de Jong		Non-Executive Vice Chairman of the board of directors
James Hughes		Chief Executive Officer and Director
Robert Barnes		Director
Philippe A. Bodson		Director
Henri Philippe Reichstul		Director
Robert E. Wilhelm		Director
George P. Kay		Director
John G. Fulton		Chief Financial Officer
Maureen J. Ryan		General Counsel and Chief Compliance Officer
Emilio Vicens		VP Business Development
Laura C. Fulton		VP Chief Accounting Officer
Andrew Parsons		VP Chief Administrative Officer
Brian Zatarain		VP Chief Risk Officer
Brian Stanley		VP Operations

Ronald W. Haddock is non-executive chairman of our board of directors and has been a director first of PEI, and then of the Company since August 2003. 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. Mr. Haddock 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. Mr. Haddock currently serves on the boards of directors of Alon U.S.A. Energy, Inc., Trinity Industries, Inc., Safety-Kleen, Adea International, and Rubicon Offshore International and 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.

Brent de Jong is the non-executive vice-chairman of our board of directors and has been a director first of PEI, and then of the Company since May 2006. Mr. de Jong was our chief executive officer from May 2006 to October 2007 and currently takes an active role in our strategy and development. Mr. de Jong has been with Ashmore, an investment manager dedicated to emerging markets, since 2002 as a senior investment professional. Before joining Ashmore, Mr. de Jong was a member of JP Morgan plc’s Financial Institutions Group focused on mergers and acquisitions in Emerging Europe, the Middle East and Africa. Prior to working with JPMorgan in London, Mr. de Jong worked for three years in JPMorgan’s Structured Finance and Private Placements Group in New York covering Latin America and Emerging Europe. Mr. de Jong holds a degree in economics from Georgetown University.

James Hughes joined us in May 2007 as Chief Operating Officer and became our Chief Executive Officer in 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, Mr. Hughes served as President and Chief Operating Officer of Prisma Energy International, from the date of its creation in 2002 until March 2004. Prior to that role, Mr. Hughes spent almost a decade with Enron Corp. in roles 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

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moving to their Warsaw, Poland office where he specialized in international project development. Mr. Hughes currently serves on the board of Quicksilver Resources Inc., an exploration and production company. He also serves as Quicksilver’s lead independent director and on its audit, compensation and governance committees. 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.

Robert Barnes has been a director first of PEI, and then of the Company since May 2006. Mr. Barnes was, in 1997, one of the founder members of Alchemy Partners LLP, a private equity advisory firm, which has to date advised on deals worth more than £1.5 billion. Mr. Barnes was a full time partner of Alchemy Partners until December 31, 2005. He is now engaged on certain Alchemy portfolio matters as well as pursuing other personal interests, including venture capital activities. Mr. Barnes’s 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. Mr. Barnes is currently a director of Guernsey Pub Company Ltd. and New Horizon Youth Centre, a charity. Mr. Barnes previously sat 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, 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 first of PEI, and then of the Company since July 2003. Mr. Bodson has extensive experience with utility and industrial concerns with international activities, which includes having served as chief executive officer 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, British Telecom Belgium and Diamond Boart and serving today as a director for Exmar, Floridienne, Fortis, Compagnie Immobiliere de Belgique, Cobepa, Hermes Focus Asset Management Europe, Louis de Waele and N.M.G.B. Mr. Bodson 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 currently a member of the board of directors of several charitable organizations or non-profit entities, including la Fondation de l’Entreprise, Contius, Atomium, the Belgian chapter of American Field Service, as chairman of Free and Fair Post Initiative and as an advisor to la Fondation Françoise Dolto. Mr. Bodson received a degree in civil engineering from the University of Liege in Belgium in 1967 and a Master of Business Administration from INSEAD, Fontainebleau, France, in 1969.

Henri Philippe Reichstul has been a director first of PEI, and then of the Company since December 2003. He is currently the CEO of Brenco, a Brazilian ethanol production company. Mr. Reichstul has also been chairman of G & R — Gestão Empresarial, a consulting firm, since 2002. Mr. Reichstul 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. He was 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 was 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, Peugot Citroen and PSA. 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 2002 and also served on the board of directors of Globopar until 2001 and as president of Globopar in 2002. Mr. Reichstul 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 first of PEI, and then of the Company since December 2003. Mr. Wilhelm was employed by Exxon Mobil (and predecessor companies) from 1963 until he retired in 2000.

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Mr. Wilhelm currently is an independent energy consultant and venture capital investor. During his career with Exxon, Mr. Wilhelm held a variety of operating assignments, primarily in the international petroleum business, including CEO for Latin America and executive vice president for all international petroleum activities. Such operating assignments included positions as vice president of Esso Europe 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 (and, since 1992, a member of the board of directors) of Exxon Mobil, with responsibility for finance, long range planning, control, public affairs and the worldwide refining and marketing businesses. He is a member of the Council on Foreign Relations, past vice chairman of the Council of the Americas, and serves on the advisory council of PricewaterhouseCoopers and the Precourt Institute for Energy Efficiency at Stanford University. 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 Masters of Business Administration from the Harvard Business School in 1964.

George P. Kay has been a director of the Company since May 2008. Mr. Kay has been vice president of GIC Special Investment since April 2006, where he is responsible for infrastructure investments in the UK, North 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, Mr. Kay worked in principal finance for the Commonwealth Bank of Australia from September 2000 to April 2006. Prior to that, Mr. Kay worked for Westpac Banking Corporation as Senior Credit Analyst. He received his Masters of Applied Finance from Macquarie University, Australia and a Bachelor of Commerce from University of Canterbury, New Zealand where he studied accounting and economics.

John G. Fulton joined us in August 2006 as Senior Vice President for Finance and became our Chief Financial Officer in March 2007. Mr. Fulton joined us from London-based Cadbury Schweppes plc, where he was Group Treasury Director with global accountability for treasury in the world’s leading confectioner from April 2005 to June 2006. Prior to joining Cadbury Schweppes plc, Mr. Fulton spent four years with Coca-Cola HBC, which is one of the largest bottlers within The Coca-Cola Company System covering 27 countries in central and eastern Europe. During this time, he spent a year based in London as Assistant Treasurer and approximately three years as Group Treasurer based in Athens, Greece. Previous to that he was with ICI plc., based in London. Mr. Fulton received a bachelor’s degree in business studies from Auckland University of Technology specializing in accounting and finance and undertook his accounting and treasury training with one of Australasia’s leading brewer, Lion Nathan, for five years and Bancorp New Zealand, a boutique merchant bank. Mr. Fulton is a member of the New Zealand Institute of Chartered Accountants and the Institute of Finance Professionals New Zealand. Mr. Fulton won the 2004 Corporate Finance Magazine Award for Treasury Excellence in Outsourcing, and has been featured in articles for Euromoney, Corporate Finance and FX&MM magazines.

Maureen J. Ryan joined us in December 2006, became our General Counsel in March 2007 and became our Chief Compliance Officer in late 2008. 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. Ms. Ryan’s 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 Vice President, Business Development for AEI. Prior to 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. Mr. Vicens’ 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

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his BA in Banking and Finance from Universidad Metropolitana in Caracas, Venezuela with honors in 1991 and his MBA from Harvard Business School in Boston, Massachusetts.

Laura C. Fulton joined us in March 2008 and is currently Vice President, Chief Accounting Officer 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 BBA 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 PEI in September 2004 and in March 2008 was appointed Vice President, Chief Administrative Officer for AEI. Mr. Parsons joined Enron Corp. in March 1999. He is responsible for the Administration department which includes Internal Audit, Sarbanes-Oxley project management and special projects, Human Resources and Information Technology. Mr. Parsons has been with AEI since 2004 working as the VP of Internal Controls and prior to that as the VP of Information Systems. Previously, he spent five years with Enron Corp. in several capacities, including serving as Vice President, Corporate Systems and IT 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 B.A. with Honors from Carleton University and an MBA from the University of Houston.

Brian Zatarain joined PEI in January 2002 and is currently Vice President, Chief Risk Officer for AEI. Previously, Mr. Zatarain was a Senior Director at AEI 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. He also serves as a director on the board of several of AEI’s operating businesses. Before joining AEI, Mr. Zatarain held a variety of positions in the international Business Development and Investment Management groups at Enron, and Enron’s affiliate PEI, from March 2000 to May 2006 primarily focused on acquisitions, greenfield development and asset management and restructuring. Prior to Enron, Mr. Zatarain worked at Coastal Power for 3 years supporting the execution of its Latin American energy infrastructure acquisition and greenfield development strategy. Mr. Zatarain holds a BA in Economics from The University of Texas and a MBA from Duke University.

Brian Stanley joined PEI in January 2002 and is currently Vice President, Operations and Safety for AEI with technical and operational responsibility for all of our assets worldwide. Mr. Stanley joined Enron Corp. in 1991. He has served as Operations Manager of the Teeside Power Station in the UK, assuming the position of Plant Manager in 1993. He held other positions within the Company including General Manager of Enron Power Operations, responsible for all power plants in the U.S. and Central America, Vice President Asset Management Enron Europe with responsibility for Power Generation facilities in Europe, and President and CEO of Enron Engineering & Operational Services responsible for global construction, engineering and operations of Power Generation and gas processing facilities. His 46 years experience in the energy industry includes previous employment with Central Electricity Generating Board and PowerGen. He holds an Electrical Engineering degree from Nottingham Regional College of Technology and is a Member of the Institution of Electrical Engineers (MIEE).

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Operations Management

The following table sets forth certain members of our operations management, their age and years of experience as of the date of this registration statement 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	VP and CEO of Promigas		24
Carlos Marcio Ferreira	VP and CEO of Elektro		3
Pablo Ferrero	VP and Country Manager Argentina, Brazil and Bolivia		16
Roberto Figueroa	VP and Country Manager Guatemala, Nicaragua, Dominican Republic, Panama and El Salvador		21
Jacek Glowacki	VP and Country Manager Poland		27
Colin Tam	VP and CEO of AEI Asia		36
Elio Tortolero	VP and Country Manager Venezuela		17

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 personal performance. They also receive an annual discretionary equity grant based on the same criteria. Our directors receive an annual directors fee, which varies based on committee membership and chairman positions, and a annual equity grant. In 2008, we paid our directors an aggregate of $1,239,584. With respect to 2008, we paid our executive officers an aggregate of $3,799,768 (pretax) in salaries and bonuses. In addition, in February 2009 we issued grants of restricted shares and options to our executive officers with an aggregate cash value of $2,168,767 for their services in 2008. 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 Memorandum and Articles of Association, as amended and restated from time to time. 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;

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	•	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.

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 AEI and its 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 annual report on Form 20-F of AEI.

Our audit committee currently comprises Messrs. Wilhelm, Bodson and Barnes. The members of our audit committee 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 and Wilhelm 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 AEI and its 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;

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	•	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 its 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;

	•	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, 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 our annual proxy statement;

	•	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

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	•	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 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. de Jong, 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. de Jong is the chairman of our nominating and corporate governance committee. Our board of directors has determined that Messrs. Wilhelm and Bodson qualify as “independent directors” under the listing standards set forth in NYSE Manual Section 303A.

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 recommend measures necessary to ensure compliance with the listing standards set forth in NYSE Manual;

	•	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 the requirements of the NYSE and applicable listing 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.

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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.

D. Employees

As of December 31, 2007 and 2006, we had 14,500 and 10,500 employees, respectively.

E. Share Ownership

Share Ownership of Directors and Executive Officers

As of the date of this registration statement, our directors and executive officers, as a group, held 2,009,155 of our ordinary shares, 199,319 of which vest over a four year period from the date of grant (as described below) and 1,809,836 of which are vested. In addition, our directors and executive officers, as a group, hold options to acquire 1,033,053 of our ordinary shares, exercisable at prices ranging from $11.18 to $16.70 per share, 111,525 of which have vested.


	Ordinary Shares Held by
	Directors and Executive Officers
	Ordinary
	Shares		Total		Grand
	Beneficially		Options		Total
Name	Owned		Owned		Owned		Percent

Directors and Executive Officers
Ronald W. Haddock⁽¹⁾		1,555,103.45		14,796.00		1,569,899.45		*
Brent de Jong		—		—		—		—
James Hughes⁽²⁾		46,224.19		269,227.00		315,451.19		*
Robert Barnes⁽³⁾		2,322.76		13,120.00		15,532.76		*
Philippe A. Bodson⁽⁴⁾		37,999.56		13,120.00		51,209.56		*
Henri Philippe Reichstul⁽⁵⁾		34,211.89		11,625.00		45,836.89		*
Robert E. Wilhelm⁽⁶⁾		39,556.24		14,796.00		54,352.24		*
John G. Fulton⁽⁷⁾		86,959.23		254,799.00		341,758.23		*
Maureen J. Ryan⁽⁸⁾		23,640.14		133,892.00		157,532.14		*
Emilio Vicens⁽⁹⁾		13,669.04		78,433.00		92,102.04		*
Laura Fulton⁽¹⁰⁾		6,438.04		39,046.00		45,484.04		*
Andrew Parsons⁽¹¹⁾		53,282.60		64,699.00		117,981.60		*
Brian Zatarain⁽¹²⁾		25,769.09		50,071.00		75,840.09		*
Brian Stanley⁽¹³⁾		83,978.83		75,249.00		159,227.83		*
All Directors and Executive Officers as a Group		2,009,155.06		1,033,053.00		3,042,208.06		*

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(1)		1,552,669.34 shares are vested and no additional vesting within 60 days. 875 options are vested and no additional vesting within 60 days.

(2)		2,506.90 shares are vested and no additional vesting within 60 days. 14,845.00 options are vested and no additional vesting within 60 days.

(3)		149.84 shares are vested and no additional vesting within 60 days. 781.00 options are vested and no additional vesting within 60 days.

(4)		35,826.64 shares are vested and no additional vesting within 60 days. 781.00 options are vested and no additional vesting within 60 days.

(5)		32,300.16 shares are vested and no additional vesting within 60 days. 687.00 options are vested and no additional vesting within 60 days.

(6)		37,122.13 shares are vested and no additional vesting within 60 days. 875.00 options are vested and no additional vesting within 60 days.

(7)		14,549.84 shares are vested and no additional vesting within 60 days. 48,380.00 options are vested and no additional vesting within 60 days.

(8)		3,021.35 shares are vested and no additional vesting within 60 days. 18,619.00 options are vested and no additional vesting within 60 days.

(9)		701.82 shares are vested and no additional vesting within 60 days. 5,002.00 options are vested and no additional vesting within 60 days.

(10)		246.41 shares are vested and no additional vesting within 60 days. 1,848.00 options are vested and no additional vesting within 60 days.

(11)		40,515.94 shares are vested and no additional vesting within 60 days. 6,044.00 options are vested and no additional vesting within 60 days.

(12)		17,941.75 shares are vested and no additional vesting within 60 days. 4,380.00 options are vested with no additional vesting within 60 days.

(13)		72,284.12 shares are vested and no additional vesting within 60 days. 8,408.00 options are vested and no additional vesting within 60 days.

*		Owns less than 1.00%.

Incentive Plans

AEI 2007 Incentive Plan

In 2007, AEI 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 bonuses to certain directors, officers and key employees and advisors of AEI. 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 AEI’s 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 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 based on person and company performance. 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 required by the 2007 Incentive Plan.

Restricted Share Grants

Our compensation committee has and may in the future elect to make grants of restricted shares to our executive officers.

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 bonuses to participants under the 2007 Incentive Plan. The amount payable to a participant receiving a grant of performance shares, performance units or a discretionary annual bonus to a participant 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

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restricted share units, share appreciation rights, performance shares, performance units or discretionary annual bonuses under the 2007 Incentive Plan have been awarded to any of our executive officers, directors or employees.

Long-Term Incentive Plan

In 2004, PEI adopted the Prisma Energy Long-Term Stock Incentive Plan, or the Long-Term Incentive Plan, which provided awards to certain directors, officers and key employees of PEI. In 2006, Enron and certain of its subsidiaries signed a Share Purchase Agreement dated May 23, 2006 (and subsequently amended and restated by the Share Purchase Agreement dated June 9, 2006), with AEIL for the sale of 100% of the outstanding equity of PEI in a two-stage transaction, as further described in “Item 4. Information on the Company — A. History and Development.” The Long-Term Incentive Plan remained in place after the change in our control.

The maximum number of share units that can be awarded under the Long-Term Incentive Plan is four million share units, and the number of share units granted under to any individual participant cannot exceed two million share units. The Long-Term Incentive Plan allows for grants in the form of, or in any combination of options, share appreciation rights, restricted share awards, share units and cash awards. The Compensation Committee of AEI’s board of directors administers the Long-Term Incentive Plan.

Under the Long-Term Incentive Plan, PEI granted share units in 2004 and 2005, some of which had time-based vesting and some of which had performance based vesting. As of the date of this registration statement, all units issued under the Long-Term Incentive Plan have vested. An aggregate of 2,862,764 of our ordinary shares were issued in respect of such vested units.

No grants have been made under this plan since 2005 and we do not contemplate making any future grants under this plan. There are no outstanding awards under this plan.

Sales Incentive Plan

In 2005, PEI adopted the Prisma Energy Sales Incentive Plan, or the 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. The excess of Enron’s realized value over defined threshold amounts, and the calendar year in which a change of control becomes effective, determines the amount to be distributed as cash awards through a cash award fund. Cash awards vest 50% upon the effectiveness of a change of control and 50% on the first anniversary of such change in control. All vested cash awards have been and shall be settled and paid as soon as practicable after becoming vested.

In 2006, Enron signed a Share Purchase Agreement dated May 23, 2006 (and subsequently amended and restated by the Share Purchase Agreement dated June 9, 2006), with AEIL and PEI for the sale of 100% of the outstanding equity of PEI in a two-stage transaction, as further described in “Item 4. Information on the Company — A. History and Development.” The closing of Stage 2 of this transaction triggered a change in control under the Sales Incentive Plan. The cash award funds available for distribution under the Sales Incentive Plan in connection with the transaction were $84 million.

Fifty percent of the cash award fund liability of $84 million, or approximately $42 million, vested at the closing of the second stage of the transaction on September 7, 2006. The remaining 50% fully vested 12 months later, provided that the participant was employed continuously by us through such date.

On October 6, 2006, participants under the Sales Incentive Plan were given three options, as follows:


	•	Option 1 — Remain with PEI, and vest and receive payment of 50% of their calculated Sales Incentive Plan awards, with the same vesting and payment schedules as presently laid out in the plan for the second 50% due upon the one-year anniversary of the change in control;

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	•	Option 2 — Remain with PEI, vest and receive payment of 50% of their calculated Sales Incentive Plan awards, and convert all or a portion of the second Sales Incentive Plan payment into a restricted share award; or

	•	Option 3 — Cash out and leave PEI, receiving payment of 50% of their calculated Sales Incentive Plan awards and cash in lieu of their awards under the Long Term Incentive Plan. Participants who chose to leave our employ also received payment of the remaining 50% due under the Sales Incentive Plan less a 16% discount.

The awards granted by PEI in 2005 under the Long Term Incentive Plan provided that, in the event of a change in control, the awards would be cancelled and converted into awards under the Sales Incentive Plan. As a result of the change in control as discussed above, Mr. Haddock’s 2005 awards under the Long Term Incentive Plan were cancelled and Mr. Haddock was reissued units under the Sales Incentive Plan with a total value of $22 million, which was granted on February 15, 2006 with an effective date of August 18, 2005.

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 the date of this registration statement 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
	Number		Percent

Greater than 5% Shareholders
Ashmore Cayman SPC No. 3 Ltd.		20,865,704.11		8.99	%
Ashmore Global Special Situations Fund 2 Limited		13,169,904.15		5.68	%
Ashmore Global Special Situations Fund 3 Limited		26,513,133.95		11.43	%
Ashmore Global Special Situations Fund 4 Limited		4,302,628.73		1.85	%
Ashmore Global Opportunities Limited		6,237,038.27		2.19	%
Asset Holder PCC Limited in respect of Ashmore Emerging Markets Liquid Investment Portfolio		1,325,065.34		0.57	%
EMDCD Ltd.		5,091,644.25		2.19	%
Ashmore Emerging Markets Global Investment Portfolio Limited		1,435,247.81		0.62	%
FCI Ltd		48,028,858.35		20.70	%

Total Ashmore Funds		128,475,162.32		55.37	%
Buckland Investment Pte Ltd		54,588,391.46		23.53	%
Sherbrooke, Ltd.		13,931,096.06		6.00	%

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 (e.g., services including, but not limited to, accounting and legal services, internal audit, implementation and compliance, preparation of financial statements, preparation and filing of tax returns, maintenance and retention of corporate books and records, advice and services related to business development, acquisitions and divestitures, transaction and financing structuring, treasury and cash management services); preparation and filing of required materials/filings with any national, state or other regulators; provision of board members and authorized signatories (including for bank account management) to us and our direct and indirect subsidiaries; and coordination and management of service providers to us and our direct and indirect subsidiaries.

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.

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

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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 approximately $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.

Familial Relationships

The wife of the Vice Chairman of our board of directors was previously a senior vice president of PEI. She was paid aggregate compensation (salary and bonus) of $570,535 in 2005 and $603,201 through the time she left in 2006. The bonus paid in each of 2005 and 2006 was in respect of the prior year’s performance. She also received a payment of $6,311,353 in 2006 under the PEI Sales Incentive Plan adopted by Enron, which represents a 16% discount to the amount she was entitled to receive under this plan. The payment under the plan was triggered by the acquisition of PEI by AEIL. Under the PEI Sales Incentive Plan, payments were to be made in two installments, 50% upon a change of control of PEI and 50% one year later. However, following the change in control employees were offered an alternative of receiving the entire payment in 2006 at a 16% discount and leaving our employ. She elected to take this alternative and terminated her employment with PEI. In November 2006, she entered into an exclusive consulting arrangement with us. Under this consulting arrangement, we paid her $89,600 in respect of services performed in 2006, $603,188 in respect of services performed in 2007 and $182,873 in respect of services from January 1, 2008 through July 31, 2008. Subsequently, she entered into a consulting services agreement effective August 1, 2008, and expiring on December 31, 2009 pursuant to which she will provide consulting services on one specific transaction. Under this consulting services agreement, we paid her $142,800 in respect of services performed from August 1, 2008 through November 30, 2008.

C. Interests of Experts and Counsel

Not applicable.

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Item 9. The Offer and Listing

A. Offer and Listing Details


	Price History of Stock

Not applicable.


	Type and class of securities being offered or listed

The Bank of New York Mellon serves as the transfer agent and registrar for the ordinary shares. As of the date of this registration statement, there were 4,767,963,377 authorized but unissued ordinary shares, including 10,394,718 ordinary shares reserved for issuance under our equity incentive plans. For more information about these plans, see Note 24 to the audited consolidated financial statements for the year ended December 31, 2007 included in this registration statement.

Limitations of rights of securities holders

Not applicable.


	Other securities being offered or listed

Not applicable.

B. Plan of Distribution

Not applicable.

C. Markets

There has been no public market for our ordinary shares.

D. Selling Shareholders

Not applicable.

E. Dilution

Not applicable.

F. Expenses of the Issue

Not applicable.

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Item 10. Additional Information


A.	Share Capital

The following is a brief description of our share capital. As of the date of this registration statement, an aggregate of 224,624,481 ordinary shares were issued and outstanding. Shareholders approved a five for one stock split on December 20, 2007. The following summary description of our share capital is qualified in its entirety by reference to the form of our Amended and Restated Memorandum and Articles of Association, and to the relevant provisions of the Companies Law (2007 Revision) of the Cayman Islands.

Our Amended and Restated Memorandum and Articles of Association will authorize the issuance of an aggregate of five billion ordinary shares, par value $0.002 per share. All of the issued ordinary shares are credited as fully paid and nonassessable. Under Cayman Islands law, nonresidents of the Cayman Islands may freely hold, vote and transfer ordinary shares in the same manner as Cayman Islands residents.

As of the date of this registration statement, there were 4,767,963,377 authorized but unissued ordinary shares, including 10,394,718 ordinary shares reserved for issuance under our equity incentive plans. For more information about these plans, see Note 24 to the audited consolidated financial statements for the year ended December 31, 2007 included in this registration statement. We may issue additional authorized but unissued ordinary shares for a variety of corporate purposes, including acquisitions and future public offerings or private placements to raise additional capital. Subject to any resolution of shareholders and to restrictions in our Amended and Restated Memorandum and Articles of Association, our board of directors is authorized to exercise the power to issue all of the remaining unissued ordinary shares. We do not currently have any plans to issue additional ordinary shares, except in connection with our employee and director benefit plans. Subject to restrictions contained in the intercompany agreement and our Amended and Restated Memorandum and Articles of Association, our board of directors may, without shareholder action, issue ordinary shares out of the already existing authorized share capital. See also “Item 6. Directors, Senior Management and Employees — E. Share Ownership.”


B.	Memorandum and Articles of Association

Dividends

Holders of ordinary shares are entitled to dividends as and when declared, subject to any provisions set forth in our Amended and Restated Memorandum and Articles of Association. Under Cayman Islands law, we may pay dividends in amounts as the board of directors deems appropriate from our retained earnings available for the purpose or our share premium account, which is equivalent to additional paid in capital, if after the payment of the dividend we are able to pay our debts as they come due. Cash dividends, if any, are paid in U.S. dollars.

For a description of laws or regulations affecting dividends and other payments in respect of the ordinary shares, see “ — E. Taxation”

Voting Rights

The holders of ordinary shares have full voting power for the election of directors and for all other purposes. Each holder of ordinary shares has one vote per share. Our ordinary shares do not have cumulative voting rights.

Directors

Our Amended and Restated Memorandum and Articles of Association provide that the board of directors consist of a minimum of five and a maximum of ten directors. Directors may be elected by the shareholders or appointed by the directors to fill a vacancy. See “Item 6. Directors, Senior Management and Employees” for further information regarding the board of directors.

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General Meetings

An annual general meeting is held each calendar year at a time and place appointed by the board of directors. Extraordinary general meetings are convened at the discretion of the board of directors and are also convened upon a written requisition by holders of ordinary shares holding in the aggregate not less than one-tenth of paid-up share capital subject to restrictions set forth in our Amended and Restated Memorandum and Articles of Association.

Quorum

The presence at a shareholder meeting, in person or by proxy, of the holders of a majority of our voting shares will constitute a quorum and permit the conduct of shareholder business. If a meeting is adjourned for lack of a quorum, it will stand adjourned until the directors determine the day, time and place of the reconvened meeting. Shareholders holding not less than 10% of our outstanding voting shares may require the directors to call special meetings of shareholders.

Resolutions

Resolutions, other than special resolutions, may be adopted at shareholders’ meetings by the affirmative vote of a simple majority of the shares entitled to vote thereon and voting at the meeting in question. To be adopted, a special resolution requires the affirmative vote of the holders of a 75% majority of the shares entitled to vote thereon attending and voting at the meeting in question.

Rights in a Winding-Up

Subject to the provisions set forth in our memorandum of association, holders of ordinary and preferred shares are entitled to participate in proportion to their holdings in any distribution of assets in a winding-up after satisfaction of liabilities to creditors.

Transfer Agent and Registrar

The Bank of New York Mellon serves as the transfer agent and registrar for the ordinary shares.

Comparison of U.S. and Cayman Islands Corporate Laws

Under the laws of many jurisdictions in the United States, majority and controlling shareholders generally have “fiduciary” responsibilities to the minority shareholders. However, minority shareholders in a Cayman Islands company may not have the same protections that minority shareholders in a U.S. company would have.

As a matter of Cayman Islands law, a company may bring suit for breaches of duty owed to it. A minority shareholder of a Cayman Islands company can file a lawsuit in its name for direct damages suffered as a result of a breach of duty owed to us or in certain limited circumstances in our name in respect of:


	•	an obligation owed by directors and officers to us in circumstances where those who control our company are acting unconscionably or perpetrating a fraud on the minority;

	•	actions we are taking which we do not have the power to take;

	•	actions that have purported to have been taken without shareholder approval, if such approval is required; or

	•	the personal rights of the shareholder that have been infringed or are about to be infringed.

As in most U.S. jurisdictions, the board of directors of a Cayman Islands company is charged with the management of our company affairs. In most U.S. jurisdictions, directors owe a fiduciary duty to the corporation and its shareholders, including a duty of care and a duty of loyalty. The duty of care requires directors to properly apprise themselves of all reasonably available information. The duty of loyalty requires directors to protect the interests of the corporation and refrain from conduct that injures the corporation or its shareholders or that deprives the corporation or its shareholders of any profit or advantage.

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The board of directors of a Cayman Islands company owes the company the duties of care and skill and the fiduciary duties of honesty and good faith. The duties of honesty and good faith are owed by each director individually to the company and to the company alone. In the exercise of their fiduciary duties, the directors must act in good faith in what they believe to be the best interests of the company. In addition, directors must not restrict their discretion to exercise their powers from time to time and must not, without consent of the company, place themselves in a position where there is a conflict between their fiduciary duties and personal interests.

The duties of care and skill do not require a director to exercise any greater degree of skill than may be reasonably expected from a person of his knowledge and experience. Although a director should give continuous attention to the affairs of our company when able, a director is not required to give continuous attention to our company. In the discharge of his duties of care and skill, a director may delegate duties to another if the director is justified in trusting that person to perform the duties honestly.

Many U.S. jurisdictions have enacted various statutory provisions which permit the monetary liability of directors to be eliminated or limited but no similar provisions exist under Cayman Islands law.

Cayman Islands law provides that a reconstruction of a Cayman Islands company, or its amalgamation with another Cayman Islands company requires the consent of a majority in number holding three-fourths in value of the shares affected (and a similar majority of any creditors if their interests are affected), present and voting in person or by proxy at the meeting and subsequent court approval.

The foregoing description of differences between U.S. and Cayman Islands corporate laws is only a summary and is not complete. For a further description, see “Item 3. Key Information — D. Risk Factors.” We are a Cayman Islands company, and it may be difficult for you to enforce judgments against us and our directors and executive officers.


C.	Material Contracts

The following Material Contracts are attached as exhibits to this registration statement:

1. Credit Agreement, dated March 30, 2007, among AEI, AEI Finance Holding LLC, various financial institutions as lenders, Credit Suisse Cayman Islands Branch, JP Morgan Chase Bank, N.A., Credit Suisse Securities (USA) LLC and J.P. Morgan Securities, Inc. 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, 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 bonuses 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. 2005 Prisma Energy Sales Incentive Plan. In 2005, PEI adopted the Prisma Energy Sales Incentive Plan, a cash award plan, for the benefit of certain directors, officers, and key employees of PEI and its subsidiaries in the event of a divestiture of PEI by Enron. The material terms of this agreement are described in “Item 6. Directors, Senior Management and Employees — E. Share Ownership.”

4. 2004 Prisma Energy Long-Term Stock Incentive Plan. The Long-Term Incentive Plan, provided awards to certain directors, officers and key employees of PEI. No grants have been made under this plan since 2005 and there are no outstanding awards under this plan. The material terms of this agreement are described in “Item 6. Directors, Senior Management and Employees — E. Share Ownership.”

5. 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

156

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.”

6. 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. The agreement will terminate upon consummation of an offering, involving not less than $400 million of gross proceeds (to AEI and/or its shareholders), upon the completion of which the shares will be listed on a stock exchange.

7. 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.

8. 2006 Restricted Stock Agreement. As a result of the change in control of AEI (formerly Prisma Energy International Inc.) that occurred on September 7, 2006, certain employees were entitled to a cash award payment on September 7, 2007, provided the employee remained employed by AEI or a subsidiary on that date or terminated employment prior to that date under certain circumstances. The 2006 Restricted Stock Agreement offered to grant to the employee an award of restricted stock in lieu of the cash award payment. Under the 2006 Restricted Stock Agreement entered into by AEI and the employees that elected this option, the restricted stock became vested and nonforfeitable either (i) 50% on September 7, 2007 and the remainder on September 7, 2008, assuming continuous employment on the applicable vesting date, or (ii) immediately upon the event of a change in control, the executive’s death or disability while in employment, or the executive’s termination by reason of involuntary termination or good reason.

157


D.	Exchange Controls

Not applicable.


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 not intended to be, nor should it be construed as, legal or tax advice to any particular prospective purchaser. 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. To the extent that the discussion relates to matters of Cayman Islands tax law, it represents the advice of Walkers, special Cayman Islands counsel to us. To the extent the discussion relates to legal conclusions under current U.S. federal income tax law, and subject to the qualifications herein, it represents the advice of Clifford Chance US LLP, our special U.S. counsel. You should consult your own tax advisors with respect to the consequences of acquisition, ownership and disposition of our ordinary shares.

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. You will not be subject to Cayman Islands taxation on payments of dividends or upon the repurchase by us of your ordinary shares. In addition, you 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 you 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.

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 written in connection with the promotion or marketing of this offering and 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, holders who are not U.S. Holders, holders who own (directly or through attribution) stock with 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

158

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

Subject to the discussion under “Passive Foreign Investment Company Rules”, below, 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 will not be eligible for the 15% rate of federal income tax available for certain dividends received in tax years beginning on or before December 31, 2010.

Sale or Other Disposition of Ordinary Shares

Subject to the application of the passive foreign investment company rules discussed below, 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. 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.

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 (including the proceeds of a stock offering) 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.

159

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 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 applicable.


G.	Statement by Experts

Not applicable.


H.	Documents on Display

Upon the effectiveness of this Form 20-F, we will be subject to the informational requirements of the Exchange Act. Accordingly, we will be 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.

As a foreign private issuer, we are not subject to the same disclosure requirements as a domestic U.S. registrant under the Exchange Act. We are exempt from the rules under the Exchange Act prescribing the furnishing and content of proxy statements and will not be required to file proxy statements with the SEC, and our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions contained in Section 16 of the Exchange Act. We will file annual reports on Form 20-F within the time period required by the SEC, which is currently six months from December 31, the end of our fiscal year.

In the event we are unable to make available a report within the time periods specified above, we will post a notification on our website describing why the report was not made available on a timely basis, and we will make the report available as soon after the end of such period as is reasonably practicable.


I.	Subsidiary Information

Not applicable.

160

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 September 30, 2008, our floating rate debt at the AEI level consisted primarily of a $947 million term loan facility, $390 million of drawn revolving credit facility and a $105 million synthetic credit facility. Although all three facilities are based on floating rates, we have partially mitigated our interest rate exposure by entering into interest rate swaps based on a notional value of $600 million. We are also exposed to interest rate fluctuations at some of our subsidiaries, the primary ones being Elektro and Promigas. In both 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 partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Using sensitivity analysis and a hypothetical 100 basis point 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 $25 million.

Foreign Exchange Rate Risk

A significant portion of our operating income is exposed to foreign exchange fluctuations. Of the currencies that we are exposed to, we are primarily exposed to fluctuation in the exchange rate between the U.S. dollar and the Brazilian real and the U.S. dollar 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. 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. 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. 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.

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 reais) 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 designate them as cash flow hedges after dividends are declared.

161

Item 19. Exhibits

In reviewing the agreements included as exhibits to this Registration Statement 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 Registration Statement 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	Credit Agreement, dated March 30, 2007, among Ashmore Energy International, AEI Finance Holding LLC, various financial institutions as lenders, Credit Suisse Cayman Islands Branch, JP Morgan Chase Bank, N.A., Credit Suisse Securities (USA) LLC and J.P. Morgan Securities, Inc.
	4.2	AEI 2007 Incentive Plan effective as of January 23, 2007, as amended on August 23, 2007
	4.3	2005 Prisma Energy International Inc. Sales Incentive Plan effective as of August 18, 2005 as amended on May 22, 2006
	4.4	2004 Prisma Energy International Inc. Stock Incentive Plan effective as of September 30, 2004 as amended on August 18, 2005 and May 22, 2006
	4.5	Distribution Concession Contract No. 187/98, dated August 27, 1998, between ANEEL and Elektro Eletricidade e Servicos S.A., as amended
	4.6	Distribution First Amendment to Concession Contract No. 187/98, dated December 14, 1999, between ANEEL and Elektro Electricidade e Servicos S.A.
	4.7	Distribution Second Amendment to Concession Contract No. 187/98, dated July 12, 2005 between ANEEL and Elektro Electridade e Servicos S.A.
	4.8	Distribution Third Amendment to Concession Contract No. 187/98, dated December 18, 2007, between ANEEL and Elektro Eletricidade e Servicos S.A.
	4.9	Second Amended and Restated Shareholders Agreement, dated May 9, 2008, among AEI and the shareholders of AEI identified therein
	4.10	2006 Restricted Stock Agreement
	8.1	List of Subsidiaries of AEI
	15.1	Consent of Deloitte & Touche LLP

174

AEI AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


	September 30,			December 31,
	2008			2007
	Millions of dollars (U.S.),
	except share and par value data

ASSETS
Current assets:
Cash and cash equivalents	$	588		$	516
Restricted cash		74			95
Accounts and notes receivable:
Trade (net of allowance of $95 and $46, respectively)		1,029			650
Unconsolidated affiliates		25			75
Inventories		323			117
Prepaids and other current assets		509			263

Total current assets		2,548			1,716
Property, plant and equipment, net		3,559			3,035
Investments in and notes receivable from unconsolidated affiliates		1,007			1,028
Goodwill		635			402
Intangibles, net		399			237
Other assets		1,322			1,435

Total assets	$	9,470		$	7,853


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	675		$	380
Unconsolidated affiliates		31			94
Current portion of long-term debt, including related party		1,104			749
Accrued and other liabilities		739			525

Total current liabilities		2,549			1,748
Long-term debt, including related party		2,877			2,515
Deferred income taxes		270			168
Other liabilities		1,346			1,276
Commitments and contingencies
Minority interest		494			288

Shareholders’ equity:
Common stock, $0.002 par value, 5,000,000,000 shares authorized; 222,984,113 and 210,403,374 shares issued and outstanding		—			—
Additional paid-in capital		1,730			1,521
Retained earnings		247			122
Accumulated other comprehensive income (loss)		(43	)		215

Total shareholders’ equity		1,934			1,858

Total liabilities and shareholders’ equity	$	9,470		$	7,853

See notes to unaudited condensed consolidated financial statements.

F-2

AEI AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	For the Three						For the Nine
	Months Ended						Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	Millions of dollars (U.S.), except per share data						Millions of dollars (U.S.), except per share data

Revenues	$	2,548		$	830		$	7,152		$	2,287

Costs of sales		2,037			472			5,679			1,227

Operating expenses:
Operations, maintenance, and general and administrative expenses		232			164			681			445
Depreciation and amortization		71			53			203			153
Taxes other than income		8			10			34			24
Other charges		44			—			44			—
(Gain) loss on disposition of assets		13			2			(40	)		(13	)

Total operating expenses		368			229			922			609

Equity income from unconsolidated affiliates		34			21			102			55

Operating income		177			150			653			506

Other income (expense):
Interest income		27			24			68			84
Interest expense		(99	)		(81	)		(292	)		(228	)
Foreign currency transaction gains (losses), net		(47	)		4			(24	)		12
Loss on early retirement of debt		—			—			—			(33	)
Other income (expense), net		7			3			9			(8	)

Total other expense		(112	)		(50	)		(239	)		(173	)

Income before income taxes and minority interests		65			100			414			333
Provision for income taxes		50			49			169			164
Minority interests expense (income)		(4	)		13			120			79

Income from continuing operations		19			38			125			90
Income from discontinued operations		—			—			—			3

Net income	$	19		$	38		$	125		$	93

Basic and diluted earnings per share:
Income from continuing operations	$	0.09		$	0.18		$	0.58		$	0.43
Discontinued operations		—			—			—			0.01

Net income	$	0.09		$	0.18		$	0.58		$	0.44

See notes to unaudited condensed consolidated financial statements.

F-3

AEI AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	For the Nine
	Months Ended
	September 30,
	2008			2007
	Millions of
	dollars (U.S.)

Cash flows provided by operating activities	$	182		$	510

Cash flows from investing activities:
Capital expenditures		(240	)		(155	)
Cash paid for acquisitions, exclusive of cash and cash equivalents acquired		(228	)		(400	)
Proceeds from sale of available for sale securities		38			—
Proceeds from sales of short-term investments		33			—
Proceeds from sale of investments		—			69
Cash and cash equivalents acquired		77			22
Net decrease in restricted cash		57			22
Other		(26	)		(19	)

Net cash used in investing activities		(289	)		(461	)

Cash flows from financing activities:
Issuance of long-term debt		282			1,458
Repayment of long-term debt		(236	)		(1,668	)
Increase (decrease) in short-term borrowings		21			—
Proceeds from issuance of common shares		200			—
Dividends paid to minority interests		(83	)		(30	)
Other		(2	)		(41	)

Net cash provided by (used in) financing activities		182			(281	)

Effect of exchange rate changes on cash		(3	)		47

Increase (decrease) in cash and cash equivalents		72			(185	)
Cash and cash equivalents, beginning of period		516			830

Cash and cash equivalents, end of period	$	588		$	645

Cash payments for income taxes, net of refunds	$	82		$	100

Cash payments for interest, net of amounts capitalized	$	189		$	192

See notes to unaudited condensed consolidated financial statements.

F-4

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED)


1.	BASIS OF PREPARATION

AEI, together with its consolidated subsidiaries, manages, operates and owns interests in essential energy infrastructure businesses in emerging markets across the multiple segments of the energy industry through a number of holding companies, management services companies (“Service Companies”), and operating companies (collectively, “AEI,” the “Company,” or the “Holding Companies”).

The operating companies of AEI as of September 30, 2008 include direct and indirect investments in the international businesses described below and are collectively referred to as the “Operating Companies”:


	2008
	Ownership		Accounting	Location of
Company Name	Interest (%)		Method	Operations	Segment

Accroven SRL (“Accroven”)		49.25	Equity Method	Venezuela	Natural gas transportation and services
Beijing Macro Gas Link Co. Ltd (“BMG”)^(a)		70.00	Consolidated	China	Natural gas distribution
Gas Natural de Lima y Callao S.A. (“Calidda”)		80.85	Consolidated	Peru	Natural gas distribution
Chilquinta Energia S.A. (“Chilquinta”)^(b)		50.00	Equity Method	Chile	Power distribution
DHA Cogen Limited (“DCL”)^(a)		57.13	Consolidated	Pakistan	Power generation
Distribuidora de Electricidad Del Sur, S.A. de C.V. (“Delsur”)		86.41	Consolidated	El Salvador	Power distribution
Empresa Distribuidora de Energia Norte, S.A. (“EDEN”)		90.00	Consolidated	Argentina	Power distribution
Elektra Noreste S.A. (“Elektra”)		51.00	Consolidated	Panama	Power distribution
Elektrocieplownia Sp. z.o.o. (“ENS”)		100.00	Consolidated	Poland	Power generation
Elektro — Eletricidade e Serviços S.A. (“Elektro”)		99.68	Consolidated	Brazil	Power distribution
Empresa Energetica Corinto Ltd. (“Corinto”)^(c)		50.00	Consolidated	Nicaragua	Power generation
EPE — Empresa Produtora de Energia Ltda. (“EPE”)^(d)		50.00	Consolidated	Brazil	Power generation
Empresa Electrica de Generacion de Chilca S.A. (“Fenix”)^(a)		85.00	Consolidated	Peru	Power generation
Gas Transboliviano S.A. (“GTB”)^(e)		17.65	Cost Method	Bolivia	Natural gas transportation and services
GasOcidente do Mato Grosso Ltda. (“GOM”)^(d)		50.00	Consolidated	Brazil	Natural gas transportation and services
GasOriente Boliviano Ltda. (“GOB”)^(d)		50.00	Consolidated	Bolivia	Natural gas transportation and services
Generadora San Felipe Limited Partnership (“Generadora San Felipe”)^(f)		100.00	Consolidated	Dominican Republic	Power generation
Jaguar Energy Guatemala LLC (“Jaguar”)^(a)		100.00	Consolidated	Guatemala	Power generation
Jamaica Private Power Corporation (“JPPC”)		84.40	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”)^(f)		100.00	Consolidated	Dominican Republic	Power generation
Peruvian Opportunity Company SAC (“POC”)^(b)		50.00	Equity Method	Peru	Power distribution
Promigas S.A. E.S.P. (“Promigas”)		52.13	Consolidated	Colombia	Natural gas transportation and services, Natural gas distribution and Retail fuel
Puerto Quetzal Power LLC (“PQP”)		100.00	Consolidated	Guatemala	Power generation
Subic Power Corp. (“Subic”)		50.00	Equity Method	Philippines	Power generation
Tipitapa Power Company Ltd (“Tipitapa”)^(a)		100.00	Consolidated	Nicaragua	Power generation
Tongda Energy Private Limited (“Tongda”)		100.00	Consolidated	China	Natural gas distribution
Trakya Elektrik Uretim ve Ticaret A.S. (“Trakya”)		59.00	Consolidated	Turkey	Power generation
Transborder Gas Services Ltd. (“TBS”)^(d)		50.00	Consolidated	Brazil, Bolivia	Natural gas transportation and services
Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. TBG (“TBG”)^(g)		4.00	Cost Method	Brazil	Natural gas transportation and services
Transredes-Trasporte de Hidrocarburos S.A. (“Transredes”)^(e)		1.28	Cost Method	Bolivia	Natural gas transportation and services

F-5

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


(a)		The Company’s initial or additional interest was purchased during 2008 (see Note 3).

(b)		The Company’s initial interest was purchased during December 2007. POC holds the interest in the operations referred to as “Luz del Sur”. At the time of purchase of the 50.00% interest in Chilquinta, the Company also acquired a 50.00% interest in a related service company, Tecnored S.A. (“Tecnored”).

(c)		As part of the acquisition of an additional interest in Corinto in 2007, the Company acquired a 50.00% interest in Empresa Energetica Corinto Holdings Ltd. (“EEC Holdings”) and began consolidating the accounts of Corinto based on the voting power controlled by AEI (see Note 3).

(d)		These four companies comprise the integrated project “Cuiabá”.

(e)		Through a 50.00% ownership in the holding company TR Holdings Ltda. (“TR Holdings”), the Company’s direct ownership in Transredes and indirect ownership in GTB decreased during the nine month period ended September 2008 as explained further in Note 21. Due to this decrease in ownership, Transredes and GTB are now accounted for using the cost method.

(f)		The Company comprises an integrated part of the operation referred to collectively as “San Felipe”.

(g)		Ownership interest based on direct ownership. Total ownership, including indirect interests held through TR Holdings, is 4.27%.

The accompanying condensed financial statements are unaudited and have been prepared in accordance with generally accepted accounting principles of the United States of America for interim financial information. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for annual financial statements. In the opinion of management, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation, have been included. Interim results are not necessarily indicative of annual results. For further information, refer to the audited consolidated financial statements and notes thereto included in the AEI and subsidiaries audited financial statements as of and for the years ended December 31, 2007 and 2006.

As a result of the sale of Vengas in November 2007 discussed in Note 3, the Company reported discontinued operations for the three and nine months ended September 30, 2007. The presentation of the results of operations through the date of sale is reported in income from discontinued operations in the condensed consolidated statements of operations.

On December 20, 2007, the shareholders of the Company approved a five-for-one stock-split. All share and per share data has been adjusted for all periods presented to reflect that change in capital structure of the Company.


2.	ACCOUNTING AND REPORTING CHANGES

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”), effective for fiscal years beginning after November 15, 2007. SFAS No. 159 includes an amendment of FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities. SFAS No. 159 permits entities to choose, at specified election dates, to measure eligible items at fair value and requires unrealized gains and losses on items for which the fair value option has been elected to be reported in earnings. The Company adopted SFAS No. 159 on January 1, 2008 and has elected not to adopt the fair value option for any eligible assets or liabilities through September 30, 2008.

F-6

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


3.	ACQUISITIONS AND DISPOSALS

Acquisitions

2008 Acquisitions

Sociedad de Inversiones en Energia (“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. The merger was made to advance the strategy of Promigas in its retail gas business. 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, and a gain of $68 million, net of tax of $0 million, was recognized on the 46.03% of Gazel effectively sold to the minority shareholders of SIE. Minority interest expense of $55 million was also recognized as a result of the gain on sale. Goodwill was recorded in the amount of $109 million, representing an estimate of the excess over the estimated fair value of the net assets acquired in the purchase of the additional 16.81% of SIE shares. Goodwill was also recorded in the amount of $82 million, representing an estimate of the step-up in fair value of the net assets of the 46.03% of Gazel sold to minority interest shareholders of SIE. SIE’s balances and results of operations have been consolidated with those of the Company prospectively from January 2, 2008.

The Company is in the process of finalizing its purchase price allocation primarily related to valuation of SIE’s plant, property and equipment, intangibles and its interests in Gazel. Accordingly, the information included in the accompanying condensed financial statements reflects the Company’s portion of the fair value of those assets and liabilities on a preliminary basis.

A summary of the estimated 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		191
Intangibles		78
Other noncurrent assets		11

Assets acquired		417

Current liabilities		87
Long-term debt		66
Other long-term liabilities		17
Minority interest		114

Liabilities assumed		284

Net assets acquired	$	133

The $78 million of acquired intangible assets has been preliminarily 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 realized considering the related expected cash flows. Trademarks have an indefinite life and will not be amortized, but will be evaluated on a regular basis for any impairment. The

F-7

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

weighted average amortization period is estimated as 26 years for continuing customer relationships and 11 years for land use rights.

Pro Forma Results of Operations

The following table reflects the consolidated pro forma results of operations of the Company as if the SIE acquisition described above had occurred as of January 1, 2007.


	For the Three		For the Nine
	Months Ended		Months Ended
	September 30, 2007		September 30, 2007
	Millions of dollars (U.S.)

Revenues	$	1,795	$	5,119
Cost of sales		1,346		3,855
Operations, maintenance, and general and administrative expenses		296		664
Operating income		175		655
Income before income taxes and minority interests		112		447
Minority interests		20		161
Income from continuing operations		38		108
Basic earnings per share	$	0.18	$	0.52

BMG — On January 30, 2008, the Company completed its acquisition of a 70.00% interest in BMG and its subsidiaries for $58 million in cash and recorded $5 million of goodwill as a result of the purchase. A portion of the interest purchased was funded in December 2007 and this 10.23% interest was 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. The Company is in the process of finalizing its purchase price allocation.

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 megawatt (“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 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. The Company is in the process of finalizing its purchase price allocation.

Tipitapa — On June 11, 2008, the Company acquired 100% of Tipitapa, a Power Generation Company with operations in Nicaragua, 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 provides 51 MW of generation capacity and associated energy through a long-term power purchase agreement (“PPA”) with two Nicaraguan distribution companies, both majority owned by Union Fenosa. The Company is in the process of finalizing its purchase price allocation.

DCL — On July 18, 2008, the Company acquired for $19 million 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. However, due to continuing vibration levels since startup, the plant was shut down in September 2008 and is currently not operating. The Company currently cannot predict when the plant will resume operations. On July 30, 2008, the Company acquired an additional 4.81% of DCL for $4 million

F-8

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

in cash, increasing its total ownership to 52.99%. As part of the transactions, the Company’s representation on DCL’s board of directors is five of the total eight members, which allows the Company to exercise control over DCL’s daily operations. The Company recorded a total of $1 million of goodwill as a result of the acquisitions of ownership interests in DCL. The PPA of DCL is accounted for as a direct financing lease by the Company. The Company is still in the process of finalizing its purchase price allocation. Since August 2008, the Company executed additional share subscription agreements for approximately $7 million, that have resulted in an increase in the Company’s ownership to 59.83%.

2008 Greenfield development projects

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-fixed generating facility. A subsidiary of the Company also executed power purchase agreements to sell capacity and energy for 15 year terms. The power generation plant construction is scheduled to begin in the first quarter of 2009 and is expected to be completed in 2012. The plant will be located 80 kilometers south of Guatemala City in Escuintla, Guatemala.

2008 Acquisitions of additional interests in entities already consolidated in 2007

Promigas — During the nine months ended September 30, 2008, Promigas acquired additional ownership interests in consolidated subsidiaries for $46 million in cash and recorded $28 million of goodwill as a result of the purchases. The Company is in the process of finalizing the purchase price allocations.

2008 Acquisitions of development assets

Fenix — On June 26, 2008, AEI acquired an 85% interest in Empresa Electrica de Generacion de Chilca S.A., referred to as “Fenix”, a Peruvian company developing a 544 MW combined cycle power plant in Chilca, Peru. The interest was acquired for $100 million cash paid at the closing. Future capital contributions, of which AEI would be required to pay $20 million, will be required from all shareholders at the commencement of construction and the full commencement of commercial operations.

2007 Acquisitions

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. EDEN is 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-9

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

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 $4 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, 2007, Tongda held controlling interests in eleven 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.

2007 Acquisitions of additional interests in entities already consolidated in 2006

Generadora San Felipe and Operadora San Felipe — On February 22, 2007, the Company acquired an additional 15.00% interest in Generadora San Felipe and an additional 50.00% interest in Operadora San Felipe for $14 million in cash and recorded $5 million of goodwill as a result of the purchases.

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.

Dispositions

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. As a result of 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 condensed 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-10

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

Summarized financial information related to Vengas’ operations is as follows:


	For the Three			For the Nine
	Months Ended			Months Ended
	September 30, 2007			September 30, 2007
	Millions of dollars (U.S.)

Revenues	$	18		$	54
Income (loss) from discontinued operations before income taxes		(1	)		3
(Benefit) provision for income taxes		(1	)		—
Income from discontinued operations		—			3


4.	OTHER CHARGES

Cuiabá — On October 1, 2007, the Company received a notice from EPE’s sole customer, Furnas Centrais Electricas S.A. (“Furnas”), purporting to terminate its agreement with EPE as a result of the current lack of gas supply from Bolivia. EPE contested Furnas’ position and is vigorously opposing Furnas’ efforts to terminate the agreement. The discussions continue in the arbitration stage. EPE determined that it is probable that it will 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 power purchase agreement. As a result of the current arbitration and the continuing lack of a gas supply contract for the EPE plant, in the third quarter of 2008, EPE determined that although a legal arrangement continued to exist and therefore lease accounting still applies, it is probable that it will be unable to collect all minimum lease payment amounts due according to the contractual terms of the lease. Therefore, the Company recorded an additional charge totaling $44 million related to its lease investment receivable reflected as a loss in the line item “Other charges” in the Condensed Consolidated Statement of Operations. The net lease receivable balance as of September 30, 2008 is $127 million. The fair value of the net lease receivable was determined based on expected future cash flows considering various potential scenarios and assigning a probability. Based on estimates and judgments, the Company assigned the most probable outcome to be the EPE plant re-commencing operations in future years under a gas supply agreement based on new market conditions or operating using diesel fuel. The Company also considered the continuation of the lease under the existing PPA, or a similar PPA commencing in the future.

As a result of the above, at September 30, 2008 the Company performed an impairment test of the integrated Cuiabá project, which is considered to be a long-lived asset group with independent cash flows, and determined that there was no impairment. Cash flows used in estimating the lease receivable balance and used in the impairment test could differ from those actually paid or received which could result in further charges recognized by the Company.

F-11

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


5.	(GAIN) LOSS ON DISPOSITION OF ASSETS

(Gain) loss on disposition of assets consists of the following:


	For the Three				For the Nine
	Months Ended September 30,				Months Ended September 30,
	2008		2007		2008			2007
	Millions of dollars (U.S.)				Millions of dollars (U.S.)

Loss on sale of operating equipment	$	3	$	2	$	14		$	8
(Gain) loss on exchange for additional shares of SIE (see Note 3)		6		—		(68	)		—
Loss on sale of debt securities (see Note 12)		—		—		14			—
Gain on sale of BLM (see Note 3)		—		—		—			(21	)
Other		4		—		—			—

	$	13	$	2	$	(40	)	$	(13	)


6.	CASH AND CASH EQUIVALENTS

Cash and cash equivalents include the following:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Parent Company	$	201	$	31
Consolidated Holding and Service Companies		54		157
Consolidated Operating Companies		333		328

Total cash and cash equivalents	$	588	$	516

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.

F-12

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

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):


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Brazilian Real	$	87	$	133
Colombian Peso		77		50
Chinese Renminbi		20		—
Argentinean Peso		9		6
Peruvian Nuevo Sol		6		8
Chilean Peso		4		—
Jamaican Dollar		4		—
Pakistan Rupee		3		—
Polish Zloty		2		4
Other		4		4

Total foreign currency cash and cash equivalents	$	216	$	205

Restricted cash consists of the following:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Current restricted cash:
Restricted due to power purchase agreements	$	2	$	5
Collateral and debt reserves for financing agreements		56		78
Other		16		12

Total current restricted cash		74		95

Noncurrent restricted cash (included in other assets, see Note 12):
Restricted due to long-term power purchase agreements		33		56
Amounts in escrow accounts related to taxes		27		25
Collateral and debt reserves for financing agreements		11		47
Other		15		—

Total non-current restricted cash		86		128

Total restricted cash	$	160	$	223

F-13

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


7.	INVENTORIES

Inventories consist of the following:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Materials and spare parts	$	190	$	78
Fuel		133		39

Total inventories	$	323	$	117


8.	PREPAIDS AND OTHER CURRENT ASSETS

Prepaids and other current assets consist of the following:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Prepayments	$	26	$	30
Regulatory assets		94		30
Deferred income taxes		136		88
Income taxes receivable		65		4
Taxes other than income		30		27
Current marketable securities		5		2
Other		153		82

Total	$	509	$	263


9.	PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant, and equipment, net consist of the following:


	September 30,			December 31,
	2008			2007
	Millions of dollars (U.S.)

Machinery and equipment	$	2,103		$	1,924
Pipelines		805			745
Power generation equipment		687			432
Land and buildings		258			117
Vehicles		25			20
Furniture and fixtures		18			13
Other		118			108
Construction-in-process		183			143

Total		4,197			3,502
Less accumulated depreciation and amortization		(638	)		(467	)

Total property, plant and equipment, net	$	3,559		$	3,035

F-14

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

Depreciation and amortization expense is summarized as follows:


	For the Three				For the Nine
	Months Ended September 30,				Months Ended September 30,
	2008		2007		2008		2007
	Millions of dollars (U.S.)				Millions of dollars (U.S.)

Depreciation and amortization of property, plant and equipment, including those recorded under capital leases	$	64	$	47	$	186	$	135
Amortization of intangible assets, net		7		6		17		18

Total	$	71	$	53	$	203	$	153

The Company capitalized interest of $1 million for both the three months ended September 30, 2008 and 2007, and $6 million and $4 million for each of the nine months ended September 30, 2008 and 2007, respectively.


10.	INVESTMENTS IN AND NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES

The Company’s investments in and notes receivable from unconsolidated affiliates consist of the following:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Equity method:
Accroven	$	22	$	14
BMG’s equity method investments		2		—
Chilquinta		315		330
EEC Holdings		7		7
GTB		—		14
POC		364		344
Promigas’ equity method investments		40		84
Subic		9		7
Tecnored		24		24
TR Holdings (see Note 21)		65		58

Total investments — equity method		848		882
Total investments — cost method		39		27

Total investments in unconsolidated affiliates		887		909

Notes receivable from unconsolidated affiliates:
Chilquinta		98		97
GTB		14		14
TBG		8		8

Total notes receivable from unconsolidated affiliates		120		119

Total investments in and notes receivable from unconsolidated affiliates	$	1,007	$	1,028

F-15

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

The Company’s share of the underlying net assets of its investments at fair value in POC, Chilquinta and Tecnored was less than the carrying amount of the investments. The basis differential of $174 million represents primarily indefinite-lived intangible concession rights which are tested annually for impairment.

Except for the $174 million of 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 credit excess of $94 million at September 30, 2008 is being amortized into income on the straight-line basis over the estimated useful lives of such assets.

Equity income (loss) from unconsolidated affiliates is as follows:


	For the Three					For the Nine
	Months Ended					Months Ended
	September 30,					September 30,
	2008			2007		2008			2007
	Millions of					Millions of
	dollars (U.S.)					dollars (U.S.)

Accroven	$	7		$	5	$	15		$	11
BMG’s equity income from investments in unconsolidated affiliates		(1	)		—		(1	)		—
Chilquinta		8			—		28			—
GTB		—			1		1			5
POC		8			—		24			—
Promigas’ equity income from investments in unconsolidated affiliates		6			6		15			16
Subic		3			3		8			8
Tecnored		1			—		3			—
TR Holdings		2			6		9			15

Total	$	34		$	21	$	102		$	55

Dividends received from unconsolidated affiliates amounted to $32 million and $14 million for the three months ended September 30, 2008 and 2007, respectively, and $54 million and $25 million for the nine months ended September 30, 2008 and 2007, respectively.


11.	GOODWILL AND INTANGIBLES

The Company’s changes in the carrying amount of goodwill are as follows:


	2008			2007
	Millions of dollars (U.S.)

Balance at January 1	$	402		$	290
Acquisitions:
New acquisitions (see Note 3)		236			146
Acquired goodwill from consolidation of new acquisitions		11			—
Translation adjustments and other		(14	)		11

Balance at September 30	$	635		$	447

F-16

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

The Company’s carrying amounts of intangibles are as follows:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Amortizable intangibles
Contracts	$	24	$	39
Concession and land use rights		175		86
Customer relationships		127		74
Software costs		7		6
Other		7		2

Total amortizable intangibles, net of accumulated amortization of $80 and $36, respectively		340		207
Nonamortizable intangibles		59		30

Total intangibles	$	399	$	237

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 Promigas, and the value of certain favorable long-term power purchase agreements. The power purchase agreements are held by several of AEI’s power generation businesses through which the amortization of these contracts may result in income or expense due to the difference between contract rates and projected market rates that increase and decrease over the contract’s life. AEI’s nonamortizable intangibles with indefinite life include concession rights of Elektra and Promigas trademarks at September 30, 2008 and concession rights of Elektra at December 31, 2007. At September 30, 2008 and December 31, 2007, the Company also has intangible liabilities of $58 million and $65 million, respectively, which represent unfavorable power purchase agreements held by three of the power generation businesses (see Note 16).

F-17

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

The following table reflects activity related to investments in debt securities:


	For the Three						For the Nine
	Months Ended						Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	Millions of dollars (U.S.)						Millions of dollars (U.S.)

Available-for-sale debt securities:
Matured debt securities included in debt restructuring agreements:
Fair value at beginning of period	$	143		$	374		$	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 losses on sale of securities		—			—			(14	)		—
Unrealized net gains (losses) affecting other comprehensive income		(28	)		(60	)		(115	)		33

Fair value at end of period		115			314			115			314

Corporate debt securities:
Fair value at beginning of period		—			23			—			24
Unrealized net losses affecting other comprehensive income		—			—			—			(1	)

Fair value at end of period		—			23			—			23

Total available-for-sale securities, end of period		115			337			115			337

Held-to-maturity debt securities:
Participation in commercial bank loan portfolio		22			—			22			—
Promissory notes		2			2			2			2

Total held-to-maturity securities, beginning and end of period		24			2			24			2

Total	$	139		$	339		$	139		$	339

On May 20, 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 September 30, 2008 consist primarily of matured debt securities of an Argentine holding company, Compañía de Inversiones de Energía S.A. (“CIESA”), which holds controlling interests in Transportadora de Gas del Sur S.A. (“TGS”), an Argentine gas transportation company. Sales of available-for-sale securities in the future could result in significant realized gains or losses. See Note 17.

F-19

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


13.	ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Employee liabilities	$	48	$	45
Income taxes payable		48		—
Deferred income taxes		70		56
Other taxes:
Value added taxes		43		42
Taxes on revenues		30		18
Withholding taxes		13		19
Governmental taxes		11		11
Other		28		14
Interest		30		30
Customer deposits		54		14
Dividends payable to minority interests		46		15
Regulatory liabilities		51		89
Tax and legal contingencies		19		15
Cost Increase Protocol payable — Trakya (see Note 21)		31		—
Deferred revenues		28		22
Other accrued expenses		53		55
Other		136		80

Total	$	739	$	525


14.	LONG TERM DEBT

Long-term debt consists of the following:


	Variable or	Interest	Final	September 30,		December 31,
	Fixed Rate	Rate (%)	Maturity	2008		2007
	Millions of dollars (U.S.), except interest rates

Debt held by Parent Company:
Senior credit facility, U.S. dollar	Variable	5.8	2014	$	947	$	979
Revolving credit facility, U.S. dollar	Variable	5.9	2012		390		345
Synthetic revolving credit facility, U.S. dollar	Variable	5.9	2012		105		105
PIK note, U.S. dollar	Fixed	10.0	2018		343		319
Debt held by consolidated subsidiaries:
BMG, Chinese Renminbi	Variable	6.9 - 8.3	2008 - 2014		7		—
BMG, Chinese Renminbi	Fixed	7.0 - 13.2	2008 - 2009		6		—
Cálidda, U.S. dollar	Variable	3.5 - 6.7	2009 - 2015		86		82
Corinto, U.S. dollar	Fixed	6.1	2010		18		22

F-20

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


	Variable or	Interest	Final	September 30,			December 31,
	Fixed Rate	Rate (%)	Maturity	2008			2007
	Millions of dollars (U.S.), except interest rates

Cuiabá, U.S. dollar notes to other shareholders	Fixed	5.9	2015 - 2016		97			99
Delsur, U.S. dollar	Variable	7.0	2015		75			100
DCL, Pakistan Rupee	Variable	13.0 - 16.1	2008 - 2019		81			—
EDEN, U.S. dollar	Variable	5.6	2013		39			44
Elektra, U.S. dollar senior notes	Fixed	7.6	2021		99			99
Elektra, U.S. dollar revolving credit facility	Variable	3.7	2009		29			—
Elektro, Brazilian real debentures	Variable	15.5 - 25.6	2009 - 2011		284			287
Elektro, Brazilian real note	Variable	5.0 - 12.3	2010 - 2020		139			127
ENS, Polish Zloty loans	Variable	7.7	2018		73			77
JPPC, U.S. dollar	Variable	7.4	2011		20			25
Luoyang, Chinese Renminbi	Variable	6.6 - 8.9	2008 - 2016		127			—
PQP, U.S. dollar notes	Variable	5.6	2015		82			90
Promigas, Colombian peso debentures	Variable	15.5 - 15.6	2011 - 2012		92			129
Promigas, Colombian peso notes	Variable	11.1 - 15.7	2008 - 2013		537			253
Promigas, U.S. dollar notes	Variable	2.8 - 8.0	2008 - 2012		295			26
Tongda, Chinese Renminbi	Variable	6.4 - 11.7	2008 - 2010		10			9
Trakya, U.S. dollar notes	Fixed	—	2008		—			26
Trakya, U.S. dollar notes	Variable	—	2008		—			21

					3,981			3,264
Less current maturities					(1,104	)		(749	)

Total				$	2,877		$	2,515

Interest rates reflected in the above table are as of September 30, 2008. The three-month U.S. dollar London Interbank Offered Rate (“LIBOR”) at September 30, 2008 was 4.1%.

Long-term debt includes related party amounts of $649 million as of September 30, 2008 and $721 million as of December 31, 2007 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 September 30, 2008 and $99 million as of December 31, 2007 from loans provided to Cuiabá by other shareholders in the project.

Promigas debt refinancing — During October 2008, Promigas refinanced various credit facilities totaling approximately $151 million. The facilities were denominated in and refinanced in Colombian peso. The interest rates of the refinanced facilities changed from a range of 12.98% to 13.94% to a range of 13.98% to 14.17%. The secured or unsecured nature of each facility was unchanged. The objective of the refinancing was the extension of current maturities of approximately $151 million of those credit facilities beyond the following 24 to 36 months. Financial covenants related to the original credit facilities remained materially unchanged in the refinancing.

DCL — DCL obtained a 5.15 billion 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

F-21

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

are due quarterly with maturity in 2019. The outstanding balance of this facility as of September 30, 2008 is 4.619 billion Rupees ($59 million). The loan is secured by DCL’s fixed and current assets.

DCL also has short-term bank loans of 1.638 billion Rupees ($22 million) for general working capital purposes and a planned 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.

BMG — Certain subsidiaries of BMG maintain various short and long-term loan agreements with financial institutions. These loans are denominated in Chinese Renminbi. The proceeds are used to finance BMG’s investment plan in various franchised city natural gas projects. The short-term loans total $6 million and bear fixed interest rates ranging from 7.0% to 13.2%, which is payable either monthly or quarterly. The long-term loans total $7 million and bear variable interest rates (0.15% to 0.20% over the loan interest rate of the equivalent level set by the People’s Bank of China (“PBOC”) on the issuance date, with interest due quarterly. Certain principal payments are due annually and others are due at maturity. No assets are pledged as collateral under any of these loan facilities.

Trakya — In March 2008, Trakya entered into an agreement with Bayerische Landesbank (“BLB”) for a counter-guarantee to enable a new letter of guarantee for $54 million related to Trakya’s supply of gas. This

F-22

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

new letter of guarantee is valid until March 6, 2009 and replaces Trakya’s previous letter of guarantee that expired earlier in 2008. The BLB counter-guarantee has been restructured and is now only partially cash collateralized. Accordingly, $27 million of Trakya’s cash balances have been reserved in a restricted account with BLB. If, however, certain material adverse conditions relating to Trakya’s Implementation Contract and its Energy Sales Agreement are triggered, there is an obligation for Trakya to fully cash collateralize the counter-guarantee.

ENS — In April 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 power purchase agreement 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. The long-term stability of the new arrangement has allowed ENS to amend its existing credit facility to extend the tenor, reduce the interest rate and change the currency, and to establish a new 40 million Polish zloty ($17 million), three-year revolving working capital facility. 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.


15.	INCOME TAXES

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.

The effective income tax rate for the nine months ended September 30, 2008 and 2007 was 41% and 49%, respectively, and both were higher than the statutory rate primarily due to the Company being taxed in multiple jurisdictions outside of the Cayman Islands and secondarily due to losses generated by the Company in its Cayman Island and other holding company jurisdictions for which no tax benefit has been provided.

The Company recognizes interest accrued related to unrecognized tax benefits and penalties as income tax expense.

F-23

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


16.	OTHER LIABILITIES

Other liabilities consist of the following:


	September 30,		December 31,
	2008		2007
	Millions of dollars (U.S.)

Deferred revenue	$	453	$	414
Special obligations		233		241
Uncertain tax positions		143		125
Notes payable to unconsolidated affiliates		109		120
Tax and legal contingencies		80		93
Unfavorable power purchase agreements		58		65
Taxes payable — San Felipe		66		59
Capital lease obligations		42		30
Cost Increase Protocol payable — Trakya (see Note 21)		29		12
Interest		23		22
Pension and other postretirement benefits		11		10
Regulatory liabilities		29		34
Other		70		51

Total	$	1,346	$	1,276

The majority of the accrued tax and legal contingencies included in other liabilities relate to tax and legal claims of Elektro (see Note 21).


17.	FAIR VALUE OF FINANCIAL INSTRUMENTS

FASB Statement No. 157, Fair Value Measurements (“SFAS No. 157”), defines fair value, establishes a framework for measuring fair value and expands disclosure about fair value measurements. AEI will defer the adoption of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except those items recognized or disclosed at fair value on an annual or more frequently recurring basis, until January 1, 2009.

SFAS No. 157 creates a fair value hierarchy to prioritize inputs used to measure fair value into three levels giving the highest priority to quoted prices in active markets, and the lowest priority to unobservable inputs. The three levels are 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.

F-24

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

The following table presents AEI’s assets and liabilities that are measured at fair value on a recurring basis:


				Fair Value Measurement at Reporting Date Using
				Final Quoted		Significant
				Prices in Active		Other			Significant
				Markets for		Observable			Unobservable
	September 30,			Identical Assets		Inputs			Inputs
Assets	2008			(Level 1)		(Level 2)			(Level 3)
	Millions of dollars (U.S.)

Available-for-sale securities	$	115		$	—	$	115		$	—
Derivatives		8			—		8			—

Total assets	$	123		$	—	$	123		$	—

Derivatives	$	(26	)	$	—	$	(26	)	$	—

Total liabilities	$	(26	)	$	—	$	(26	)	$	—

Available-for-sale securities — The Company’s available-for-sale securities consist primarily of matured debt securities of an Argentine holding company, CIESA, which holds controlling interests in TGS, an Argentine gas transportation company. The matured debt securities are convertible upon governmental approval into equity interests in the holding company pursuant to a debt restructuring agreement, entered into in 2005 and expiring on December 31, 2008. These securities were 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 approximate current fair market value of the securities at September 30, 2008 and December 31, 2007 was $115 million and $233 million, respectively. The value considers primarily the underlying equity value of TGS. The valuation decreased below the original cost beginning in the fourth quarter of 2007 and remains in an unrealized loss position due to the decline in the stock price of TGS. The TGS stock trades on both the Argentine and New York stock exchanges, which have recently been impacted by the current local and world financial crises. The decline in the valuation from its cost through September 30, 2008 has resulted in a total of $130 million of unrealized losses, or 53% less than cost, in the Company’s other accumulated comprehensive income account.

At each period end, including as of September 30, 2008, in order to evaluate any impairment, 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. 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 the near-term probability of converting the debt into equity in CIESA. The Company also considered past actions with two similar matured debt securities included in debt restructuring agreements, one of which was successfully converted to equity and the other matured debt security was sold at a $14 million loss compared to original cost. Based on these items, as well as the Argentine government’s stated intention to not approve the restructuring agreement as currently executed, the Company believes the restructuring agreement will likely be terminated. The debt securities, which represent a claim against the assets of CIESA (representing a 55% interest in TGS), could still ultimately be exchanged for the TGS stock. At September 30, 2008, the approximate fair value of the TGS stock that would be expected to be received was $227 million. The Company believes that the ultimate outcome of the debt will be conversion into an asset at least equal to the original cost of the securities, whether through bankruptcy or a negotiated resolution.

Considering the limited duration for which the securities have been in a loss position, the historical volatility of the securities value, current market conditions, the Company’s intent regarding the conversion to equity of

F-25

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

CIESA through one of various alternatives to gain a controlling interest in TGS and the Company’s ability to hold these securities for a reasonable period of time sufficient for a forecasted recovery of fair value, the Company does not consider those investments to be other-than-temporarily impaired as of September 30, 2008.

Derivatives — The Company hedges its exposure to foreign currency and interest rate risk through the use of derivative instruments including interest rate swaps and foreign currency forwards and swaps. The fair value of AEI’s derivative portfolio is determined using observable inputs including LIBOR rate curves and forward foreign exchange curves.


18.	PER SHARE DATA

Basic and diluted earnings per share were as follows:


	For the Three				For the Nine
	Months Ended				Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Basic earnings per share:
Income from continuing operations (millions of U.S. dollars)	$	19	$	38	$	125	$	90
Average number of common shares outstanding (millions)		223		209		217		209
Income from continuing operations per share	$	0.09	$	0.18	$	0.58	$	0.43
Effect of dilutive securities:
Stock options (millions of options)		—		—		—		—
Restricted stock (millions of shares)		—		—		—		1
Dilutive earnings per share	$	0.09	$	0.18	$	0.58	$	0.43

The Company issues restricted stock grants to directors and employees which are included in the calculation of basic earnings per share. The calculation of diluted earnings per share at September 30, 2007 excluded 1,656,406 stock options issued to employees. These options are excluded from the calculation of diluted earnings per share because the exercise price of those options exceeded the average fair value of the Company’s stock during the related period. The calculation of diluted earnings per share at September 30, 2008 excluded 2,879,537 stock options issued to employees as the effect 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 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, referred to as GIC. 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 pay down its revolving credit facility. Upon closing, a nominee of Buckland was appointed to the Company’s board of directors.

F-26

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


19.	COMPREHENSIVE INCOME

The components of comprehensive income were as follows:


	For the Three						For the Nine
	Months Ended						Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	Millions of dollars (U.S.)						Millions of dollars (U.S.)

Net income	$	19		$	38		$	125		$	93
Other		—			(1	)		—			5
Other comprehensive income (loss):
Foreign currency translation (net of income tax of $0)		(254	)		28			(144	)		129
Amortization of actuarial and investment gains (net of income tax of $0 and $2, respectively)		—			—			—			5
Net unrealized gain (loss) on qualifying derivatives (net of income tax of $0)		1			(7	)		1			(8	)
Net change in fair value of available-for-sale securities (net of income tax of $0)		(28	)		(60	)		(115	)		33

Total other comprehensive income (loss)		(281	)		(39	)		(258	)		159

Comprehensive income (loss)	$	(262	)	$	(2	)	$	(133	)	$	257

Accumulated other comprehensive income consists of the following:


	September 30,			December 31,
	2008			2007
	Millions of dollars (U.S.)

Cumulative foreign currency translation	$	68		$	212
Unrealized derivative losses		(24	)		(25	)
Unamortized actuarial and investment gains		22			22
Unrealized gain (loss) on available-for-sale securities		(109	)		6

Total	$	(43	)	$	215


20.	PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit cost of the Elektro plans are as follows:


	For the Three						For the Nine
	Months Ended						Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	Millions of dollars (U.S.)						Millions of dollars (U.S.)

Service cost	$	1		$	1		$	3		$	2
Interest cost		8			7			24			20
Expected employee contribution		—			—			(1	)		(1	)
Expected return on plan assets for the period		(10	)		(8	)		(29	)		(22	)

Total net periodic pension costs	$	(1	)	$	—		$	(3	)	$	(1	)

F-27

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

The total amounts of employer contributions paid for the three and nine months ended September 30, 2008 were less than $1 million and $1 million, respectively. The expected remaining scheduled annual employer contributions for 2008 are less than $1 million.


21.	COMMITMENTS AND CONTINGENCIES

Letters of Credit — In the normal course of business, AEI and its 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 subsidiaries’ intended business purpose. As of September 30, 2008, AEI and its subsidiaries had entered into letters of credit, bank guarantees, and performance bonds that had outstanding balances of $27 million and $175 million in unused letter of credit availability, of which $67 million of the total facility balances were fully cash collateralized. Additionally, as of September 30, 2008, lines of credit of $1,629 million were outstanding, with an additional $187 million available.

Under a sponsor undertaking agreement, AEI is obligated to provide, or cause to be provided, all performance bonds, letters of credit, or guarantees required under the service agreement between Accroven and its customer, Petróleos de Venezuela Gas, S.A. 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. 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.

Corinto financed its purchase of its assets through an arrangement with the U.S. Maritime Administration (“MARAD”). As part of the security for this financing, MARAD required Enron (Corinto’s former owner) to purchase Corinto’s long-term debt with MARAD (less any amounts already deposited in a reserve fund) in the event that Enron’s corporate rating fell to BB plus or below. MARAD filed a proof of claim against Enron alleging Enron’s breach of the purchase agreement because Enron’s rating fell below BB plus. This issue is still under negotiation as part of the Enron bankruptcy claims process. The Company is obligated to reimburse Enron for amounts up to $8 million which Enron pays related to the MARAD claim. The outstanding balance on the Corinto debt, less amounts in the reserve fund of approximately $7 million, as of September 30, 2008 is $8 million. The Company does not believe that the currently expected outcome of this claim will have a material adverse effect on its financial condition, results of operations, or liquidity.

TBG and its shareholders were provided shareholder parent undertakings. The guaranty provided by one of the Company’s subsidiaries was in the total amount of approximately $17 million. However, TBG cannot call more than approximately $4 million under the guaranty, since the Company has already complied with its capital commitment obligations. The remaining $4 million under the guaranty can be called only under limited circumstances. The Company does not believe that the exposure under these guarantees will have a material adverse effect on its financial condition, results of operations, or liquidity.

Political Matters:

Turkey — Since the change in the Turkish government in November 2002, Trakya and the other Turkish build-operate-transfer (BOT) projects have been under pressure from the Ministry 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 power purchase agreements. 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, but if accepted, implementation of changes to the power purchase agreements will take some time due to the need for a coordinated interaction among multiple

F-28

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

government agencies. 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.

Trakya also has been under pressure from the Turkish Energy Regulatory Market Authority to renegotiate the terms of its contract. In addition, Trakya was in negotiations with the Ministry regarding a contractual decrease in Trakya’s tariff due to a decrease in the Turkish statutory tax rate. In July 2006, the Ministry formally communicated to Trakya in writing its request that the reduction in enacted tax rates would require a discussion regarding an effective retroactive tariff adjustment under Trakya’s Cost Increase Protocol (“CIP”). During the third quarter of 2008, Trakya reached a settlement with the Ministry with respect to this issue and agreed to pay the Ministry approximately $63 million over a two-year period commencing in September 2008, with such payments to be made to TETAS, the Turkish state-run off-taker of Trakya’s energy supply. Over the two-year period, interest will accrue on the unpaid balance at six-month LIBOR plus 3%.

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 subject to payment of compensation for stranded costs. Stranded costs compensation is based upon the capital expenditures incurred before May 1, 2004, which could not be recovered from future sales in the free market, and will be paid in quarterly installments of varying amounts. The maximum compensation attributable to ENS is 1.12 billion Polish zloty (approximately US $470 million).

The European Commission, in a decision dated September 25, 2007, declared the Polish long-term power purchase contracts to be illegal state aid. In the same decision, the above-mentioned Polish legislation allowing for termination of long-term contracts with compensation was declared to be a state aid measure compatible with relevant EU legislation. In the decision, Poland was obligated to terminate the long-term contracts by the end of 2007 (such termination becoming effective as of April 1, 2008), with the entities that voluntarily terminated their contracts within that period not being obligated to return the aid already received. ENS sent notice of its termination of its long-term power purchase contract in December 2007, with such termination being effective as of April 1, 2008. In March 2008, ENS entered into a new power delivery agreement with Mercuria Energy Trading Sp. z o.o. effective April 1, 2008. The Company does not expect the restructuring of ENS’ power sales agreement to have a material adverse effect on its financial condition, results of operations, or liquidity.

Bolivia/Brazil — On May 1, 2006, the Bolivian government purported to nationalize the hydrocarbons industry under Supreme Decree No. 28701. The Decree, among other things, anticipated, through future action, the nationalization of the shares necessary for the state-run oil and gas company, Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), to control at least 50% plus one share of certain named companies, including Transredes. On May 1, 2008, the Bolivian government issued Supreme decree No. 29541 (“Expropriation Decree”) pursuant to which it stated that YPFB would acquire 263,429 shares of Transredes from TR Holdings at a price of US$48 per share. The Expropriation Decree provided that YPFB would make the purchase price available for immediate collection and that YPFB would adopt necessary measures to control and manage Transredes. It further provided that TR Holdings would guarantee the continuity and validity of all service contracts, insurance and other contracts of Transredes and that Transredes was prohibited from disposing of assets, goods or taking other actions that could make its operations more costly or prevent

F-29

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

operations of affiliates. The decree also stated that YPFB would not assume any contingent liability of the former administration of Transredes for actions or decisions taken by the controlling shareholders before May 1, 2008. Finally the decree stated that within 30 days from the date of publication of the decree, the executive president of YPFB would take all corporate measures necessary to guarantee the exercise of the majority shareholding in accordance with the governing documents of Transredes, among them the appointment of a new board of directors, management positions and change of the company’s name. 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. The government subsequently registered these shares in YPFB’s name. At that time, TR Holdings had not been compensated for these shares and the Company filed an arbitration claim against the government demanding, among other things, full compensation. In October 2008, the Company reached a settlement with the Bolivian government pursuant to which the Bolivian government agreed to pay to the Company $120 million in two installments. The first payment was made in October 2008 and the second payment is scheduled to be made approximately four months later. Upon reaching this settlement, the Company withdrew its arbitration proceeding. The Company is also currently evaluating the commercial impact that these political events in Bolivia could have on Cuiabá in Brazil.

Due to a shortage in gas exports from Bolivia, Cuiabá has been experiencing gas supply shortages. The gas supply agreement between TBS and Empresa Petrolera Andina S.A. was not honored by YPFB after nationalization of the gas sector in Bolivia. An interim gas supply agreement between TBS and YPFB was executed on June 22, 2007. TBS and YPFB had periodically extended the provisional gas supply agreement, however, the latest provisional agreement expired on June 30, 2008. Negotiations for a definitive gas supply agreement as well as negotiations with Furnas (Cuiabá’s off-taker) and ANEEL (Agência Nacional de Energia Elétrica, the regulator of the Brazilian electricity sector) are on hold. Cuiabá has not received a regular supply of gas since August 2007 and since that time has only operated sporadically. As a result of a Brazilian government order, EPE entered into an agreement on March 31, 2008 with Furnas to operate on diesel fuel for a 30-day period which was renewable up to a maximum of 120 days. EPE operated on diesel for approximately one month under this agreement but has not been generating electricity since May 2008 and the term of this agreement has now expired. If EPE is unable to secure an adequate long-term supply of gas, the operations of Cuiabá will be materially adversely effected. Under these circumstances, there will be a corresponding negative impact on the Company’s financial performance and cash flows (see Note 4).

Litigation/Arbitration:

The Company’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 September 30, 2008, the Company has accrued liabilities totaling approximately $165 million for claims and suits, as recorded in accrued liabilities and other liabilities. This amount has been determined based on managements’ assessment of the ultimate outcomes of the particular cases, and based on the Company’s general experience with these particular types of cases. Although the ultimate outcome of such matters cannot be predicted with certainty, the Company accrues for contingencies associated with litigation when a loss is probable and the amount of the loss is reasonably estimable. The Company 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 the Company’s financial position, results of operations or liquidity. It is possible, however, that some matters could be decided unfavorably to the Company and that the Company could be required to pay damages or to make expenditures in amounts in excess of that recorded and that could be material, but cannot be estimated at September 30, 2008.

F-30

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

Elektro — Elektro is a party to approximately 5,000 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 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 September 30, 2008, the Company has accrued approximately $18 million (based on the exchange rate on September 30, 2008) related to these cases, excluding those described below.

In December 2007, Elektro received a VAT assessment of approximately $8 million (based on the exchange rate on September 30, 2008) from the São Paulo State Treasury. Elektro believes that it has a strong basis on which to contest this assessment. It has presented an administrative defense and is awaiting the administrative decision.

In December 2007, Elektro received two tax assessments issued by the Brazilian Internal Revenue Service (IRS), one alleging 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 $235 million (based on the exchange rate as of September 30, 2008) 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 IRS appealed this ruling to the Taxpayer Counsel, 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 $32 million (based on the exchange rate as of September 30, 2008) 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 the Company 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 has accrued approximately $48 million (based on the exchange rate as of September 30, 2008) and made a judicial deposit of approximately $20 million (based on the exchange rate as of September 30, 2008) related to this issue and does not believe that the currently expected outcome under these lawsuits will exceed this amount or will have a material adverse effect on its financial condition, results of operations, or liquidity.

Promigas — A class action suit is pending against Promigas pursuant to which the plaintiffs seek to recover $5 million in damages resulting from a pipeline explosion caused by terrorists in October 2001. While the matter is still in the initial stages, the Company does not believe that the currently expected outcome will have a material adverse effect on its financial condition, results of operations, or liquidity. No reserves with respect to this claim have been established.

EPE — On October 1, 2007, EPE received a notice from its off-taker, Furnas, purporting to terminate the power purchase agreement with EPE as a result of the current lack of gas supply from Bolivia described above. EPE notified Furnas that EPE believed that Furnas had no contractual basis to terminate the power

F-31

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

purchase agreement and initiated an arbitration proceeding in accordance with the power purchase agreement. It is anticipated that due to the complexity of the case the arbitration could take more than 18 months to be finalized. If EPE is unable to satisfactorily resolve the dispute with Furnas, the operations of Cuiabá will be materially adversely effected with a corresponding negative impact on the Company’s financial performance and cash flows (see Note 4).

San Felipe Limited Partnership — In 1995, a demand for arbitration was filed against San Felipe in connection with San Felipe’s alleged breach of a settlement agreement arising from a nuisance dispute over San Felipe’s power plant in Puerto Plata, Dominican Republic, which was decided in favor of the plaintiff. In August 2006, a Dominican Republic appeals court ruled against San Felipe, upholding the award of approximately $11 million, including accrued interest and in March 2009 the Dominican Republic Supreme Court rejected San Felipe’s appeal and upheld the lower court’s ruling. The final amount of the award is currently being determined. The Company has accrued $10 million for this claim and does not believe the currently expected outcome will have a material adverse effect on its financial condition, results of operations, or liquidity.

Under San Felipe’s Power Purchase Agreement, 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 September 30, 2008, 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 $21 million at the exchange rates as of September 30, 2008) 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. The Company has accrued approximately $66 million (based on the exchange rate as of September 30, 2008) with respect to the period from January 1998 through September 2008 which management believes is adequate. In addition, San Felipe has a contractual right under its Power Purchase Agreement to claim indemnification from CDEEE for taxes paid by San Felipe although the Company cannot be assured that any such amounts will be collected.

Elektra — In April 2006, Elektra was ordered by a local regulatory authority to reimburse $4 million to its customers in connection with alleged overcharging from July 2002 through June 2006. Elektra has appealed this order and believes that it has good grounds on which to challenge it. The regulatory authority decided in June 2006 to suspend any further action against Elektra until the Supreme Court renders a decision in a similar case brought against an unrelated electricity distribution company in Panama. The Company does not believe that the currently expected outcome will have a material adverse effect on its financial condition, results of operations, or liquidity.

TBS — TBS is currently assessing whether it may have some claims against a former supplier of gas. If TBS decides to initiate any such claims, it is possible that the supplier may file certain claims that it believes it may have against TBS.


22.	SEGMENT AND GEOGRAPHIC INFORMATION

F-32

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)

unconsolidated affiliates due to the fact that the nature of operations in these affiliates are similar to the Company’s operations.

The Company’s reportable segments are Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel. Headquarters and Other expenses primarily 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. It also includes the effects of eliminating transactions between segments including 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.

The tables below present summarized financial data about AEI’s reportable segments. Segment eliminations for intercompany transactions between segments are included in Headquarters and Other.


As of and for the Three Months Ended						Nat. Gas.		Nat. Gas.		Retail		Headquarters
September 30, 2008	Power Dist.		Power Gen.			Trans.		Dist.		Fuel		and Other			Total
	Millions of dollars (U.S.)

Revenues	$	644	$	343		$	51	$	150	$	1,386	$	(26	)	$	2,548
Equity income from unconsolidated affiliates		17		3			10		2		3		(1	)		34
Operating income (loss)		126		(25	)		32		24		45		(25	)		177
Depreciation and amortization		37		8			6		5		15		—			71
Capital expenditures		64		1			5		19		6		5			100
Total assets as of September 30, 2008		3,696		1,995			907		1,089		1,427		356			9,470


As of December 31, 2007 and for the Three Months					Nat. Gas.		Nat. Gas.		Retail		Headquarters
Ended September 30, 2007	Power Dist.		Power Gen.		Trans.		Dist.		Fuel		and Other			Total
	Millions of dollars (U.S.)

Revenues	$	480	$	206	$	52	$	82	$	32	$	(22	)	$	830
Equity income from unconsolidated affiliates		—		3		13		5		1		(1	)		21
Operating income		98		10		32		14		8		(12	)		150
Depreciation and amortization		35		10		4		2		1		1			53
Capital expenditures		44		—		—		5		16		—			65
Total assets as of December 31, 2007		3,732		1,433		1,138		913		384		253			7,853


For the Nine Months Ended					Nat. Gas.		Nat. Gas.		Retail		Headquarters
September 30, 2008	Power Dist.		Power Gen.		Trans.		Dist.		Fuel		and Other			Total
	Millions of dollars (U.S.)

Revenues	$	1,699	$	900	$	153	$	421	$	4,049	$	(70	)	$	7,152
Equity income from unconsolidated affiliates		55		8		27		10		3		(1	)		102
Operating income		326		15		99		85		211		(83	)		653
Depreciation and amortization		109		19		17		14		41		3			203
Capital expenditures		132		3		14		56		26		9			240

F-33

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


For the Nine Months Ended					Nat. Gas.		Nat. Gas.		Retail		Headquarters
September 30, 2007	Power Dist.		Power Gen.		Trans.		Dist.		Fuel		and Other			Total
	Millions of dollars (U.S.)

Revenues	$	1,258	$	630	$	147	$	247	$	100	$	(95	)	$	2,287
Equity income from unconsolidated affiliates		—		8		33		10		4		—			55
Operating income		281		117		95		76		25		(88	)		506
Depreciation and amortization		98		28		15		5		4		3			153
Capital expenditures		112		1		8		10		24		—			155

The tables below present revenues and operating income of the Company’s consolidated subsidiaries by significant geographical location for the three and nine months ended September 30, 2008 and 2007 and property, plant and equipment, net as of September 30, 2008 and December 31, 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.


	Revenues				Operating Income
	For the Three				For the Three					Property, Plant &
	Months Ended				Months Ended					Equipment, Net
	September 30,				September 30,					September 30,		December 31,
	2008		2007		2008			2007		2008		2007
	Millions of				Millions of					Millions of dollars (U.S.)
	dollars (U.S.)				dollars (U.S.)

Colombia	$	1,525	$	125	$	86		$	50	$	859	$	614
Brazil		452		341		35			52		1,385		1,482
Panama		142		94		10			9		246		242
Turkey		123		85		9			11		134		143
Guatemala		63		46		13			12		46		37
Dominican Republic		48		51		(7	)		10		24		23
Other		195		88		31			6		865		494

Total	$	2,548	$	830	$	177		$	150	$	3,559	$	3,035


	Revenues				Operating Income
	For the Nine				For the Nine
	Months Ended				Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	Millions of				Millions of
	dollars (U.S.)				dollars (U.S.)

Colombia	$	4,443	$	392	$	342	$	143
Brazil		1,184		1,057		157		245
Panama		377		298		28		48
Turkey		284		248		6		42
Guatemala		173		122		34		32
Dominican Republic		170		89		12		15
Other		521		81		74		(19	)

Total	$	7,152	$	2,287	$	653	$	506

F-34

AEI AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS (UNAUDITED) — (Continued)


23.	SUBSEQUENT EVENTS

Emgasud — On November 28, 2008, AEI, through certain of its wholly owned affiliates acquired a 28.00% equity interest in Emgasud S.A., (“Emgasud”), an Argentine corporation focused on the electricity and gas industries. This transaction was effected through the contribution of $15 million to Emgasud and the acquisition of minority shareholder equity positions in exchange for 1,699,643 AEI shares. On December 23, 2008, AEI made a second capital contribution to Emgasud of $10 million which increased its ownership interest in Emgasud to 31.89%. The agreement with Emgasud provides for the acquisition by AEI or its affiliates of an equity interest in Emgasud of up to 61.41%.

Nicaragua Energy Holdings — On December 8, 2008, AEI signed an agreement with Centrans Energy Services, a Cayman Islands company (“Centrans”), to contribute their respective interests in various Nicaragua power companies to a common holding company, Nicaragua Energy Holdings, a Cayman Islands company. This transaction closed on January 1, 2009, and currently AEI owns 57.67% and Centrans owns 42.33% of Nicaragua Energy Holdings, which indirectly owns 100% of Corinto and Tipitapa and an interest in the Amayo wind project. In addition, AEI gave Centrans a call option that may be exercised at any time prior to December 8, 2013 to increase its interest in Nicaragua Energy Holdings up to 50%.

Elektro — In August 2001, Elektro filed two lawsuits against the State Highway Department — DER (the State of São Paulo’s regulatory authority responsible for the control, construction and maintenance of the majority of the roads in the state) and other private highway concessionaires 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 State Highway Department and such concessionaires. The lower court and State Court ruled in favor of the State Highway Department. 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 the Superior Court. The Superior Court has not yet ruled on the appeal.

F-35

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, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years then ended. Our audits also included the financial statement schedule, listed in the index to the financial statements. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing 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 at December 31, 2007 and 2006, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As described in Note 2 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes, in 2007 and Statements of Financial Accounting Standards (“SFAS”) No. 123(R), Share-based Payment, and SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, in 2006.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 30, 2008

F-36

AEI AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2007		2006
	(Millions of dollars (U.S.), except share and par value data)

ASSETS
Current assets:
Cash and cash equivalents	$	516	$	830
Restricted cash		95		117
Accounts and notes receivable:
Trade (net of allowance of $46 and $39, respectively)		650		502
Unconsolidated affiliates		75		10
Inventories		117		89
Regulatory assets		30		131
Deferred income taxes		88		26
Prepaids and other current assets		145		134

Total current assets		1,716		1,839

Property, plant, and equipment, net		3,035		2,307

Investments and other assets:
Investments in and notes receivables from unconsolidated affiliates		1,028		203
Regulatory assets		10		5
Deferred income taxes		334		330
Investments in debt securities		306		294
Goodwill		402		290
Intangibles, net		237		78
Other assets		785		788

Total investments and other assets		3,102		1,988

Total assets	$	7,853	$	6,134


LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable:
Accounts payable, trade	$	380	$	259
Unconsolidated affiliates		94		4
Current portion of long term debt		653		279
Current portion of long term debt, related party		96		8
Regulatory liabilities		89		79
Accrued liabilities		436		338

Total current liabilities		1,748		967
Long-term debt		1,890		1,733
Long-term debt, related party		625		657
Deferred income taxes		168		112
Payables to unconsolidated affiliates		120		11
Regulatory liabilities		275		219
Other liabilities		881		637

Total liabilities		5,707		4,336

Commitments and contingencies
Minority interest		288		357

Shareholders’ equity:
Common stock, $0.002 par value, authorized 5,000,000,000 shares; 210,403,374 and 201,888,480 shares issued and outstanding		—		—
Additional paid-in capital		1,521		1,433
Retained earnings (deficit)		122		(9	)
Accumulated other comprehensive income		215		17

Total shareholders’ equity		1,858		1,441

Total liabilities and shareholders’ equity	$	7,853	$	6,134

See notes to consolidated financial statements.

F-37

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Year Ended December 31,
	2007			2006
	(Millions of dollars (U.S.), except share and per share data)

Revenues	$	3,216		$	946

Costs of sales (excluding depreciation shown separately below)		1,796			566

Operating expenses:
Operations, maintenance, and general and administrative expenses		630			193
Depreciation and amortization		217			59
Taxes other than income		43			7
Other charges		50			—
(Gain) loss on disposition of assets		(21	)		7

Total operating expenses		919			266

Equity income from unconsolidated affiliates		76			37

Operating income		577			151

Other income (expense):
Interest income		110			71
Interest expense		(306	)		(138	)
Foreign currency transaction gains (loss), net		19			(5	)
Loss on early retirement of debt		(33	)		—
Other income (expense), net		(22	)		7

Total other income (expense)		(232	)		(65	)

Income before income taxes and minority interest		345			86
Provision for income taxes		(193	)		(84	)
Minority interests		(65	)		(20	)

Income (loss) from continuing operations		87			(18	)
Income from discontinued operations		3			7
Gain from disposal of discontinued operations		41			—

Net income (loss)	$	131		$	(11	)

Basic and diluted earnings per share:
Income (loss) from continuing operations	$	0.42		$	(0.09	)
Discontinued operations		0.21			0.04

Net income (loss)	$	0.63		$	(0.05	)

See notes to consolidated financial statements.

F-38

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Year Ended December 31,
	2007			2006
	(Millions of dollars (U.S.))

Cash flows from operating activities:
Net income (loss)	$	131		$	(11	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		217			59
Other charges		50			—
Increase in deferred revenue		120			28
Deferred income taxes		106			25
Equity earnings from unconsolidated affiliates		(76	)		(37	)
Distributions from unconsolidated affiliates		28			11
Foreign currency transaction (gain) loss, net		(19	)		5
(Gain) loss on disposition of assets		(21	)		7
(Gain) from disposal of discontinued operations		(41	)		—
Loss on early retirement of debt		33			—
Minority interests		65			20
Changes in operating assets and liabilities, net of translation, acquisitions, dispositions and non-cash items:
Trade receivables		(59	)		(34	)
Accounts payable, trade		77			27
Accrued income taxes		(26	)		9
Accrued interest		14			(8	)
Inventories		(7	)		(15	)
Prepaids and other current assets		(5	)		13
Regulatory assets		112			31
Regulatory liabilities		(10	)		8
Other		(3	)		17

Net cash provided by operating activities		686			155

Cash flows from investing activities:
Proceeds from sale of investments		162			24
Capital expenditures		(249	)		(76	)
Cash paid for acquisitions, exclusive of cash and cash equivalents acquired		(1,111	)		(2,280	)
Cash and cash equivalents acquired		21			516
Net decrease in restricted cash		61			27
Other		(35	)		60

Net cash used in investing activities		(1,151	)		(1,729	)

Cash flows from financing activities:
Issuance of long-term debt		1,531			1,788
Repayment of long-term debt		(1,777	)		(172	)
Payment of debt issuance costs		(18	)		(33	)
Increase (decrease) in short-term borrowings		459			(19	)
Dividends paid to minority interest		(101	)		(64	)
Proceeds from issuance of common shares		—			920
Other		(6	)		(25	)

Net cash provided by financing activities		88			2,395

Effect of exchange rate changes on cash		63			3

Increase (decrease) in cash and cash equivalents		(314	)		824
Cash and cash equivalents, beginning of period		830			6

Cash and cash equivalents, end of period	$	516		$	830

Cash payments for income taxes, net of refunds	$	172		$	50

Cash payments for interest, net of amounts capitalized	$	246		$	66

See notes to consolidated financial statements.

F-39

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY


									Accumulated
			Additional			Retained			Other			Total
	Common		Paid-In			Earnings			Comprehensive			Shareholders’			Comprehensive
	Stock		Capital			(Deficit)			Income (Loss)			Equity			Income
	(Millions of dollars (U.S.))

Balance, January 1, 2006	$	—	$	350		$	2		$	(25	)	$	327
Net loss		—		—			(11	)		—			(11	)	$	(11	)
Contribution of invested capital		—		1,088			—			—			1,088			—
Compensation under stock incentive plan		—		(1	)		—			—			(1	)		—
Foreign currency translation		—		—			—			2			2			2
Stock issuance costs		—		(4	)		—			—			(4	)		—
Transition adjustment for pension and other post retirement benefits, net of income tax of $3 million		—		—			—			6			6			—
Change in fair value of available-for-sale-securities		—		—			—			34			34			34

Comprehensive income															$	25

Balance, December 31, 2006	$	—	$	1,433		$	(9	)	$	17		$	1,441
Net income		—		—			131			—			131			131
Contribution of invested capital		—		79			—			—			79			—
Compensation under stock incentive plan		—		9			—			—			9			—
Foreign currency translation		—		—			—			210			210			210
Minimum pension liability adjustments, net of income tax of $8 million		—		—			—			16			16			16
Net unrealized loss on qualifying derivatives		—					—			(25	)		(25	)		(25	)
Change in fair value of available-for-sale-securities		—		—			—			(3	)		(3	)		(3	)

Comprehensive income															$	329

Balance, December 31, 2007	$	—	$	1,521		$	122		$	215		$	1,858

See notes to consolidated financial statements.

F-40

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


1.	DESCRIPTION OF THE COMPANY AND OPERATIONS

AEI (the “Parent Company,” formerly known as Ashmore Energy International and previous to that as Prisma Energy International Inc. (“PEI”)), 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, and operating companies (collectively, “AEI,” the “Company,” or the “Holding Companies”). AEI, through its investments, is involved in power distribution, Power Generation, natural gas transportation and services, natural gas distribution, and retail fuel sales entirely outside of the United States. The Parent Company’s largest shareholders are investment funds (the “Ashmore Funds”), which have directly or indirectly appointed Ashmore Investment Management Limited (“Ashmore”) as their investment manager.

On October 3, 2005, certain Ashmore Funds acquired 51% of Elektra Noreste, S.A.’s (“Elektra”) voting and equity capital. Elektra was formed in 1998 to own and operate certain power distribution facilities and related assets in Panama. As of December 31, 2007, 51% of Elektra’s common stock is owned by the Parent Company, indirectly through a chain of subsidiaries; 48.25% is owned by the Panamanian government; and 0.75% is owned by employees or held as treasury stock. On October 12, 2005, Ashmore Energy International Limited (“AEIL,” formerly known as Elektra Energy International Limited) was formed by Ashmore to act as a holding company for certain energy-related assets acquired by the Ashmore Funds, including Elektra, and to act as a platform to acquire PEI and the 15 operating businesses in which PEI had a substantive interest.

In March 2006, as part of the formation of AEIL, certain Ashmore Funds transferred their interest in Elektra by contributing their collective controlling ownership interest in Constellation Power International Investments, Ltd. (“CPI”), the indirect holder of a 51% interest in Elektra, to AEI LLC, a Delaware limited liability company (“AEI Delaware”), in return for 100% of the membership interests in AEI Delaware. All the membership interests of AEI Delaware were, in turn, contributed to AEIL by those Ashmore Funds in return for ordinary shares of AEIL. These funds, together with certain other funds managed by Ashmore, are now the controlling shareholders of the Parent Company, which indirectly owns 100% of CPI.

Interests in certain debt instruments issued by a number of holding companies of Argentine energy companies were also contributed immediately after the contribution of Elektra by certain Ashmore Funds to AEIL. The debt interests in three of these Argentine holding companies, which held controlling interests in certain Argentine electrical distribution, gas transportation and natural gas distribution companies, including Empresa Distribuidora de Energia Norte, S.A. (“EDEN”), were, in the case of EDEN, or are expected to be, exchanged for equity interests in such holding companies or operating companies pursuant to various restructuring agreements upon receipt of required governmental approvals (see Note 13).

In 2006, AEIL acquired PEI from Enron Corp. and certain of its subsidiaries (collectively, “Enron”) 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 51% of the economic interest.

Due to the requirement to obtain certain governmental / regulatory approvals and consents from PEI’s partners and lenders, which were obtained between the completion of Stage 1 and Stage 2, AEIL was not permitted to, and did not, control the PEI operating businesses until the completion of Stage 2 of the acquisition, although AEIL had significant influence over PEI’s operating and financial policies as a result of its appointment of three of seven directors and certain officers, including the Chief Executive Officer. During that period, PEI remained controlled by Enron and its affiliates. AEI’s ownership in PEI was accounted for using the equity method of accounting for the period from May 25, 2006 to September 6, 2006. PEI’s financial position, results of operations, and cash flows are consolidated in the Company’s financial statements prospectively from September 7, 2006.

F-41

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. In October 2007, the Company changed its name to AEI.

The operating companies of AEI as of December 31, 2007 and 2006 include direct and indirect investments in the international businesses described below and are collectively referred to as the “Operating Companies”:

2007

2006

Ownership

Location of

Company Name

Interest (%)

Operations

Description

Accroven SRL (“Accroven”)

49.25

Venezuela

Gas extraction, fractionation
and storage

Bahia Las Minas Corp. (“BLM”)^(a)

—

51.00

Panama

Power generation

Beijing Macro Gas Link Co. Ltd (“BMG”)^(b)

10.23

—

China

Gas distribution

Gas Natural de Lima y Callao S.A. (“Cálidda”)^(b)

80.85

—

Peru

Gas distribution

Chilquinta Energia S.A (“Chilquinta”)^(b)

50.00

—

Chile

Power distribution

Distribuidora de Electricidad Del Sur, S.A. de C.V. (“DelSur”)^(b)

86.41

—

El Salvador

Power distribution

Empresa Distribuidora de Energia Norte, S.A. (“EDEN”)^(b)

90.00

—

Argentina

Power distribution

Elektra Noreste S.A. (“Elektra”)

51.00

Panama

Power distribution

Elektrocieplownia Sp. z.o.o. (“ENS”)

100.00

Poland

Power generation

Elektro- Eletricidade e Serviços S.A. (“Elektro”)

99.68

Brazil

Power distribution

Empresa Energetica Corinto Ltd. (“Corinto”)^(b)

50.00

35.00

Nicaragua

Power generation

EPE — Empresa Produtora de Energia Ltda. (“EPE”)^(c)

50.00

Brazil

Power generation

Gas Transboliviano S.A. (“GTB”)^(f)

17.00

Bolivia

Gas pipeline

GasOcidente do Mato Grosso Ltda. (“GOM”)^(c)

50.00

Brazil

Gas pipeline

GasOriente Boliviano Ltda. (“GOB”)^(c)

50.00

Bolivia

Gas pipeline

Generadora San Felipe Limited Partnership (“Generadora San Felipe”)^(d)

100.00

85.00

Dominican Republic

Power generation

Jamaica Private Power Corporation (“JPPC”)^(b)

84.40

—

Jamaica

Power generation

Operadora San Felipe Limited Partnership (“Operadora San Felipe”)^(d)

100.00

50.00

Dominican Republic

Power generation

Peruvian Opportunity Company SAC (“POC”)^(h)

50.00

—

Peru

Power distribution

Promigas S.A. E.S.P. (“Promigas”)^(e)

52.13

52.88

Colombia

Diversified gas transportation
and distribution

Puerto Quetzal Power LLC (“PQP”)^(b)

100.00

55.00

Guatemala

Power generation

Subic Power Corp. (“Subic”)

50.00

Philippines

Power generation

Tongda Energy Private Limited (“Tongda”)^(b)

100.00

—

China

Gas distribution

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

59.00

Turkey

Power generation

Transborder Gas Services Ltd. (“TBS”)^(c)

50.00

Brazil and Bolivia

Purchase and sale of
natural gas for EPE

Transportadora Brasileira Gasoduto Bolivia-Brazil S/A-TBG (“TBG”)^(f)

4.00

Brazil

Gas pipeline

Transredes-Trasporte de Hidrocarburos S.A. (“Transredes”)⁽ⁱ⁾

25.00

Bolivia

Gas and liquids pipeline

Vengas, S.A. (“Vengas”)^(g)

—

98.13

Venezuela

LPG transportation and distribution


(a)		The ownership interest in BLM was sold in March 2007 (see Note 3).


(b)		The Company’s initial or additional interest was purchased during 2007 (see Note 3).


(c)		The company comprises an integrated part of the operation referred to collectively as “Cuiabá.”


(d)		The company comprises an integrated part of the operation referred to collectively as “San Felipe”. The remaining unowned interests, amounting to 15% for Generadora San Felipe and 50% for Operadora San Felipe Limited Partnership, were purchased in February 2007 (see Note 3).

F-42

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(e)		During December 2006, the Company purchased an additional 42.98% ownership interest in Promigas through two acquisitions. During December 2007, the Company sold a .75% interest for $19 million in cash (see Note 5). Promigas holds various ownership interests in other operating companies.

(f)		Ownership interest based on direct ownership. Total ownership including indirect interests held through Transredes is 29.75% for GTB, and 7.0% for TBG.


(g)		The ownership interest in Vengas was sold in November 2007 (see Note 3).

(h)		The Company’s initial interest was purchased during 2007 (see Note 3). The Company holds the interest in the operations referred to as “Luz del Sur”.


(i)		In addition, the Company has a small ownership percentage through a partnership in which the Company has a minority interest.

The Cuiaba and Trakya entities are variable interest entities. The Company has ownership interests and notes receivable with Cuiaba, which will absorb a majority of the entity’s expected losses, receive a majority of the entity’s expected residual returns, or both. The Company has a majority equity position in and is closely associated with Trakya’s operations through its Operations and Management agreement. Therefore, the Company has determined that it is the primary beneficiary for both Cuiaba and Trakya.


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. Furthermore, the Company consolidates variable interest entities where it is determined to be the primary beneficiary. 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 for 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 accounting principles generally accepted in the United States of America.

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. For certain acquisitions completed in 2007, the Company is still finalizing its purchase price allocation primarily related to valuation of property, plant and equipment and intangibles. Accordingly, the information included in the accompanying financial statements reflects the fair value of certain of those assets and liabilities on a preliminary basis.

Discontinued Operations — As a result of the sale of Vengas in November 2007 discussed in Note 3, the Company reported discontinued operations for the years ended December 31, 2007 and 2006. 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 an original or remaining 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

F-43

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

power purchase agreements. Restrictions on cash and cash equivalents extending for a period greater than one year have been classified as non-current in other assets.

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 method.

Regulatory Assets and Liabilities — As the Company has certain operations that are subject to the provisions of the Statement No. 71, Accounting for the Effects of Certain Types of Regulation, assets and liabilities that result from the regulated rate making process are recorded that would not be recorded under generally accepted accounting principles for non-regulated entities. The Company capitalizes incurred allowable costs as deferred regulatory assets if there is a probable expectation that future revenue 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 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		5-50 years
Pipelines		21-40 years
Power generation equipment		18-30 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 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.

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.

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

F-44

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

component of accumulated other comprehensive income (loss) in shareholders’ equity until realized. 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 electric distribution, c) improved operational efficiencies for the gas distribution business, 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 for impairment at least annually.

Intangible Assets — The Company’s intangible assets, excluding goodwill, are primarily made up of power purchase agreements, concession rights, continuing customer relationships and joint-operating agreements. The power purchase agreements have a finite life and are amortized based on the unit method over the term of the agreement. The total value of the agreements represents the present value of the total estimated net earnings to be realized due to the agreements. Amounts amortized each year are representative of the discounted projected net earnings for the respective year. The weighted-average life of all power purchase agreements is 10 years. Customer relationships, amortizable concession rights and joint-operating agreements 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. At each period-end presented, the Company had no material asset retirement obligations.

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 primarily attributable to sales and other revenues associated with the transmission and distribution of power; sales of liquefied petroleum gases (“LPG”); sales from the generation of power; and revenues from providing administrative, operations, and maintenance services to unconsolidated affiliates. 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 and the approved or contractual billing rates for each category of customer. Accrued revenues were $134 million and $113 million as of December 31, 2007 and 2006. 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. The Company determined that certain power purchase agreements should be considered leases and recognizes these revenues ratably over the term of the power purchase agreement based on a levelized rate of return considering the terms of the agreement. Taxes collected from customers and remitted to governmental authorities are excluded from revenues.

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-hour 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 from new customers are received in advance and are recognized over the shorter of the estimated life of the customer relationship or the life of the concession

F-45

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Diluted earnings per share is calculated similarly, except that it includes the dilutive effect of the assumed exercise of securities, including the effect of outstanding options and securities issuable under the Company’s stock-based incentive plans. Potentially dilutive securities are excluded in 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 enters 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 a cash flow hedges are reflected in accumulated other comprehensive income (loss) and recognized in income when the hedged transaction occurs. 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. Some contracts of the Company do not meet derivative classification requirements due to the fact that the contracts are not readily convertible to cash.

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 2006, the Company adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.

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. In 2006, the Company adopted SFAS No. 123(R), Share-based Payment.

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

F-46

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 of the international subsidiaries is the U.S. dollar due to their operating, financing, and other contractual arrangements. For the periods presented, the Operating Companies that are considered to have their local currency as the functional currency are EDEN in Argentina, Tongda in China, Elektro in Brazil, 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 balances, including gains/losses, eliminate upon consolidation.

Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 period. 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, impairments of goodwill, intangible assets and equity method investments, collectibility 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.

Recent Accounting Policies — In February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement No. 155, Accounting for Certain Hybrid Financial Instruments, (“SFAS No. 155”), which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation and clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS No. 133. The Company’s adoption of SFAS No. 155 on January 1, 2007 did not have a material impact on the Company’s consolidated financial statements.

In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes and prescribes the minimum threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted FIN 48 on January 1, 2007, and recorded a reduction to beginning retained earnings of less than $1 million. See Note 18.

In December 2007, the FASB issued Statement No. 141 (Revised 2007), Business Combinations (“SFAS No. 141R”), that 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. SFAS No. 141R 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, SFAS No. 141R determines what information must be disclosed to enable users of the financial statements to evaluate the

F-47

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

nature and financial effects of the business combination. The Company will adopt SFAS No. 141R in 2009 as appropriate for any future business combinations.

In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Certain requirements of SFAS No. 157 are effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of SFAS No. 157 has been deferred for one year by the FASB. The Company adopted the sections of SFAS No. 157 which are effective for fiscal years beginning after November 15, 2007 and there was no impact on the Company’s consolidated financial statements. The Company will adopt the remaining requirements of SFAS No. 157 on January 1, 2009, and has not yet determined the impact, if any, on the Company’s consolidated financial statements.

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”), effective for fiscal years beginning after November 15, 2007. SFAS No. 159 includes an amendment of FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities. SFAS No. 159 permits entities to choose, at specified election dates, to measure eligible items at fair value and requires unrealized gains and losses on items for which the fair value option has been elected to be reported in earnings. The Company adopted SFAS No. 159 on January 1, 2008 and has elected to not adopt the fair value option for any eligible assets nor liabilities.

In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51 (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Company will adopt SFAS No. 160 on January 1, 2009 and has not yet determined the impact, if any, on the Company’s consolidated financial statements.


3.	ACQUISITIONS AND DISPOSALS

Acquisitions of additional interest in entities already consolidated in 2006

Generadora San Felipe and Operadora San Felipe — On February 22, 2007, AEI acquired an additional 15% interest in Generadora San Felipe and an additional 50% LP 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.

2007 Acquisitions

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 of $181 million was financed by $100 million of third party debt and $81 million of cash. Delsur is an electricity 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 being conversion of AESEBA debt to equity and $17 million in cash. AESEBA

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

holds 90% of the equity of EDEN. EDEN is 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. On June 26, 2007, AEI entered into a contract to sell a 15% interest in AESEBA to a third-party. In 2008, AEI and the third-party have agreed in principle to terminate the contract for nominal consideration with AEI retaining 100% of the equity of AESEBA, with the termination expected to be finalized in the second quarter of 2008.

Cálidda — On June 28, 2007, AEI and Promigas acquired 100% of the equity ownership of Cálidda for $56 million in cash. AEI and Promigas now own Cálidda through a 60/40 equity ownership split. Cálidda is a Peruvian natural gas distribution company that owns the concession to operate in Lima and Callao provinces.

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.

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 includes, among other associated companies, service companies, including Tecnored S.A. (“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.

BMG — On December 17, 2007, AEI completed the acquisition of a 10.23% interest in BMG for $6 million. BMG constructs urban gas pipelines, sells and distributes gas, and operates auto-filling stations in China.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of the estimated fair values of the consolidated assets acquired and liabilities assumed as of the date of acquisitions is as follows:


	DelSur		EDEN		Cálidda		Tongda		JPPC		Corinto
	Millions of dollars (U.S.)

Current assets	$	37	$	45	$	26	$	12	$	28	$	29
Property, plant, and equipment — net		72		95		83		28		76		37
Goodwill		53		—		—		4		—		—
Intangibles		83		6		48		31		—		3
Other noncurrent assets		—		36		7		3		12		10

Assets acquired		245		182		164		78		116		79

Current liabilities		21		57		11		23		11		35
Long-term debt		—		38		76		4		20		14
Other long-term liabilities		34		5		21		2		48		18
Minority interest		9		7		—		4		11		(2	)
Preferred stock		—		—		—		—		—		7

Liabilities assumed		64		107		108		33		90		72

Net assets acquired	$	181	$	75	$	56	$	45	$	26	$	7

Of the $171 million of acquired intangible assets, $85 million was allocated to concession rights in EDEN, Cálidda and Tongda, $83 million to continuing customer relationships in DelSur, and $3 million to a power purchase agreement in Corinto. The concessions rights will be amortized on a straight-line basis over the remaining life of the concessions. Continuing customer relationships will be amortized based on the benefits realized considering the expected cash flows of the DelSur project. The power purchase agreement will be amortized based on the benefits realized considering the expected cash flows of the Corinto project. The weighted average amortization period is 26 years for concession rights, 37 years for continuing customer relationships, and 7 years for the power purchase agreement.

2006 Acquisitions

PEI — During 2006, AEIL completed the acquisition of all of the assets and assumed substantially all of the operating liabilities of PEI in two stages accounted for as a purchase step acquisition (see Note 1). For the period from May 25, 2006 to September 6, 2006, AEIL’s ownership in PEI was accounted for using the equity method of accounting. The aggregate consideration paid for the acquisition was as follows:


Stage 1:
Debt assumed by AEI	$	727
Cash consideration		563
Stage 2:
Cash consideration		462
Other — transaction costs		16

Total	$	1,768

PEI owned and operated its businesses through a number of intermediate holding companies, management services companies, and operating companies and was involved in power distribution, Power Generation, and natural gas transportation and services outside of the United States. AEIL acquired PEI to expand its portfolio of energy infrastructure assets in various international emerging markets. The acquisition cost was less than

F-50

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the fair value of PEI’s net assets at the date of acquisition. The excess of the fair value of net assets over cost of $59 million was recorded as a pro rata reduction to the amounts assigned to noncurrent assets of PEI. Intangible assets acquired of $21 million consisted primarily of power purchase agreements, which are being amortized over the term of such agreements.

Promigas — On May 23, 2006, PEI distributed a portion of its interests in a holding company that held shares representing a 33.04% ownership interest in Promigas (“Promigas Equity”) to a subsidiary of Enron. PEI retained 9.9% of Promigas that AEIL obtained in connection with its purchase of PEI and continued to account for its investment under the equity method due to PEI’s significant financial influence. Under Colombian securities law, at such time, an investor could not acquire 10% or more of an entity listed on the Colombian stock exchange without doing so through a public process in the Colombian stock exchange. In accordance with the Share Purchase Agreement among Enron, certain subsidiaries of Enron, AEIL, and PEI, Enron commenced a public auction process (a “martillo”) of the Promigas Equity through the Colombian stock exchange. On December 22, 2006, PEI purchased the 33.04% ownership interest in Promigas from Enron for $350 million. On December 27, 2006, PEI purchased an additional 9.94% ownership interest in Promigas, also through a martillo, from another shareholder for $161 million. PEI incurred $1 million in acquisition costs related to both martillos. With the conclusion of the acquisitions in December 2006, PEI held a 52.88% ownership interest and began consolidating the accounts of Promigas. PEI acquired Promigas to further expand its portfolio of essential energy infrastructure assets and to gain a controlling position in Promigas. The acquisitions resulted in approximately $289 million of goodwill, which is not deductible for income tax purposes, and $20 million of recognized intangible assets comprised primarily of joint-operating agreements in its retail business.

A summary of the estimated fair values of the assets acquired and liabilities assumed during 2006, which includes earnings of PEI of $59 million from May 25, 2006 to September 6, 2006, is as follows:


	PEI		Promigas
	Millions of dollars (U.S.)

Current assets	$	1,835	$	167
Property, plant and equipment, net		1,646		488
Goodwill		—		289
Intangibles		21		20
Other noncurrent assets		933		304

Assets acquired		4,435		1,268

Current liabilities		872		176
Long-term debt		932		223
Other long-term liabilities		618		206
Minority interest		186		151

Liabilities assumed		2,608		756

Net assets acquired	$	1,827	$	512

Disposals

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 undertook the divestiture after the acquisition of PEI because of Panamanian legislation limiting the common control of distribution and generation companies within the

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

territory of Panama. The Company recognized a gain of $21 million in the first quarter of 2007 as a result of the sale of BLM which is reflected in (gain) loss on disposition of assets in the consolidated statement of operations.

At December 31, 2006, BLM was a long-lived asset held for sale included in prepaids and other current assets, other assets, accrued liabilities and other liabilities. The carrying amounts of the major classes of assets and liabilities of BLM, were as follows:


	December 31, 2006
	Millions of dollars (U.S.)

Current assets	$	23
Property, plant, and equipment — net		81
Noncurrent assets		5
Total		109
Current liabilities		16
Long-term debt		33
Noncurrent liabilities		4

Total	$	53

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 for which no taxes were recorded due to certain exemptions under the holding company’s tax regime status. Vengas was previously presented as part of the retail fuel segment.

As the operations and cash flows of Vengas have been eliminated from the ongoing operations of the Company, and Vengas will not have any significant continuing involvement in the operations of the Company, the presentation of the results of operations of this businesses through the date of sale are reported in income from discontinued operations in the consolidated statement of operations.

Summarized financial information related to these operations is as follows:


	For the Year Ended December 31,
	2007		2006
	Millions of dollars (U.S.)

Revenues	$	64	$	23
Income from discontinued operations before taxes		3		7
Provision for income tax		—		—
Income from discontinued operations		3		7
Gain on sale of discontinued operations, net of tax		41		—

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Pro Forma Results of Operations

The following table reflects the comparative consolidated pro forma results of operations of the Company as if the acquisitions and disposals described above had occurred as of January 1, 2007 and January 1, 2006, respectively.


	For the Year Ended December 31,
	2007		2006
	Millions of dollars (U.S.)

Revenues	$	3,452	$	3,044
Cost of sales		1,946		1,694
Operations and maintenance expense		974		833
Operating income		664		620
Other expense		319		174
Income from continuing operations before income taxes		286		367
Net income from continuing operations		126		49
Basic earnings per share	$	0.60	$	0.25


4.	OTHER CHARGES

Cuiaba — During the fourth quarter of 2007, the Company recorded a charge totaling $50 million against its lease investment receivable balance associated with the EPE power purchase agreement. On October 1, 2007, the Company received a notice from EPE’s sole customer, Furnas Centrais Electricas S.A. (“Furnas”), purporting to terminate its agreement with EPE as a result of the current lack of gas supply from Bolivia. EPE contested Furnas’ position and is vigorously opposing Furnas’ efforts to terminate the agreement. The discussions are currently in the arbitration stage. EPE determined that it is probable that it will be unable to collect all minimum lease payment amounts due according to the contractual terms of the lease. Accordingly, an allowance was recorded against the total minimum lease receivable. Also, during the fourth quarter 2007, due to the current arbitration, the lack of gas and the reduced operations of the EPE generation facility, the Company performed an impairment test of Cuiaba, which is considered to be the long-lived asset group with independent cash flows, and determined that there was no impairment. If EPE’s resolution with Furnas differs significantly from its current estimates or if EPE is unable to secure an adequate supply of gas or find acceptable alternative sources of fuel supply, an additional allowance for minimum lease receivables may need to be recorded, and the value of Cuiaba may need to be impaired. At this time, the Company is unable to predict the ultimate impact or duration of the current issues related to Cuiaba.


5.	(GAIN) LOSS ON DISPOSITION OF ASSETS

(Gain) loss on disposition of assets consists of the following:


	For the Year Ended December 31,
	2007			2006
	Millions of dollars (U.S.)

Loss on sale of operating equipment	$	10		$	7
Gain on sale of BLM		(21	)		—
Gain on sale of shares of Promigas		(10	)		—

	$	(21	)	$	7

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company recognized a gain on the sale of its interest in BLM during the first quarter of 2007 of $21 million (see Note 3). As a result of 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 statement of operations.

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 (EXPENSE) INCOME, NET

Other (expense) income, net, consists of the following:


	For the Year Ended December 31,
	2007			2006
	Millions of dollars (U.S.)

Insurance claims settlements	$	—		$	7
Dividend income		3			—
Gain (loss) on derivatives		(13	)		2
Other		(12	)		(2	)

	$	(22	)	$	7

The Company maintains insurance for damage and business interruption to cover most equipment failures. Insurance recoveries are recorded when the amount is determined and payment is assured. The Cuiaba operating companies (EPE, GOM, and GOB), consolidated through PEI, entered into a lawsuit against their insurer in order to claim reimbursement for losses resulting from a failure in one of EPE’s turbines, which occurred during 2001. The final settlement amount of $4 million was received and recorded in the fourth quarter of 2006. Additionally, in the fourth quarter of 2006, BLM received a final settlement of $3 million for an insurance claim related to business interruption and damages to its principal generating units, resulting from a lighting strike in 2000.

The Company recognized a $14 million loss related to foreign currency derivative transactions in 2007. The Company also recognized $1 million and $2 million gain in 2007 and 2006, respectively, for the ineffective portion of interest rate swaps that qualified for hedge accounting treatment (see Note 21).


7.	CASH AND CASH EQUIVALENTS

Cash and cash equivalents include the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Parent Company	$	31	$	223
Consolidated Holding and Service Companies		157		163
Consolidated Operating Companies		328		444

Total cash and cash equivalents	$	516	$	830

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

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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):


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Brazilian Real	$	133	$	244
Colombian Peso		50		34
Peruvian Nuevo Sol		8		—
Venezuelan Bolivar		—		7
Argentinean Peso		6		—
Polish Zloty		4		4
Other		4		3

Total foreign currency cash and cash equivalents	$	205	$	292

Restricted cash consists of the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Current restricted cash:
Restricted due to power purchase agreements	$	5	$	1
Collateral and debt reserves for financing agreements (see Note 17)		78		106
Other		12		10

Total current restricted cash		95		117

Noncurrent restricted cash (see Note 15):
Restricted due to long-term power purchase agreements	$	56	$	47
Amounts in escrow accounts related to taxes		25		16
Collateral and debt reserves for financing agreements (see Note 17)		47		76

Total non-current restricted cash		128		139

Total restricted cash	$	223	$	256

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


8.	INVENTORIES

Inventories consist of the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Materials and spare parts	$	78	$	61
Fuel		39		28

Total inventories	$	117	$	89


9.	REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities consist of the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Regulatory assets, current		30		131
Regulatory assets, noncurrent		10		5

Total assets	$	40	$	136

Regulatory liabilities, current		89		79
Regulatory liabilities, noncurrent		34		25
Special obligations		241		194

Total liabilities	$	364	$	298

Special obligations represent contributions from consumers to be invested in Elektro’s property, plant, and equipment. The assets acquired, using the funds received from consumers or the assets provided directly to Elektro by the consumers, are recognized in property, plant, and equipment. In October 2006, the regulator of the Brazilian electricity sector, ANEEL — Agência Nacional de Energia Elétrica (“ANEEL”), issued a resolution that modified the terms of the tariff rate-setting process, which, among other things, established that the depreciation associated with these assets acquired from consumers will no longer be considered as a component of the tariff to be granted to the concessionaire. Additionally, in accordance with this new ANEEL regulation, the Special Obligation balance began being amortized in August 2007 using the depreciation rates of property, plant, and equipment. Future additions to Special Obligations will be recorded at their current value at the time of the acquisition of the new assets.

Regulatory current assets include $11 million of assets which do not earn a return and will be collected within the following twelve months.

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


10.	PREPAIDS AND OTHER CURRENT ASSETS

Prepaids and other current assets consist of the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Prepayments	$	30	$	15
Assets held for sale		—		23
Net investment in direct financing lease		—		26
Income taxes receivable		4		10
Taxes other than income		27		17
Other		84		43

Total	$	145	$	134


11.	PROPERTY, PLANT, AND EQUIPMENT, NET

Property, plant, and equipment, net consist of the following:


	2007		2006
	Millions of dollars (U.S.)

Machinery and equipment	$	1,924	$	1,419
Pipelines		745		612
Power generation equipment		432		362
Land and buildings		117		81
Vehicles		20		21
Furniture and fixtures		13		14
Other		108		66
Construction-in-process		143		112

Total		3,502		2,687
Less accumulated depreciation and amortization		467		380

Total property, plant and equipment, net	$	3,035	$	2,307

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 $1,389 million and $1,143 million at December 31, 2007 and 2006, 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 $143 million at December 31, 2007 and 2006.

Promigas has property, plant, and equipment that, as part of its concession agreement, for which the government has the option to purchase upon conclusion of the contract in 2026 or of its extended term, if any, at a price to be determined between the parties or by independent appraisers. The property, plant, and

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

equipment balance, net of accumulated depreciation, was $614 million and $512 million at December 31, 2007 and 2006, respectively.

Depreciation and amortization expense for total property, plant, and equipment was $184 million and $55 million for the years ended December 31, 2007 and 2006, respectively. These totals include the amortization of assets recorded under capital leases (see Note 17). The Company capitalized interest of $5 million in 2007 and $6 million in 2006.

Property, plant, and equipment of several of the Operating Companies is pledged as collateral for their respective long-term financings (see Note 17).


12.	INVESTMENTS IN AND RECEIVABLES FROM UNCONSOLIDATED AFFILIATES

AEI’s investments in and receivable from unconsolidated affiliates consist of the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Equity method:
Accroven	$	14	$	5
Chilquinta		330		—
ECC Holdings		7		—
GTB		14		7
POC		344		—
Promigas’ equity method investments		84		107
Subic		7		5
Tecnored		24		—
Transredes		58		40

Total investment — equity method		882		164
Total investment — cost method		27		5

Total investment in unconsolidated affiliates		909		169

Notes receivable from unconsolidated affiliates:
Chilquinta		97		—
Corinto		—		9
GTB		14		17
TBG		8		8

Total notes receivable from unconsolidated affiliates		119		34

Total investment in and receivables from unconsolidated affiliates	$	1,028	$	203

The Company’s share of the underlying net assets of its equity investments exceeded the purchase price of those investments in the amounts of $109 million and $104 million as of December 31, 2007 and 2006, respectively. The excess is effectively being amortized into income on the straight-line basis over the estimated useful lives of such assets.

The Company’s share of the underlying net assets of its investments at fair value in POC, Chilquinta and Tecnored was less than the carrying amount of the investments. The basis differential of $170 million is reflected as equity method goodwill which is tested annually for impairment.

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Equity income (loss) from unconsolidated affiliates are as follows:


	For the Year Ended December 31,
	2007		2006
	Millions of dollars (U.S.)

Accroven	$	12	$	—
Chilquinta		1		—
GTB		5		2
PEI (see Note 1)		—		30
POC		1		—
Promigas		—		3
Promigas’ equity income from investments in unconsolidated affiliates		29		—
Subic		10		4
Transredes		18		(2	)

Total	$	76	$	37

Dividends received from unconsolidated affiliates amounted to $32 million and $9 million in 2007 and 2006, respectively.

As discussed in Note 3, the Company acquired additional ownership interests in Promigas during December 2006 and the accounts of Promigas were consolidated as of December 31, 2006. The amount reflected in the table above as equity income from unconsolidated affiliates is the amount prior to the consolidation of Promigas during 2006. The amount reflected as Promigas’ equity method investments represents the account balances and equity income of Promigas’ equity method investments only during the periods after Promigas was consolidated. PEI equity income in 2006 represents AEI’s share of four months of equity income while PEI was accounted for under the equity method (see Note 3).

Summarized financial data for investments accounted for under the equity method are as follows:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Combined Balance Sheet data
Current assets	$	1,265	$	330
Noncurrent assets		3,864		1,509
Current liabilities		930		230
Noncurrent liabilities		2,070		982


	For the Year Ended December 31,
	2007		2006
	Millions of dollars (U.S.)

Combined Income Statement data
Revenues	$	4,486	$	429
Gross profit		964		388
Net income		266		43

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


13.	INVESTMENTS IN DEBT SECURITIES

The following table reflects activity related to investments in debt:


	For the Year Ended
	December 31,
	2007			2006
	Millions of dollars (U.S.)

Investment in debt securities:
Available-for-sale debt securities:
Matured debt securities included in debt restructuring agreements:
Fair value at beginning of period	$	268		$	225
Purchases of additional securities in exchange for AEI common stock		82			—
Purchases of additional securities for cash		5			21
Sale of existing securities		—			(12	)
Conversion to equity securities		(74	)		—
Unrealized net gains affecting OCI		1			34

Fair value at end of period		282			268
Corporate debt securities:
Fair value at beginning of period		24			24
Sale of existing securities		(24	)		—
Fair value at end of period		—			24

Total available-for-sale securities, end of period		282			292

Held-to-maturity debt securities:
Purchase of participation in commercial bank loan portfolio		22			—
Promissory notes		2			2

Total held-to-maturity securities, end of period		24			2

Total	$	306		$	294

In March 2006, as part of the formation of AEIL, interests in certain debt securities, acquired by Ashmore Funds through 2006, were contributed to AEIL by certain funds, which directly or indirectly appointed Ashmore as their investment manager. As discussed in Note 1, because of the common control of the contributing entities, these debt securities were recorded at Ashmore’s carrying value, which represented fair value. The aggregate value of these securities at contribution was $250 million. Values of the debt investments in various Argentine holding companies ranged from zero to $149 million. Additional debt securities have been acquired by AEIL or contributed by other shareholders of AEI from the time of the original contributions mentioned above through December 31, 2007.

The debt securities classified as available-for-sale include matured debt securities, which are subject to debt restructurings entered into in 2005 and 2006, and corporate debt securities. Subject to certain governmental and regulatory approvals being achieved, these matured debt securities may be converted to equity in the underlying companies or their subsidiaries. In June 2007, $74 million of the matured debt securities were converted to equity in AESEBA, which holds a 90% equity interest in EDEN. No gain or loss was recognized on this conversion. The $21 million of previously unrealized gain is included in accumulated other comprehensive income.

F-60

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The corporate debt securities, which were held by subsidiaries of Promigas, were sold during 2007. The subsidiary of Promigas then purchased participation in a commercial bank loan portfolio, which matures in 2012, and accounts for them as held-to-maturity securities.

The $2 million of promissory notes, which approximates fair value due to its floating interest rate are classified as held-to-maturity and mature on September 1, 2015.

No gains or losses in the consolidated statement of operations were realized by the Company as a result of the sale of any of these available-for-sale or held-to-maturity securities. Sales of available-for-sale securities in the future could result in significant realized gains or losses, including potential gains on securities with nominal carrying amounts, although such securities are currently recorded at their fair market values.


14.	GOODWILL AND INTANGIBLES

AEI’s changes in the carrying amount of goodwill and intangibles are as follows:


	As of December 31,
	2007			2006
	Millions of dollars (U.S.)

Goodwill, January 1	$	290		$	—
Acquisitions		103			290
Transaction adjustments		(2	)		—
Other, including fair value adjustments		11			—

Goodwill, December 31	$	402		$	290

Intangibles:
Amortizable, net of accumulated amortization of $36 and $4, respectively	$	207		$	45
Nonamortizable		30			33

Total intangibles	$	237		$	78

Goodwill — AEI evaluates goodwill for impairment at the reporting unit level which, in most cases, is one level below the operating segment. Generally, each Company business constitutes a reporting unit. During 2007, reporting units were generally acquired in separate transactions. In 2006, the acquisition of PEI and Promigas resulted in the acquisitions of several business with multiple reporting units. The Company performs an annual goodwill impairment test, on September 30, and test for impairment if certain events occur that more likely than not reduce the fair value of the reporting unit below its carrying value. There was no goodwill impairment recognized in 2007.

Intangibles — The Company’s amortizable intangible assets include joint-operating agreements of Promigas, continuing customer relationships of DelSur, and the value of certain favorable long-term power purchase agreements. The power purchase agreements are held by several of AEI’s Power Generation businesses through which the amortization of these contracts may result in income or expense due to the difference between contract rates and projected market rates that increase and decrease over the contract’s life. Also included are concession rights held mainly by certain power distribution businesses. For the years ended December 31, 2007 and 2006, amortization expense for all amortizable intangible assets was $28 million and $4 million, respectively. AEI’s nonamortizable intangibles with indefinite life include $30 million of concession rights of Elektra at both December 31, 2007 and 2006. The Company also has intangible liabilities of $65 million and $17 million at December 31, 2007 and 2006, respectively, which represent unfavorable power purchase agreements held by two of the Power Generation businesses (see Note 19).

F-61

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On December 31, 2007, ENS voluntarily terminated its 20-year power purchase agreement, with such termination becoming effective as of April 1, 2008. The voluntary termination allows ENS to participate in the compensation system provided by the law (see Note 26). An intangible asset in the amount of $6 million associated with the long-term power purchase agreement was written off and included in 2007 amortization expense.

The following tables summarize the estimated amortization expense for the next five years and thereafter for intangible assets as of December 31, 2007:


	Millions of dollars (U.S.)

2008	$	25
2009		21
2010		15
2011		13
2012		12
Thereafter		121

Total	$	207


15.	OTHER ASSETS

Other assets consist of the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Long-term receivables from customers:
CDEEE	$	161	$	114
Promigas		113		76
Elektro		12		12
Furnas		11		25
Other		1		2

		298		229
Net investment in direct financing lease		174		203
Restricted cash (see Note 7)		128		139
Noncurrent assets of assets held for sale		—		87
Deferred financing costs — net of amortization		22		37
Other miscellaneous investments		10		8
Other deferred charges		94		47
Other noncurrent assets		59		38

Total	$	785	$	788

Long-Term Receivables from Customers — San Felipe’s power purchase contract with its off-taker, Corporation Dominicana de Empresas Electricias Estatales (“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 $161 million ($114 million in 2006) of accrued income and withholding taxes and associated penalties and interest and an offsetting long-term receivable from CDEEE for the reimbursement of these tax items.

F-62

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Promigas, through its subsidiaries in the local natural gas distribution sector, has unsecured long-term trade receivables with customers for installation services, with interest rates at an average of 29% 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 Superintendence of Finance, the Colombian regulatory body.

Elektro has long-term receivables that are due from customers in installments. The terms of the notes receivable are from one to three years. The notes accrue interest ranging from 0.3% to 2.7% per month and are adjusted for inflation based on IGP-M (Brazil market general price index).

In July 2005, EPE obtained final approval for an amendment to its power purchase agreement. Under the previous agreement, Furnas had been challenging the contracted volumes and was paying only a portion of the amounts due to EPE. The amended agreement established, among other revisions and clarifications, Furnas’ obligation for the past-due balances to be paid in 60 installments retroactive from July 2004. The agreement allows for the balance, denominated in Brazilian real, to accrue interest based on the Selic rate (Brazil central bank overnight lending rate) of 11.2% at December 31, 2007 (see Note 4).

Net investment in direct financing lease — EPE entered into long-term power supply agreement to sell all the electric power generated by EPE to Furnas. The power purchase agreement between EPE and Furnas was amended in July 2005 and is currently in arbitration as discussed in Note 4. As a result of the 2005 amendment, the Company determined that the power supply agreement should be accounted for as an in-substance finance lease. The lease inception date was July 1, 2005.

The components of the net investment in direct financing lease for EPE are as follows:


	December 31,
	2007			2006
	Millions of dollars (U.S.)

Total minimum lease payment to be received	$	484		$	534
Less amounts representing executory costs		(208	)		(233	)

Total minimum lease receivable		276			301
Less allowance for uncollectibles		(40	)		—
Less unearned income		(82	)		(73	)
Estimated residual value of leased property		20			1

Net investment in direct financing lease		174			229
Current portion		—			26

Long-term portion	$	174		$	203

The current portion of net investment in the EPE direct financing lease is classified in prepaids and other current assets, however, as a result of the allowance established in connection with the arbitration, there is no current balance at December 31, 2007. The entire lease investment is considered noncurrent.

F-63

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


17.	LONG TERM DEBT

Long-term debt consists of the following:


				Carrying Amount
	Variable or	Interest	Final	December 31,
	Fixed Rate	Rate (%)	Maturity	2007			2006
	Millions of dollars (U.S.), except interest rates

Debt held by Parent Company:
Senior credit facility, U.S. dollar	Variable	7.8	2014	$	979		$	976
Revolving credit facility, U.S. dollar	Variable	8.1	2012		345			—
Synthetic revolving credit facility, U.S. dollar	Variable	8.2	2012		105			—
PIK note, U.S. dollar (net of unamortized premium of less than $1 and $3, respectively)	Fixed	10.0	2018		319			547
Debt held by consolidated subsidiaries:
Cálidda, U.S. dollar	Variable	4.9 - 9.2	2015		82			—
Corinto, U.S. dollar	Fixed	6.1	2010		22			—
Cuiaba, U.S. dollar notes to other shareholders	Fixed	5.9	2015 - 2016		99			108
Delsur, U.S. dollar	Variable	6.6	2008		100			—
EDEN, U.S. dollar	Variable	7.7	2013		44			—
Elektra Noreste senior notes, U.S. dollar	Fixed	7.6	2021		99			99
Elektro, Brazilian real debentures	Variable	13.7 - 20.5	2009 - 2011		287			358
Elektro, Brazilian real note	Variable	5.0 - 12.4	2010 - 2019		127			57
ENS, U.S. dollar loans	Variable	6.0	2015		77			85
JPPC, U.S. dollar	Variable	7.8	2011		25			—
PQP, U.S. dollar notes	Variable	7.6	2015		90			57
Promigas, Colombian peso debentures	Variable	13.2 - 13.3	2011 - 2012		129			116
Promigas, Colombian peso notes	Variable	10.1 - 14.9	2008 - 2014		253			166
Promigas, U.S. dollar notes	Variable	5.7 - 7.9	2008 – 2012		26			15
Tongda, Chinese renminbi	Variable	6.6 - 11.7	2008 - 2010		9			—
Trakya, U.S. dollar notes	Fixed	7.9	2008		26			50
Trakya, U.S. dollar notes	Variable	6.5 - 10.3	2008		21			43

					3,264			2,677
Less current maturities					(749	)		(287	)

Total				$	2,515		$	2,390

Interest rates reflected in the above table are as of December 31, 2007. The three-month London Interbank Offered Rate (“LIBOR”) at December 31, 2007 was 4.7%.

Long term debt includes related party amounts of $721 million as of December 31, 2007 and $666 million as of December 31, 2006 from shareholders associated with both the Company’s senior credit facility and PIK notes. Long-term debt also includes related party amounts of $99 million as of December 31, 2007 and $108 million as of December 31, 2006 from loans provided to Cuiaba by other shareholders in the project.

F-65

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.)

2008	$	749
2009		344
2010		277
2011		383
2012		169
Thereafter		1,342

Total	$	3,264

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 26). 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 EDEN as mentioned below, were in compliance with their respective debt covenants as of December 31, 2007.

Senior Credit Facility — As of March 31, 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 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. The refinanced term loan amortizes 30% of the principal over seven years in equal quarterly principal payments, and the remaining outstanding principal will 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, which is 250 basis points higher for the synthetic facility. 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 purpose of this credit facility was to refinance the existing senior and bridge loan on better terms and pricing and to provide for a revolver facility that will provide the Company with additional liquidity. 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 and nonfinancial covenants, which restrict the activities of the Company. Nonfinancial covenants include providing annual audited consolidated financial statements. 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, 2007. The senior credit facility does not require reserves for debt service.

Payment in Kind (PIK) Notes — On May 24, 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 $33 million was

F-66

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

recorded. The cash proceeds from the original PIK notes issued were used to pay a portion of the purchase price in the PEI acquisition and for general corporate purposes. 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 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 note principal, interest, and any applicable redemption premium; (2) an AEI failure to make payments or perform other obligations with respect to other AEI 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 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 AEI’s existing senior and bridge loan 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 determined by reference to May 24, 2007, as follows: (1) year 1: 100%, (2) year 2: 102%, (3) year 3: 104%, (4) year 4: 106%, and (5) year 5 and thereafter: 108%.

Cálidda — The $35 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 with a mortgage on Cálidda’s gas transportation 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 transportation concession. This mortgage and trust contract established a first and preferred mortgage on Cálidda’s gas transportation concession, in favor of the lenders. The mortgage shall be maintained until the debt is fully repaid.

Cálidda also has an additional subordinated loan for $47 million. Interest accrues at LIBOR plus 0.30% and is payable quarterly. In March 2008, the principal maturity was extended from 2008 to 2009 and the interest rate was increased to LIBOR plus 0.65%. The loan is collateralized with of a $48 million letter of credit with a maximum facility of $47 million. AEI Peru Holdings, Ltd posted $29 million as collateral for the letter of credit.

Cuiaba — The debt consists of a group of promissory notes with a single counterparty bearing weighted average fixed interest rates of 5.9% and is unsecured. Principal and interest payments are due annually, with final maturities from 2015 through 2016. The notes contain certain prepayment and rollover provisions.

DelSur — In May 2007, AEI borrowed $100 million from external lenders in order to fund a portion of the acquisition of an 86.4% equity interest in DelSur. The loan matures and full principal is due on May 22, 2008. Interest is payable quarterly. Interest rates are variable, so that rates are, at the election of AEI, either LIBOR or a base rate, as defined by the lending agreement, plus a margin of 1.25% to 2.25% depending of the rate election choices provided by the lending agreement. The loan is guaranteed by an irrevocable guarantee from DelSur for the timely payment of all obligations under the loan. All shares of DelSur held, equal to 86.4% equity ownership of DelSur, are pledged as collateral for the loan.

EDEN — The financing consists of an unsecured loan agreement maturing in 2013. Principal and interest are payable on a quarterly basis. Interest are LIBOR plus 2.50% for the first three years, LIBOR plus 2.75% for the next two years and LIBOR plus 3.75% for the remaining four years.

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:

F-67

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

change in control, change in the operator and cross default. The transfer of shares from the previous owner to the Company was completed on June 26, 2007, constituting a breach of the existing credit agreement for this debt causing EDEN to be in default. The designated administrative agent, upon receipt of instructions from the lenders, may declare the principal, accrued interest, and all other obligations to be due and payable. EDEN has not been notified of the execution of such actions by the lenders. The loan balance of $44 million is classified as current at December 31, 2007.

Elektra — Elektra has notes payable under a senior debt agreement totaling $100 million, which is recorded at $99 million, net of $1 million unamortized discount at December 31, 2007. 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. The notes also require reserves for insurance and debt service.

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 in 2009, 2010, and 2011. The debentures accrue interest at 11.8% per year and are indexed to the Brazil market general price index (IGP-M) for the first series, and are indexed to the Brazil interbank interest rate (CDI) plus 1.65% 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 $5 million and $9 million at December 31, 2007 and 2006, respectively. A balance of 508 million Brazilian reais (U.S.$287 million) remains outstanding for these public debentures as of December 31, 2007, as Elektro fully executed the third series call option in September 2007 and executed a tender offer in December 2007 for the second series, which resulted in a repurchase of 288 million Brazilian reais (U.S.$156 million) during 2007.

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 — 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 2019 and accrue interest based on the Global Reversion Reserve fund rate (“RGR”) plus 5% per year or on the Taxa de Juros de Longo Prazo (“TJLP”) (Brazil long-term interest rate) plus spreads from 0.94% to 6%. These financings are secured either by pledge of funds or by bank letters of guarantee. The total amount of funds classified as restricted cash related to this financing was $15 million and $13 million at December 31, 2007 and 2006, respectively.

A summary of the relevant interest rates and indices for Brazil is as follows:


	December 31, 2007

CDI		11.8	%
IGP-M		7.8	%
RGR		0.0	%
TJLP		6.4	%

ENS — The financing consists of a commercial bank syndicated loan bearing a floating interest rate based on LIBOR plus a variable margin between 1.25% and 1.68%. ENS entered into an interest rate swap agreement financed at a fixed rate of interest of 6.28% on $114 million of the original amount. Principal payments are due semiannually and interest payments are due monthly, with final maturity in 2015. The loan is secured by all the noncurrent assets of ENS, which had a net book value as of December 31, 2007 of $28 million. The loan requires reserves for debt service and maintenance.

PQP — During 2007, PQP refinanced its credit facilities. The financing for PQP includes notes payable and a revolving line of credit with a commercial bank. The notes have variable interest rates of LIBOR plus

F-68

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2.75%, 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, 1.70% for letters of credit issuance, and LIBOR plus 2.00% 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, which had a net book value as of December 31, 2007 of $112 million, including major power purchase and fuel supply contracts and PQP’s power barges.

Promigas — Promigas’ long-term debt financing consists principally of Colombian peso debentures and Colombian peso notes with local commercial banks.

During 2001 and 2002, Promigas issued public debentures in the amount of 200 billion Colombian pesos. The debentures accrue interest at the Colombian Consumer Price Index (CCPI) plus 7.5%. Interest is payable quarterly. The proceeds of the debentures were used to repay outstanding liabilities and finance the company’s investment plan in 2001 and 2002. The 200 billion Colombian peso ($99 million) debentures remain outstanding as of December 31, 2007, with 50% maturing each in 2011 and 2012.

During 2003 and 2004, a subsidiary of Promigas issued public debentures in the amount of approximately 60 billion Colombian pesos. The debentures accrue interest at CCPI plus 7.4%. Interest is payable quarterly. The proceeds of the debentures were used to repay outstanding liabilities. Debentures outstanding as of December 31, 2007 are 60 billion Colombian pesos ($30 million) and mature in 2011.

The peso notes bear interest at rates ranging from 9.3% to 12.6%. The maturities of these notes vary from one to seven 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 between 2008 and 2012, interest payments due either quarterly or semiannually, and no collateral requirements.

Trakya — The financing consists of Export-Import Bank of the United States, OPIC, and commercial bank loans. These loans bear various interest rates, including fixed rates of 7.95% on $25 million, interest rates based on a certificate interest rate plus 3.2% on $9 million, and interest rates based on six-month LIBOR on $12 million. Trakya was required to enter into interest rate swap agreements on the LIBOR-based loan for a fixed rate of 7.9%. Principal payments are due semiannually, with final maturity in 2008. Interest payments are due either quarterly or semiannually. All assets of Trakya, which had a net book value as of December 31, 2007 of $390 million, are pledged as collateral under its loan facilities. The loan facilities also require reserves for debt service, debt reserves and insurance deductible shortfall reserves. The total amount of funds classified as restricted cash related to this financing was $51 million at December 31, 2007.

Others — JPPC and Corinto have outstanding debt instruments which require reserves for debt service, which amounted to $11 million and $7 million, respectively, at December 31, 2007. JPPC is also required to maintain insurance coverage. Tongda debt instruments do not require reserves. See Note 26 for further information regarding Corinto’s debt instruments.

Capital Lease Obligations — Summarized below are the future obligations relating to certain sale and leaseback transactions (capital leases) for certain pipelines and related equipment in which Promigas is the lessee. The related capital leases are recorded as obligations in the amount of $37 million ($38 million in 2006), with rates from 12.3% to 12.5%. At December 31, 2007 and 2006, the gross assets under capital leases were $31 million and $61 million and accumulated amortization amounted to $5 million and $14 million, respectively. The leases are all nonrecourse to AEI.

F-69

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. The long term amounts are included in other liabilities on the balance sheet (see Note 19):


	Millions of
	dollars (U.S.)

2008	$	11
2009		18
2010		8
2011		4
2012		2
Thereafter		8

Future minimum lease payments		51
Less amount representing interest		14

Total	$	37


18.	INCOME TAXES

Income Tax Provision — The provision for income taxes on income from continuing operations are comprised of the following:


	For the Year Ended
	December 31,
	2007		2006
	Millions of dollars (U.S.)

Current:
Cayman Islands	$	—	$	—
Foreign		106		64

Total current		106		64

Deferred:
Cayman Islands		—		—
Foreign		87		20

Total deferred		87		20

Provision for income taxes	$	193	$	84

F-70

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Effective Tax Rate Reconciliation — A reconciliation of the Company’s income tax rate to its effective tax rate as a percentage of income before minority interest and taxes, is as follows:


	December 31,
	2007			2006

Statutory tax rate — Cayman Island		0.0	%		0.0	%
Foreign tax rate differential		42.0	%		64.7	%
Tax credits		0.0	%		(1.1	)%
Change in valuation allowance		14.0	%		31.0	%

Effective tax rate		56.0	%		97.6	%

The effective tax rate reconciliation for the “Statutory Tax Rate — Cayman Islands” takes into account net losses of $218 million in 2007 and $88 million in 2006 which do not generate a tax benefit by virtue of the 0% statutory tax rate in the Cayman Islands.

As described in Note 2, the Company adopted the provisions of FIN 48 effective on January 1, 2007. As a result of the adoption of FIN 48 and recognition of the cumulative effect of adoption of a new accounting principle, the Company recorded a $2 million increase in the liability for unrecognized income tax benefits, with an offsetting amount to intangible assets of $1 million and retained earnings of less than $1 million.

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 following is a tabular reconciliation of the total amounts of unrecognized tax benefits for the year:


	For the Year Ended
	December 31, 2007
	Millions of dollars (U.S.)

Unrecognized tax benefit, January 1, 2007	$	51
Gross increases, tax positions in prior period		5
Gross decreases, tax positions in prior period		(12	)
Gross increases, tax positions in current period		16
Settlements		(1	)
Lapse of statute of limitations		(9	)

Unrecognized tax benefit, December 31, 2007	$	50

Included in the balance of unrecognized tax benefits at December 31, 2007, are $44 million of tax benefits that, if recognized, would affect the effective tax rate. Also included in the balance of unrecognized tax benefits at December 31, 2007, are $4 million of tax benefits that, if recognized, would result in a decrease to goodwill recorded in purchase business combinations, and $2 million of tax benefits that, if recognized, would result in adjustments to other tax accounts, primarily deferred taxes.

The Company recognizes interest accrued related to unrecognized tax benefits and penalties as income tax expense. Related to the unrecognized tax benefits noted above, the Company accrued penalties of $12 million and interest of $5 million during 2007 and in total, as of December 31, 2007, has recognized a liability for penalties of $46 million and interest of $29 million.

The Company does not believe it is reasonably possible the total amount of the unrecognized tax benefits will significantly change within the next 12 months.

F-71

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Brazil		2002-present
Colombia		2005-present
Dominican Republic		1998-June 2001 and 2003-present
Philippines		2004-present
Poland		2002-present
Turkey		2002-present

Additionally, 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. The Company believes that its tax positions comply with applicable tax law and intends to defend its positions through appropriate administrative and judicial processes. The Company believes it has adequately provided for any probably outcomes related to these matters.

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,
	2007			2006
	Millions of dollars (U.S.)

Deferred tax assets:
Goodwill	$	71		$	112
Accrued expenses		244			155
Operating losses and tax credit carryforwards		236			208
Reserves		39			28
Valuation allowance		(168	)		(103	)

Total deferred tax assets		422			400
Deferred tax liabilities:
Fixed assets	$	(201	)	$	(122	)
Foreign currency and other		(25	)		(53	)

Total deferred tax liabilities		(226	)		(175	)

Total deferred tax assets (liabilities)	$	196		$	225

The Company has net operating loss carryforwards in several jurisdictions that expire between 2008 and 2016. The tax effected amount of these net operating loss carryforwards was $48 million at December 31, 2007 and $45 million at December 31, 2006. 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 $164 million at December 31, 2007 and $161 million at December 31, 2006.

F-72

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company also has tax credits in jurisdictions in which the credit will never expire. The amounts of these credits were $1 million at December 31, 2007 and $2 million at December 31, 2006. 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.)

2008	$	1	$	—
2009		5		—
2010		1		—
2011		19		—
2012		22		2
Thereafter		—		21
Unlimited		164		1

Total	$	212	$	24

The Company records a valuation allowance when it is more likely than not that some portion or all of deferred tax asset 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 allowances was $168 million at December 31, 2007 and $103 million at December 31, 2006.

The Company is subject to changes in tax laws, treaties, and regulations in and between the countries in which it operates. A material change in these tax laws, treaties, or regulations could result in a higher or lower effective tax rate on the Company’s worldwide earnings.


19.	OTHER LIABILITIES

Other liabilities consist of the following:


	December 31,
	2007		2006
	Millions of dollars (U.S.)

Deferred revenue	$	414	$	294
Accrued taxes payable — San Felipe (see Note 15)		59		114
Accrued interest		22		23
Accrued tax and legal contingencies		93		79
Capital lease obligations		30		27
Liabilities of assets held for sale — BLM (see Note 3)		—		37
Pension and other postretirement benefits (see Note 25)		10		10
Accrual for tax uncertainties		125		—
Unfavorable power purchase agreements		65		17
Other		63		36

Total	$	881	$	637

The majority of the accrued tax and legal contingencies included in other liabilities relate to tax and legal claims accrued by Elektro (see Note 26).

F-73

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As part of the accounting for AEIL’s purchase of PEI and AEI’s purchase of JPPC, the fair value of the power purchase agreements for San Felipe and JPPC were determined to be below market value. Fair value adjustments of $17 million, $37 million and $6 million were recorded on the financial statements of San Felipe and JPPC as part of the purchase accounting adjustments for San Felipe in 2006, JPPC in 2007 and the additional interests of San Felipe purchased in 2007, respectively (see Note 3).


20.	LEASE COMMITMENTS

The Company determined that the power purchase agreements entered into by Trakya, ENS, San Felipe, JPPC and certain arrangements of Promigas subsidiaries are operating leases. As a result of the termination of ENS’ power purchase agreement this agreement will no longer be considered an operating lease after December 31, 2007 (see Note 26).

Future minimum lease payments associated with all leases to be received for the next five years and in total thereafter are as follows:


	Direct
	Financing		Operating
	Millions of dollars (U.S.)

2008	$	—	$	137
2009		12		150
2010		24		140
2011		24		110
2012		23		117
Thereafter		91		817

Total	$	174	$	1,471


21.	FINANCIAL INSTRUMENTS AND DERIVATIVES

Most of the Company’s derivative instruments are designated and qualify as hedges. Net unrealized losses of $25 million related to the current year change in the fair value are included in accumulated other comprehensive income. Over the next year, none of the accumulated other comprehensive losses related to derivative instruments as of December 31, 2007 are expected to be recognized in income from continuing operations.

Excluding forecasted transactions related to the payment of variable interest on existing financial instruments described above, the maximum length of time over which AEI is hedging its exposure to variability in future cash flows for forecasted transactions is less than 12 months.

Interest Rate and Currency Swaps — There is exposure to risks resulting from changes in interest rates as a result of the issuance of variable-rate and fixed-rate debt, as well as interest rate swap and option agreements both at the parent and operating company level. As of December 31, 2007, the floating rate debt of the Parent Company consisted primarily of a $1 billion term loan facility that has an interest rate based on LIBOR (see Note 17). The Company has entered into three to five year interest rate swap agreements, designated as cash flow hedges, to eliminate the variability of cash flows in the interest payments on up to $600 million of the $1 billion. Changes in the cash flows of the interest rate swaps are expected to exactly offset the changes in cash flows attributable to fluctuations in LIBOR on the loan.

Trakya has interest rate swap agreements on its LIBOR-based BLB/Hermes and BLB/Siemens senior loans designated as cash flow hedges, which eliminate the variability associated with these loans. The swap agreements mature at the same time as the debt. PQP entered into an interest rate swap agreement which established fixed interest rates on a portion of its LIBOR-based Citibank loan facility. An interest rate swap

F-74

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

agreement was utilized by ENS to hedge the entire balance of its floating interest rate exposure on a commercial bank syndicated loan which was terminated during 2007. ENS recognized an after-tax gain of $1 million in 2007 related to this agreement.

Net Investment Hedges — The Company uses hedge transactions, designated as fair value hedges, to protect its net investment in Elektro against adverse changes in the exchange rate between the U.S. dollar and the Brazilian real. Since the derivative’s underlying exchange rate is expected to move in tandem with the exchange rate between the functional currency (Brazilian real) of the hedged investment and AEI’s functional currency (U.S. dollar), no material ineffectiveness is anticipated. The Company recorded $1 million of losses as currency translation adjustments related to these hedges in both 2007 and 2006.

The Company also entered into certain derivative contracts which were not designated as hedging instruments. These contracts were entered to economically hedge foreign exchange risk associated with Brazilian real-based dividends received from Elektro on a recurring basis. The Company recognized a loss of $14 million in 2007 in other income (expense), net related to these derivatives (see Note 6).

The Company also entered into a derivative transaction in association with its purchase of additional shares of Promigas in December 2006 (see Note 3). The transaction did not qualify for hedge accounting and thus recognized a gain of $2 million in other income (expense), net in 2006.

Fair Value of 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 interest rate swaps and foreign currency forwards and swaps 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.

The following table summarizes the estimated fair values of the Company’s long-term investments, debt, and derivative financial instruments:


	December 31,
	2007				2006
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	Millions of dollars (U.S.)

Assets:
Notes receivable from unconsolidated subsidiaries	$	122	$	120	$	34	$	31
Investment in debt securities, including available-for-sale securities		306		306		294		294
Liabilities:
Interest rate swaps		25		25		5		5
Foreign currency forwards and swaps		2		2		1		1
Long-term debt, including current maturities		3,264		3,292		2,677		2,691

F-75

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. One individual customer accounted for 14% of the accounts receivable balance as of December 31, 2007. As of December 31, 2006, there were two individual significant customers who accounting for 13% and 11%, respectively, of total accounts receivable.


22.	SHAREHOLDERS’ EQUITY AND EARNINGS PER SHARE

Basic and diluted earnings per share were as follows:


	For the Year Ended December 31,
	2007		2006

Basic earnings per share:
Income (loss) from continuing operations (millions of U.S. dollars)	$	87	$	(18	)
Average number of common shares outstanding (millions)		209		202
Income (loss) from continuing operations per share	$	0.42	$	(0.09	)

The Company incurred a net loss from continuing operations for the year ended December 31, 2006 and has therefore excluded the 1,920,997 of non-vested restricted stock from the computation of the 2006 diluted income (loss) per share as the effect would be anti-dilutive.

In December 2006, February 2007 and September 2007, the Company issued restricted stock grants to directors and employees which are included in the calculation of basic earnings per share. During February and September 2007, the Company also issued 1,656,405 stock options to employees. These options are excluded from the calculation of diluted earnings per share because the exercise price of those options exceeded the average fair value of the Company’s stock during the related period.

Accumulated other comprehensive income consists of the following:


	December 31,
	2007			2006
	Millions of dollars (U.S.)

Foreign currency translation	$	212		$	2
Unrealized derivative losses		(25	)		—
Minimum pension liability		22			6
Available-for-sale securities		6			9

Total	$	215		$	17


23.	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 is for one year and is renewable for successive one-year periods. 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 paid under the MSA during the term is approximately $5 million. The Company paid $3 million and less than $1 million during 2007 and 2006, respectively, for these services.

F-76

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 — shareholders — The Company recorded interest expense to shareholders of $63 million and $20 million during 2007 and 2006, respectively, related to debt.

Interest income from unconsolidated subsidiaries — Stage 1 of AEIL’s acquisition of PEI included a $1 billion loan from AEIL to PEI. Since PEI was an equity investment of AEIL until the closing of Stage 2 of the acquisition, $26 million of interest income was earned by AEIL on the loan to PEI and was not eliminated in the consolidated statement of operations for the year ended December 31, 2006. The Company also recognized interest income from development and shareholder loans to TBG and GTB in the amount of $2 million during both 2007 and 2006.

One of the Company’s subsidiaries, PQP, had a long-term receivable with one of its minority shareholders totaling $4 million at December 31, 2006. This long-term receivable was settled as part of AEI’s acquisition of an additional interest in PQP in 2007.


24.	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.

2007 Equity Incentive Plan — AEI adopted a Board of Directors-approved Incentive Plan for a 10-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 shares totaling 15,660,340 to be awarded over the 10-year period. Awards can be made in the form of Appreciation Rights or Stock Options, or as Restricted Shares. The plan also allows for the issuance of the same types of 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 price, quantity, and allocation of such awards. In February 2007, the Compensation Committee of the Board of Directors approved grants with a graduated 48-month vesting period. A grant was approved for 3,367,795 shares, 65% of which was to be subject to options, and the remainder of which were to be restricted shares. Grants of options to purchase 767,880 shares and 200,585 restricted shares at $11.18 per share were made pursuant to this Compensation Committee approval. The Compensation Committee also approved a grant in September 2007 with a graduated 48-month vesting period. The total grant approved was for 1,219,209 shares, 65% of which were subject to options, and the remainder in restricted shares. Grants of options to purchase 919,957 shares and 299,252 restricted shares at $13.60 per share were made.

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 2007, which resulted in compensation expense during 2007 for these awards that was negligible.

F-77

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The amounts of restricted stock, share units and stock options related to the 2007 Incentive Plan are disclosed below:


	In thousands

Shares/Options authorized to be granted under plan		15,660
Shares/Options granted during 2007 (net of termination of 38)		(2,150	)

Shares/Options available for grant at December 31, 2007		13,510

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 as follows:


Weighted Average Fair Value of Grants	$	4.61
Expected Volatility		25.00	%
Risk-Free Interest Rate		4.00	%
Dividend Yield		0.00	%
Expected Life		7 Years

Expected volatility is based upon the weekly stock price changes over a three 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 vest 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 $1 million for 2007.

Summarized restricted stock award activity under the 2007 Equity Incentive Plan for the year ended December 31, 2007 is as follows:


				Weighted-
				Average		Aggregate
Restricted Stock	Shares			Grant Price		Intrinsic Value
	(Thousands)					(Millions of
						dollars (U.S.))

Granted		500		$	12.63	$	6
Forfeited		—			—		—
Exercised		(6	)		11.18		—
Vested		—			—		—

Nonvested, December 31, 2007		494		$	12.65	$	6

As of December 31, 2007, there was $5 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 3.5 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 $1 million for 2007.

F-78

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summarized option award activity under the 2007 Equity Incentive Plan for the year ended December 31, 2007 is as follows:


				Weighted-		Weighted-
				Average		Average
				Fair Value of		Exercise Price		Aggregate
Stock Options	Options			Grants		of Grants		Intrinsic Value
	(Thousands)							(Millions of
								dollars (U.S.))

Granted		1,688		$	4.61	$	12.50	$	8
Forfeited		—			—		—		—
Exercised		(31	)		4.11		11.18		—
Vested		—			—		—		—

Nonvested, December 31, 2007		1,657		$	4.62	$	12.52	$	8

As of December 31, 2007, there was $6 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 3.5 years.

As a Cayman Islands entity, the Company 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. The Stock Incentive Plan allowed for grants in the form of, or in any combination of stock options, stock appreciation rights, restricted stock awards, share units, and cash awards. The Compensation Committee of PEI’s board of directors administered the Stock Incentive Plan.

In 2006, Enron and certain of its subsidiaries signed a Share Purchase Agreement dated May 23, 2006 (and subsequently amended and restated by the Share Purchase Agreement dated June 9, 2006) with AEIL for the sale of 100% of the outstanding equity of PEI in a two-staged transaction. The Stock Incentive Plan of PEI remained in place after the change in control of the Company.

The “enterprise value” based model is a fair value based method of accounting for stock-based compensation that was used by PEI prior to January 1, 2006, and continued to be used to approximate the fair value of the stock options until such time as a third-party valuation of PEI was completed as of October 6, 2006 as a result of the change in control, as described in detail below, which established a value of $6.41 per unit for PEI’s units effective May 1, 2006. Effective with the completion of the amalgamation of PEI and AEIL the fair value of all options in total remained the same for all continuing stock options outstanding, but the number of shares decreased proportionately to reflect the new $7.99 per unit value based on a third-party valuation of the amalgamated company.

Awards issued to non-employee directors are fully vested at the grant date in accordance with the grant agreement. There were several grants to non-employee directors in 2006, which resulted in $1 million in compensation expense for these awards being recorded for the year ended 2006.

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 September 30, 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. None of the performance-based units vested unless the minimum performance goals set out in the grant agreements were attained and the maximum number of units was established. The performance goals under the performance-based grants were changed as a result of the acquisition of PEI, and the vesting

F-79

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

schedules under these grants were extended through September 30, 2007. The estimated market price of each performance-and time-based unit on the grant date was $5 per unit. Amounts of units vested and exercised are found in the tables below.

PEI also granted share units in 2005 at an estimated market value of $5.40 per unit, which were to vest over a 36-month period ending December 31, 2007. However, as a result of the change of control, these awards were canceled and converted into awards under PEI’s Sales Incentive Plan, discussed below.

On May 22, 2006, an acknowledgement was signed by the Stock Incentive Plan participants and Enron to modify the Stock Incentive Plan that eliminated the discretion of the Compensation Committee to grant dividend equivalent units and instead provided that dividend equivalent rights would be granted with respect to the shares of common stock underlying the units (the “Acknowledgement”). This Acknowledgement also provided that dividend equivalent rights could be paid only in the form of additional units (and not in cash as previously provided). The terms of the Acknowledgement resulted in a modification of the Stock Incentive Plan, because PEI issued a new instrument of equal or greater value than the previous instrument that existed. Thus, the awards granted under the Stock Incentive Plan were also modified and revalued as of May 22, 2006, the grant date of the dividend equivalent rights.

The dividend equivalent rights had the same vesting rights as the time- and performance-based share units that they were derived from (except for participants who opted to leave the Company in November 2006) and were classified as equity as at December 31, 2006. Those dividend equivalent rights are included in the time- and performance-based shares activity tables below.

The closing of Stage 2 of the acquisition of PEI by AEI on September 7, 2006 constituted a change of control under the Stock Incentive Plan, as a result of which the end of the performance period was changed to September 2006 and the vesting period of all of the performance-based awards made under the Stock Incentive Plan was extended by an additional nine months.

On October 6, 2006, participants under the Stock Incentive Plan were given two options as follows:


	•	Option 1 — Remain with PEI and retain their units, with the same vesting and payment schedules as laid out in the Stock Incentive Plan

	•	Option 2 — Leave PEI and sell their units to PEI at a price based on a third-party valuation of PEI, which established a value of $6.41 per unit for PEI’s units effective May 1, 2006

Awards for participants who remained with PEI continued to be accounted for as equity awards, although any equity awards that vested subsequent to the May 1, 2006 share value revision would involve monthly compensation expense to be calculated on those vested awards at the revised value of $6.41 per share. Therefore, only participants who selected Option 1 were classified as equity. Participants who selected Option 2 were deemed to have received a new instrument, since they received additional value without having to provide services. The incremental cost of Option 2 was considered to be a modification of an equity award to a liability award followed by a subsequent settlement and payment in November 2006.

Compensation expense recognized for the Stock Incentive Plan was $10 million and $23 million for 2007 and 2006, respectively. 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. Amounts for the 2005 grants, which settled in cash, were included in other liabilities at December 31, 2006, with the balance paid out during 2007.

F-80

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summarized time-based share unit award and performance-based share unit award activity, including the effects of the amalgamation of PEI and AEI in December 2006, is as follows:


				Weighted-
				Average		Aggregate
	Units/Shares			Grant Price		Intrinsic Value
	(Thousands)					(Millions of
						dollars (U.S.))

Time-Based Restricted Units/Shares:
Nonvested restricted units, December 31, 2006		641		$	7.99	$	5
Units exercised		(55	)		7.99		—
Units forfeited		—			—		—

Total restricted shares — December 31, 2007		586	(i)	$	7.99	$	5

Performance-Based Restricted Units/Shares:
Nonvested restricted units, December 31, 2006		2,307		$	7.99	$	18
Units exercised		(128	)		7.99		(1	)
Units forfeited		—			—		—

Total restricted shares, December 31, 2007		2,179	(i)	$	7.99	$	17


(i)		All of the shares listed above were vested and treated as outstanding.

As a Cayman Islands entity, the Company does not realize any tax benefits from the granting or exercising of these restricted shares.

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”). The excess of Enron’s realized value over defined threshold amounts, and the calendar year in which a change of control became effective, determined the amount to be distributed as Cash Awards (“Cash Award Fund”). 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.

In 2006, Enron signed a Share Purchase Agreement dated May 23, 2006 (and subsequently amended and restated by the Share Purchase Agreement dated June 9, 2006), with AEIL and PEI for the sale of 100% of the outstanding equity of PEI in a two-staged transaction. The closing of Stage 2 of this transaction triggered a change in control under the Sales Incentive Plan. The Cash Award Fund available for distribution under the Sales Incentive Plan in connection with the transaction was $84 million. Compensation expense recognized for the Sales Incentive Plan was $17 million and $21 million for 2007 and 2006, respectively.

Fifty percent of the Cash Award Fund liability of $84 million, or approximately $42 million, vested at the closing of the second stage of the transaction on September 7, 2006, and was recorded as a liability acquired in the business combination effected by the change in control described previously. The remaining 50% vested 12 months after the change in control, for participants employed continuously by the Company through such date. The Company recorded this remaining 50% ratably over the 12-month period following the change in control.

On October 6, 2006, participants under the Sales Incentive Plan were given 3 options, as follows:


	•	Option 1 — Remain with PEI, and vest and receive payment of 50% of their calculated Sales Incentive Plan awards, with the same vesting and payment schedules as presently laid out in the plan for the second 50% due upon the one-year anniversary of the change in control

F-81

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	Option 2 — Remain with PEI, vest and receive payment of 50% of their calculated Sales Incentive Plan awards, and reinvest the second Sales Incentive Plan payment in amalgamated company restricted stock units

	•	Option 3 — Cash out and leave PEI, receiving payment of 50% of their calculated Sales Incentive Plan awards. Participants who chose to leave the Company also received payment of the remaining 50% due under the Sales Incentive Plan less a 16% discount on the remaining 50% payment due.

Summarized restricted stock issued in lieu of the second Sales Incentive Plan payment, as described in Option 2 above, is shown below for the year ended December 31, 2007. These restricted stock shares vested 50% on the first anniversary of the September 7, 2006, change in control, and the remaining 50% vested on the second anniversary of the September 7, 2006, change in control. Any restricted stock shares not vested upon the employee’s departure from the Company were forfeited.


				Weighted-
				Average		Aggregate
Restricted Stock Issued in Lieu of Second Sales Incentive Plan Payment	Shares			Grant Price		Intrinsic Value
	(Thousands)					(Millions of
						dollars (U.S.))

Nonvested, December 31, 2006		640		$	7.99	$	5
Exercised		(8	)		7.99		0
Forfeited		—			—		—
Vested		(312	)		7.99		(2	)

Nonvested, December 31, 2007		320		$	7.99	$	3

As of December 31, 2007, there was $2 million of total unrecognized compensation cost related to nonvested restricted stock issued in lieu of the second Sales Incentive Plan payment. This cost is expected to be substantially recognized in 2008.


25.	PENSION AND OTHER POSTRETIREMENT BENEFITS

On December 31, 2006, SFAS No. 158 was adopted, which requires the Company to recognize the funded status of its pension and other postretirement benefit plans in its December 31, 2006 consolidated balance sheet, with corresponding adjustments to accumulated other comprehensive income. The adoption did not have a material effect on any individual line items on the Company’s consolidated balance sheet as of December 31, 2006. The Company uses a year-end measurement date for its plans.

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 its expatriate employees and 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 for each of 2007 and 2006. 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 $1 million in 2007 and $2 million in 2006.

In certain countries, including Panama, El Salvador and Argentina, local labor laws 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. In Argentina, the Company is not required to deposit funds into a trust, but does accrue the severance benefit obligation in its records. The Company accrues these benefits based on historical

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

experience and third party evaluations. Accrued severance indemnities included in other liabilities as of December 31, 2007 and 2006 are $8 million and $1 million, respectively.

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.

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,
	2007		2006
	Millions of dollars (U.S.)

Projected benefit obligation	$	307	$	229
Accumulated benefit obligation		285		214
Fair value of plan assets		325		222
Prepaid (accrued) pension liability current		18		(7	)

Prior to the adoption of SFAS No. 158, Elektro did not recognize a material additional minimum liability for pension plans with an accumulated benefit obligation in excess of plan assets. Subsequently, Elektro recorded other comprehensive income of $16 million and $6 million, net of tax of $8 million and $3 million, as of December 31, 2007 and 2006, respectively.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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,
	2007			2006
	Millions in dollars (U.S.)

Change in projected benefit obligation:
Benefit obligation, beginning of period	$	229		$	—
Service cost		3			1
Interest cost		31			6
Actuarial gains and losses		9			(2	)
Benefits paid		(12	)		(2	)
Effect of foreign exchange rate change		47			—
Acquisition of PEI		—			226

Benefit obligation — end of period	$	307		$	229

Change in plan assets:
Fair value of plan assets, beginning of period	$	222		$	—
Actual return on plan assets		65			14
Contributions by employer		2			1
Contributions by plan participants		2			—
Benefits paid		(12	)		(2	)
Effect of foreign exchange rate change		46			—
Acquisition of PEI		—			209

Fair value of plan assets — end of period	$	325		$	222

Funded status at end of year	$	18		$	(7	)

Amounts recognized on the balance sheet — prepaid (accrued) pension liability	$	18		$	(7	)

Net amount recognized at end of year	$	18		$	(7	)

The components of net periodic benefit cost are as follows:


	For the Year Ended December 31,
	2007			2006
	Millions of dollars (U.S.)

Service cost	$	3		$	1
Interest cost		31			6
Expected employee contribution		(2	)		—
Expected return on plan assets for the period		(33	)		(7	)

Total net periodic pension costs	$	(1	)		—

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Projected benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The actuarial assumptions as of December 31, 2007 and 2006, are as follows:


	2007						2006
				Periodic						Periodic
	Benefit			Pension			Benefit			Pension
	Obligation			Cost			Obligation			Cost

Weighted-average of discount rates		10.24	%		10.24	%		11.30	%		11.30	%
Weighted-average rates of compensation increase		7.12	%		7.12	%		8.15	%		8.15	%
Weighted-average expected long-term rate of return on plan assets					11.28	%					12.35	%

The basis used to determine the expected long term rate of return on assets were:(i) forward rates for long term government bonds and (ii) expected return on each asset category, as determined by the pension fund managers through historical experience and current market conditions. As the return rates on Brazilian government bonds are subject to volatility, a reduction margin of 0.31% was applied to the estimated forward rates for Brazilian government bonds.

The asset allocation of the plan assets is as follows:


	December 31,
	2007			2006

Fixed income		70.7	%		70.6	%
Equities		21.7	%		20.7	%
Real estate		4.0	%		5.1	%
Loans to participants		3.6	%		3.6	%

Total		100.0	%		100.0	%

The primary objective of the plan is to provide eligible employees with scheduled payments. The Company follows consistent standards for preservation and liquidity with the goal of earning the highest possible return while minimizing risk. The target asset allocation represents a long-term perspective and plan assets are rebalanced as needed.

The following table summarizes the scheduled cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign:


	Millions of
	dollars (U.S.)

Expected employer contribution in 2008	$	2
Expected benefit payments:
2008		12
2009		13
2010		13
2011		14
2012		15
2013 - 2017		63

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


26.	COMMITMENTS AND CONTINGENCIES

The Company’s future minimum commitments as of December 31, 2007, are as follows:


	2008		2009		2010		2011		2012		Thereafter		Other		Total
	Millions of dollars (U.S.)

Power commitments(1)	$	873	$	919	$	984	$	1,010	$	999	$	9,044	$	—	$	13,829
Fuel commitments(2)		332		272		260		230		247		1,452		—		2,793
Equipment commitments(3)		12		18		3		3		17		89		—		142
Transportation commitments(4)		82		84		86		88		78		296		—		714
FIN 48 obligations, including interest and penalties		—		—		—		—		—		—		125		125
Other commitments		58		3		2		2		2		—		—		68

Total	$	1,357	$	1,296	$	1,335	$	1,333	$	1,343	$	10,882	$	—	$	17,671


(1)		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, 2007 and 2006 totaled $917 million and $232 million.

(2)		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, 2007 and 2006 totaled $425 million and $107 million.

(3)		Represents commitments of various duration for parts and maintenance services provided by third parties, which are expensed during the year of service.

(4)		Represents a commitment to purchase gas transportation services from an unconsolidated affiliate and third parties.

The estimated FIN 48 tax liabilities will be settled as a result of expiring statutes, audit activity or financial decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or on expiration of statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the FIN 48 tax liability would not result in a cash payment.

Letters of Credit — In the normal course of business, AEI and certain of its 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 subsidiaries’ intended business purpose. As of December 31, 2007, AEI and certain of its subsidiaries had entered into letters of credit, bank guarantees, and performance bonds that had outstanding balances of $44 million and $226 million in unused letter of credit availability, of which $80 million of the total facility balances were fully cash collateralized. Additionally, as of December 31, 2007, lines of credit of $666 million were outstanding, with an additional $298 million available for future disbursements.

Under a sponsor undertaking agreement, AEI is obligated to provide, or cause to be provided, all performance bonds, letters of credit, or guarantees required under the service agreement between Accroven and its customer, Petroleos de Venezuela Gas, S.A. In February 2006, AEI’s board of directors approved the execution of a reimbursement agreement with a bank to issue four new letters of credit totaling approximately $21 million. 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.

Enron financed part of its equity investment in Corinto through an arrangement with the U.S. Maritime Administration (“MARAD”). MARAD required Enron to purchase Corinto’s long-term debt with MARAD (less any amounts already deposited in a reserve fund) in the event that Enron’s corporate rating fell to BB plus or below. MARAD filed a proof of claim against Enron alleging Enron’s breach of the purchase agreement because Enron’s rating fell below BB plus. This issue is still under negotiation as part of the Enron bankruptcy claims process. The Company is committed to reimburse Enron for any amounts up to $11 million

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

that Enron pays related to the MARAD claim. The Company has rights to recover a portion of any amounts paid to Enron from the other shareholders of Corinto, but there is no assurance that these amounts would be collected. The outstanding balance on the Corinto debt, less amounts in the reserve fund of approximately $7 million, as of December 31, 2007 is $14 million. The claim is currently in the discovery phase; however, the Company does not believe that the currently expected outcome of this claim will have a material adverse effect on its financial condition, results of operations, or liquidity.

TBG and its shareholders were provided shareholder parent undertakings. The guaranty provided by one of the Company’s subsidiaries was in the total amount of approximately $17 million. However, TBG cannot call more than approximately $4 million under the guaranty, since the Company has already complied with its capital commitment obligations. The remaining $4 million under the guaranty can be called only under limited circumstances. Transredes provided a similar shareholder parent undertaking for TBG and its shareholders. The remaining guaranty for Transredes is approximately $12 million. The Company does not believe that the exposure under these guarantees will have a material adverse effect on its financial condition, results of operations, or liquidity.

Restrictions on Transfer of Net Assets — Certain governmental restrictions, such as statutory capital reserves, and lender provisions, including required maintenance of cash reserves and restrictions on payment of dividends, restrict various subsidiaries of the Company from transferring their net assets to the Company. The net assets of consolidated subsidiaries affected by such restrictions amount to approximately $386 million as of December 31, 2007. The net assets of unconsolidated subsidiaries affected by such restrictions amount to approximately $298 million as of December 31, 2007.

Political Matters:

Turkey — Since the change in the Turkish government in November 2002, Trakya and the other Turkish build-operate-transfer (BOT) projects have been under pressure from the Ministry to renegotiate their current contracts. The primary aim of the Ministry is to reduce what it views as excess return paid to the projects by the State Wholesale Electricity and Trading Company under the existing power purchase agreements. 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, but if accepted, implementation of changes to the power purchase agreements will take some time due to the need for a coordinated interaction among multiple government agencies. The Company does not believe that the currently expected outcome under the restructuring will have a material adverse effect on its financial condition, results of operations, or liquidity.

Trakya also has been under pressure from the Turkish Energy Regulatory Market Authority to renegotiate the terms of its contract. Trakya is in negotiations with the Ministry regarding a decrease in Trakya’s tariff due to a decrease in the Turkish statutory tax rate. In July 2006, the Ministry formally communicated to Trakya in writing its request that the reduction in enacted tax rates would require a discussion regarding a possible tariff adjustment under Trakya’s Cost Increase Protocol (“CIP”). In January 2008, Trakya was again approached by the Ministry seeking information regarding the implementation of the CIP provisions and a possible retroactive tariff modification. Based on the discussions in 2006 and in 2008, as of December 31, 2007 the Company has accrued approximately $12 million related to settlement with the Ministry and believes such reserves are adequate.

The Turkish Energy Market Regulatory Authority has also been attempting to submit Trakya to additional regulation. Trakya filed an appeal with the administrative appellate court set aside current regulations on the basis that they do not protect the vested rights of Trakya. A failure of Trakya to prevail in these actions could materially and negatively affect the project and its revenues and/or lead to a buyout of the plant pursuant to the implementation contract.

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AEI AND SUBSIDIARIES

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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 subject to payment of compensation for stranded costs. Stranded costs compensation would be based upon the capital expenditures incurred before May 1, 2004, which could not be recovered from future sales in the free market, and would be paid in quarterly installments. The maximum compensation attributable to ENS under the current proposal would be 1.12 billion Polish zloty (approximately U.S.$405 million).

The European Commission, in a decision dated September 25, 2007, declared the Polish long-term power purchase contracts to be illegal state aid. In the same decision the above-mentioned Polish legislation allowing for termination of long-term contracts with compensation was declared to be a state aid measure compatible with relevant EU legislation. In the decision Poland was obligated to terminate the long-term contracts by the end of 2007 (such termination becoming effective as of April 1, 2008) and the entities which voluntarily terminate their contracts within that period will not be obligated to return the aid already received. The entities that do not elect to terminate their long-term contracts will be obligated to return state aid received after May 1, 2004 and it is possible that those entries would not be entitled to continue the performance of their long-term contracts. ENS sent notice of its termination of its long-term power purchase contract in December 2007, with such termination to be effective as of April 1, 2008. In March 2008, ENS entered into a new power delivery agreement with a new energy purchaser, Mercuria Energy Trading Sp z.o.o. effective April 1, 2008. The Company does not expect the restructuring of ENS’ power sales agreement to have a material adverse effect on its financial condition, results of operations, or liquidity.

Bolivia/Brazil — On May 1, 2006, the Bolivian government purported to nationalize the hydrocarbons industry under Supreme decree No. 28701. The Decree, among other things, anticipates, through future action, the nationalization of the shares necessary for the state-run oil and gas company, Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), to control at least 50% plus one share of certain named companies, including Transredes. In March 2008, the Bolivian government issued another decree stating a deadline of April 30, 2008 for final implementation of the original decree. Further actions would be necessary for the government to expropriate the shares in Transredes held by the Company. No significant impact on operations at Transredes, GTB and TBG has occurred since the purported nationalization. The Company is currently evaluating the commercial impact that these political events in Bolivia could have on Cuiaba in Brazil.

Due to a shortage in gas exports from Bolivia, Cuiaba has been experiencing gas supply shortages (see Note 4). The gas supply agreement between TBS and YPFB expired during 2007. An interim gas supply agreement between TBS and YPFB was executed on June 22, 2007, which contemplates a reduction in the gas supply to Cuiaba through 2009. Negotiations for a definitive gas supply agreement, as well as negotiations with Furnas (Cuiaba’s off-taker) and ANEEL are ongoing. Cuiaba has not been receiving a regular supply of gas since August and since that time has only operated sporadically. As a result of a Brazilian government order, EPE anticipates entering into a short term agreement with Furnas pursuant to which it will run the Cuiaba plant on diesel and Furnas will acquire the energy produced by the plant. If EPE is unable to secure an adequate long-term supply of gas, the operations of Cuiaba will be materially adversely effected. Under these circumstances, there will be a corresponding impact on the Company’s financial performance and cash flows.

Litigation/Arbitration:

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

general experience with these particular types of cases. Although the ultimate outcome of such matters cannot be predicted with certainty, the Company accrues for contingencies associated with litigation when a loss is probable and the amount of the loss is reasonably estimable. The Company 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 the Company’s financial statements. It is possible, however, that some matters could be decided unfavorably to the Company and that the Company could be required to pay damages or to make expenditures in amounts that could be material, but cannot be estimated at December 31, 2007.

Elektro — Elektro is a party to approximately 5,000 lawsuits. The nature of these suits generally fall into three categories, namely civil, tax and labor. Civil cases include suits involving the suspension of power to nonpaying customers, suits involving 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 taxes, 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. The Company has accrued $18 million related to these cases, excluding those described below, as of December 31, 2007.

In December 2007, Elektro received two tax assessments issued by the Brazilian Internal Revenue Service (IRS), one alleging 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 $241 million is due related to the tax periods noted. Elektro has presented an administrative defense and is awaiting the administrative decision. Elektro believes that it has good grounds on which to contest these assessments and no reserves with respect to these claims have been recorded.

In December 2007, Elektro received a VAT assessment for approximately $8 million from the Sao Paulo State Treasury. Elektro believes that it has good grounds on which to contest this assessment. It has presented an administrative defense and is awaiting the administrative decision. No reserves with respect to this claim have been recorded.

In December 2006, the Brazilian National Social Security Institute notified Elektro about several labor and pension issues raised during a two-year inspection. A penalty was issued to Elektro in the amount of approximately $24 million for the assessment period from 1998 to 2006. Because Elektro is in the initial stage of presenting its administrative defense, the Company cannot determine the amount of any potential loss at this time. No reserves with respect to this claim have been recorded.

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. The Company has accrued approximately $49 million and made a judicial deposit of approximately $20 million related to this issue and does not believe that the currently expected outcome under these lawsuits will exceed this amount or will have a material adverse effect on its financial condition, results of operations, or liquidity.

Promigas — A class action suit is pending against Promigas pursuant to which the plaintiffs seek to recover $5 million in damages resulting from a pipeline explosion caused by terrorists in October 2001. While the matter is still in the initial stages, the Company does not believe that the currently expected outcome will have a material adverse effect on its financial condition, results of operations, or liquidity. No reserves with respect to this claim have been established.

EPE — As discussed in Note 4, on October 1, 2007, EPE received a notice from Furnas purporting to terminate the power purchase agreement with EPE as a result of the current lack of gas supply from Bolivia

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

described above. EPE strongly disagrees with Furnas’ position and notified Furnas that EPE believes Furnas has no contractual basis to terminate the power purchase agreement and initiated an arbitration proceeding in accordance with the power purchase agreement. Arbitrators for this proceeding are currently being selected. It is anticipated that due to the complexity of the case the arbitration could take more than 18 months to be finalized. If EPE is unable to satisfactorily resolve the dispute with Furnas, the operations of Cuiaba will be materially adversely effected with a corresponding impact on the Company’s financial performance and cash flows.

Under San Felipe’s Power Purchase Agreement, 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, 2007, 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 DOP716 million (equivalent to $21 million at the exchange rates prevailing on December 31, 2007) 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 is still pending. We have accrued approximately $59 million with respect to the period from January 1998 through December 31, 2007 which we believe is adequate. In addition, San Felipe has a contractual right under its Power Purchase Agreement to claim indemnification for taxes paid by San Felipe although the Company cannot be assured that any such amounts will be collected.

TBS — TBS is currently assessing whether it may have some claims against a former supplier of gas. If TBS decides to initiate any such claims, it is possible that the supplier may file certain claims that it believes it may have against TBS.

For a description of additional contingences related to income tax, see Note 18.


27.	RISKS AND UNCERTAINTIES

Regulatory, Political and Operations Risk — The revenues of some of the Operating Companies are dependent on tariffs or other regulatory structures that allow regulatory authorities to periodically review the prices such businesses charge customers and the other terms and conditions under which services and products are offered. Other Operating Companies rely on long-term contracts with governmental or quasi-governmental entities for all or substantially all of their revenues. Past and potential regulatory intervention and political pressures may lead to tariffs that are not compensatory or otherwise undermine the value of the long-term contracts entered into by the Company.

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The political and social conditions in many of the geographic regions where AEI’s businesses are located, including Latin America, present many risks, such as civil strife, guerrilla activities, insurrection, border disputes, leadership succession turmoil, war, expropriation, and nationalization.

The central banks of most foreign countries have the ability to suspend, restrict, or otherwise impose conditions on foreign exchange transactions or to approve the remittance of currency into or out of the country. In several of the countries where AEI operates, such controls and restrictions have historically been imposed.

Additionally, the Parent Company’s future dividends and other payments from its subsidiaries could be impacted by exchange controls or similar government regulations restricting currency conversion or repatriation of profits. Changes in government, even through democratic elections, could negatively impact the future profitability and cash flows of AEI.

Concentration of Customers and Suppliers — Many of the Operating Companies individually rely upon one or a limited number of customers that provide all or substantially all of the business’ revenue. Many of these businesses also rely on a limited number of suppliers to provide natural gas, liquid fuel, LPG, and other services required for the operation of the business. In certain cases, the financial performance of these Operating Companies is dependent upon the continued performance by a customer or supplier under their long-term purchase or supply agreements. One customer under long-term power purchase agreements accounted for 11% of the Company’s consolidated revenues in 2007. The same customer accounted for 13% of the Company’s consolidated revenues in 2006. The Operating Company that sold power to this customer is part of the Power Generation segment of the Company. The Company’s reportable segments are discussed further in Note 28. The loss of, or a significant modification of, one or more of the long-term purchase or supply agreements could have a material adverse impact on the Company’s results of operations and financial condition.


28.	SEGMENT AND GEOGRAPHIC INFORMATION

The Company manages, operates and owns interest 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 and 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 and operating expenses (including depreciation and amortization, 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 non-controllable 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 — The 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

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AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 business 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. It also includes the effects of eliminating transactions between segments including 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.

The tables below present summarized financial data about AEI’s reportable segments. Segment eliminations for intercompany transactions between segments are included in Headquarters and Other. For 2006, there are no Natural Gas Distribution segment revenues as this segment relates primarily to Promigas, which was acquired effective December 31, 2006.


	Power			Power			Nat. Gas.			Nat. Gas.			Retail			Headquarters
For the Year Ended December 31, 2007	Dist.			Gen.			Trans.			Dist.			Fuel			and Other			Total
	(Millions of dollars (U.S.))

Revenues	$	1,746		$	874		$	199		$	352		$	160		$	(115	)	$	3,216
Equity income from unconsolidated affiliates		2			11			39			13			11			—			76
Operating income		373			77			128			85			49			(135	)		577
Interest income		58			27			7			2			2			14			110
Interest expense		(90	)		(41	)		(42	)		(14	)		(12	)		(107	)		(306	)
Depreciation and amortization		139			42			20			8			3			5			217
Capital expenditures		(168	)		(3	)		(9	)		(24	)		(37	)		(8	)		(249	)
Goodwill		53			33			27			117			158			14			402
Total assets		3,732			1,433			1,138			913			384			253			7,853

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Power			Power			Nat. Gas.			Nat. Gas.		Retail			Headquarters
For the Year Ended December 31, 2006	Dist.			Gen.			Trans.			Dist.		Fuel			and Other			Total
	(Millions of dollars (U.S.))

Revenues	$	685		$	278		$	24		$	—	$	—		$	(41	)	$	946
Equity income from unconsolidated affiliates		26			21			10			—		4			(24	)		37
Operating income		151			60			21			—		3			(84	)		151
Interest income		20			11			—			—		—			40			71
Interest expense		(27	)		(18	)		(5	)		—		(2	)		(86	)		(138	)
Depreciation and amortization		47			9			2			—		1			—			59
Capital expenditures		(71	)		(1	)		—			—		(4	)		—			(76	)
Goodwill		—			—			27			97		152			14			290
Total assets		2,399			1,471			1,034			400		290			540			6,134

The table below presents revenues of the Company’s consolidated subsidiaries by significant geographical location for the years ended December 31, 2007 and 2006 and net property, plant and equipment, net as of December 31, 2007, and 2006. 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.


	Revenues				Operating Income					Property Plant &
	For the Year Ended				For the Year Ended					Equipment, Net
	December 31,				December 31,					December 31,
	2007		2006		2007		2006			2007		2006

Brazil	$	1,406	$	390	$	220	$	120		$	1,482	$	1,238
Colombia		563		—		198		3			614		512
Guatemala		168		48		42		12			37		52
Panama		389		371		57		37			242		233
Turkey		337		116		46		38			143		145
Other		353		21		14		(59	)		517		127

Total	$	3,216	$	946	$	577	$	151		$	3,035	$	2,307


29.	SUBSEQUENT EVENTS

SIE — On January 2, 2008, Promigas contributed its ownership interests in its wholly owned subsidiary Gazel to SIE in exchange for additional shares of SIE. The contribution was effected through the merger of certain subsidiaries of Promigas. As a result of the transaction, Promigas’ ownership in SIE increased to 54% and SIE now owns 100% of Gazel.

BMG — On January 30, 2008, AEI acquired a 70% interest in BMG and its subsidiaries for $28 million in cash. A portion of the interest purchase was funded in December 2007 and this 10% interest was accounted for under the cost method in 2007. In 2008, BMG will be consolidated as a result of the January 2008 transaction. BMG builds city gas pipelines and sells and distributes piped gas in the People’s Republic of China.

Luoyang — On February 5, 2008, AEI acquired for $14 million in cash a 48% interest in Luoyang Yuneng Sunshine Cogeneration Company Limited “Luoyang”, is 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.

F-93

AEI AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Trakya — In March 2008, Trakya entered into an agreement with Bayerische Landesbank (BLB) for a counter-guarantee to enable a new letter of guarantee for $54 million related to Trakya’s supply of gas. This new letter of guarantee is valid until March 6, 2009 and replaces Trakya’s previous letter of guarantee that expired earlier this year. The BLB counter-guarantee has been restructured and is now only partially cash collateralized. Accordingly, $27 million of Trakya’s cash balances have been reserved in a restricted account with BLB. If, however, certain material adverse conditions relating to Trakya’s Implementation Contract and the Energy Sales Agreement are triggered, there is an obligation for Trakya to fully cash collateralize the counter-guarantee.

Equity Incentive Plan — In February 2008, the Compensation Committee of the Board of Directors approved grants under the Company’s Equity Incentive Plan with a graduated 48-month vesting period. A grant was approved for options to purchase up to 1,218,425 shares and up to 242,748 restricted shares. None of these awards have been issued as of the date hereof.

* * * * * *

F-94

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 income statement of Prisma Energy International Inc. and subsidiaries (the “Company”), a predecessor entity of AEI, and the related consolidated statements of shareholder’s equity and cash flows for the 249 day period ended September 6, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America and in accordance with the auditing 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.

As discussed in Note 13 to the consolidated financial statements, in 2006 the Company changed its method of accounting for stock-based compensation in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Share-based Payment.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Prisma Energy International Inc. and subsidiaries for the 249 day period ended September 6, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

October 19, 2007

F-96

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES
(PREDECESSOR)

CONSOLIDATED STATEMENT OF INCOME


	249 Day
	Period Ended
	Sept. 6, 2006
	(In millions)

REVENUES	$	1,414
COST OF SALES (excluding depreciation shown separately below)		750
OPERATING EXPENSES:
Operations, maintenance, and general and administrative expenses		233
Depreciation and amortization		63
Taxes other than income		32
Loss on disposition of assets		6

Total		334
Equity earnings from unconsolidated affiliates		35

OPERATING INCOME		365

OTHER INCOME (EXPENSE):
Interest income from unconsolidated affiliates		2
Interest income		80
Interest expense		(70	)
Interest expense — Shareholder		(26	)
Foreign exchange gains — net		17
Gain on early retirement of debt		—
Other income (expense) — net		26

Total		29

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTEREST AND INCOME TAXES		394
MINORITY INTEREST		21

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		373
INCOME TAX EXPENSE		209

NET INCOME	$	164

Basic earnings per share	$	159.39
Diluted earnings per share	$	71.96

See notes to consolidated financial statements.

F-97

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES
(PREDECESSOR)

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY


											Accumulated
											Other
	Invested				Additional			Retain			Comprehensive			Total
	Capital		Common		Paid-In			Earnings			Income			Shareholders’			Comprehensive
	(Predecessor)		Stock		Capital			(Deficits)			(Loss)			Equity			Income
	(In millions)

BALANCE — January 1, 2006	$	—	$	—	$	3,017		$	512		$	(1,058	)	$	2,471
Net income									164						164		$	164
Distributions to shareholders						(740	)		(802	)					(1,542	)
Compensation under stock incentive plan						11									11
Dividend of portion of subsidiary to parent						(53	)		(2	)		3			(52	)
Cumulative transaction adjustments												80			80			80
Net gains (losses) from cash flow hedging activities
Change in fair value of cash flow hedge												2			2			2
Reclassification to earnings												1			1			1
Income Tax												(1	)		(1	)		(1	)
Change in fair value of net investment hedge												(2	)		(2	)		(2	)
Minimum pension liability accrual, net of income tax of $1 million												(2	)		(2	)		(2	)

Comprehensive income																	$	242

BALANCE — September 6, 2006	$	—	$	—	$	2,235		$	(128	)	$	(977	)	$	1,130

See notes to consolidated financial statements.

F-98

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES
(PREDECESSOR)

CONSOLIDATED STATEMENT OF CASH FLOWS


	249 Day
	Period Ended
	Sept. 6, 2006
	(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	164
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		63
Increase in deferred revenue		57
Deferred income taxes		86
Equity earnings from unconsolidated affiliates		(35	)
Distributions from unconsolidated affiliates		19
Foreign exchange gains — net		(17	)
Loss on disposition of assets		6
Minority interest expense		21
Changes in operating assets and liabilities:
Trade receivables		(2	)
Accounts payable — trade		46
Accrued income taxes		43
Accrued interest		(2	)
Inventory		2
Prepayments		(15	)
Regulatory assets and liabilities		17
Other operating activities		(5	)

Net cash provided by operating activities		448

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(72	)
Increase in restricted cash — net		(377	)
Other investing activities		1

Net cash provided by investing activities		(448	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long — term debt		937
Repayment of long — term debt		(80	)
Increase in short — term borrowing		89
Net distributions to Shareholder		(846	)
Capital Contributions		(727	)
Dividends paid to minority interest		(13	)
Debt issue costs		10
Other financing activities		50

Net cash used in financing activities		(580	)

EFFECT OF EXCHANGE RATE CHANGES		22

NET CASH FLOW		(558	)
CASH AND CASH EQUIVALENTS — Beginning of period		1,046

CASH AND CASH EQUIVALENTS — End of period	$	488

See notes to consolidated financial statements.

F-99

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the 249 Day Period Ended September 6, 2006

1. ORGANIZATION AND FORMATION

These consolidated financial statements present the historical results of Prisma Energy International Inc. (“PEI”, or “Parent Company”) which was purchased by Ashmore Energy International Limited (“AEIL”) in a two step transaction completed on September 6, 2006 (the “Acquisition”).

PEI, a Cayman Islands exempted company, was formed on June 24, 2003, to own and, in certain circumstances, operate many of the international energy infrastructure businesses owned by Enron Corp. and its affiliates (collectively “Enron”, or “Shareholder”). PEI, which is a holding company, owns and operates its businesses through a number of holding companies, management services companies, and operating companies (collectively, “Prisma Energy”, the “Company”, or the “Companies”). Prisma Energy is involved in the generation, transmission and distribution of power, and the transmission and distribution of natural gas and natural gas liquids outside of the United States.

Beginning on December 2, 2001, Enron and certain of its affiliates filed for protection pursuant to Chapter 11 of the United States Bankruptcy Code. Enron’s plan of reorganization, The Supplemental Modified Fifth Amended Joint Plan of Affiliated Debtors (the “Plan of Reorganization”), was confirmed by the United States Bankruptcy Court on July 15, 2004. On August 31, 2004, PEI and Enron entered into a Contribution and Separation Agreement (“Agreement”) which allowed for the contribution and rescission of certain equity interests, transferred contracts, transferred receivables and shared services assets (collectively referred to as the “Assets”) between Enron and PEI in exchange for shares in PEI. The Plan of Reorganization contemplated that these shares would either be distributed to Enron’s unsecured creditors or sold to a third party.

Under the terms of the original Agreement, prior to the distribution of the shares in PEI to the creditors, Enron could identify additional assets to be contributed. Similarly, prior to the distribution of the shares, Enron had the ability to rescind the transfer of Assets. Most of the contributed Assets were transferred to PEI between August 31, 2004, and November 30, 2004, in exchange for 939,846 shares of common stock. Additionally, Enron’s remaining 50% ownership in Smith/Enron Co-generation Limited Partnership (“SECLP”) and the Service Company that operates SECLP, notes receivable from EPE — Empresa Produtora de Energia Ltda. (“EPE”), notes receivable from GasOcidente do Mato Grosso Ltd. (“Gasmat”), and notes receivable from other Holding Companies were transferred in January and May 2006.

Prior to the contribution of the Assets to PEI, the only subsidiary of PEI was Prisma Energy International Services LLC (“Prisma Services”), which was assigned by Enron to PEI in July 2003. Prisma Services, headquartered in Houston, Texas, has approximately 125 employees that provide services to Prisma Energy, as well as, in certain instances, Enron with respect to operating and managing its international assets.

As further discussed below, subsequent to this Agreement, Enron entered into a share purchase agreement with AEIL for the sale of Prisma Energy which was executed in a two-stage transaction.

At the initial closing, Prisma Energy distributed to Enron approximately 77% of its indirect ownership in Promigas S.A., ESP. Enron also retained the right, under certain limited circumstances, to rescind the transfer to PEI of its indirect equity interests in Accroven S.R.L., Elektrocieplownia Nowa Sarzyna Sp. z.o.o., and Puerto Quetzal Power LLC. Enron’s rescission and contribution rights on any other Assets have been terminated as a part of the sale transaction described above.

Enron, AEIL, and PEI signed a share purchase agreement dated May 23, 2006 (“Share Purchase Agreement”), which was subsequently amended and restated on June 9, 2006, for the sale of 100% of the outstanding equity of Prisma Energy in a two-stage transaction. At the initial closing on May 25, 2006, AEIL purchased a 49% economic interest and a 24.26% voting interest in Prisma Energy. AEIL purchased the remaining economic and voting interest in a second closing (“Second Closing”) dated September 6, 2006, after certain consents and waivers were obtained from third parties (contract counterparties, regulators, etc).

F-100

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On May 25, 2006, the Company also entered into an agreement to provide services to AEIL related to the management of certain of their international energy businesses. This agreement terminated 90 days following the Second Closing.

On December 29, 2006, AEIL and PEI were amalgamated under Cayman law, with PEI being the surviving entity, and PEI’s name was changed to Ashmore Energy International. In October 2007, the Company changed its name to AEI.

The equity interests at September 6, 2006, contributed by Enron or purchased from third parties by Prisma Energy include indirect investments in the international businesses described below:


	Ownership
	Interest^(a)		Location of
Company Name	(%)		Operations	Description

ELEKTRO — Eletricidade e Serviços S.A. (“Elektro”).		99.7	Brazil	Power distribution
EPE — Empresa Produtora de Energia Ltda. (“EPE”)^(b)		50.0	Brazil	Power generation
GasOcidente do Mato Grosso Ltda. (“Gasmat”)^(b)		50.0	Brazil	Gas pipeline
GasOriente Boliviano Ltda. (“Gasbol”)^(b)		50.0	Bolivia	Gas pipeline
Transborder Gas Services Ltd. (“TBS”)^(b)		50.0	Brazil and Bolivia	Purchase and sale of natural gas for EPE
Transredes — Transporte de Hidrocarburos S.A. (“Transredes”)		25.0	Bolivia	Gas and liquids pipeline
Gas Transboliviano S.A. (“GTB”)^(c)		17.0	Bolivia	Gas pipeline
Transportadora Brasileira Gasoduto Bolivia-Brasil S/A — TBG (“TBG”)^(c)		4.0	Brazil	Gas pipeline
Promigas S.A. E.S.P. (“Promigas”)		9.9	Colombia	Diversified gas transportation and distribution
Vengas, S.A. (“Vengas”)		97.8	Venezuela	LPG transportation and distribution
Accroven SRL (“Accroven”)		49.3	Venezuela	Gas extraction, fractionation and storage
Bahía Las Minas Corp. (“BLM”)		51.0	Panama	Power generation
Puerto Quetzal Power LLC (“PQP”)		55.0	Guatemala	Power generation
Empresa Energetica Corinto Ltd. (“Corinto”)		35.0	Nicaragua	Power generation
Smith/Enron Cogeneration Limited Partnership (“SECLP”)^(d)		85.0	Dominican Republic	Power generation
Smith/Enron O&M Limited Partnership^(d)		50.0	Dominican Republic	Power generation
Trakya Elektrik Üretim ve Ticaret A.S. (“Trakya”)		59.0	Turkey	Power generation
Elektrocieplownia Nowa Sarzyna Sp. z.o.o. (“Nowa Sarzyna”)		100.0	Poland	Power generation
Subic Power Corp.		50.0	Philippines	Power generation


(a)		Approximate ownership interests as of date of contribution to Prisma Energy. The ownership interest in PQP was increased to 55% in April 2005. The ownership in Promigas was reduced from 42.94% to 9.9% as of May 25, 2006, following the distribution of 33.04% back to Enron.


(b)		The companies comprise an integrated operation referred to collectively as “Cuiaba”.


(c)		Ownership interest based on direct ownership. Total ownership including indirect interests held through Transredes is 29.75% for GTB, and 7.0% for TBG.


(d)		Ownership interest of 35% held by Vengas was contributed to Prisma Energy in August 2004 in connection with the contribution of Vengas. An additional 50% interest was contributed in May 2006 by Enron. This was accounted for as a transfer between entities under common control.

F-101

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


2.	BASIS OF PRESENTATION

For accounting purposes, the contribution of the Assets to Prisma Energy was a transfer between entities under common control. The historical results of operations and cash flows have been presented as if Enron had contributed the Assets as of January 1, 2006 (the “Contribution Date”).

The assets and liabilities have been accounted for at the historical book values carried by Enron. Prior to the contribution, Enron obtained a third party valuation for the Prisma Energy Assets. The carrying values of the Assets were evaluated for impairment at that time and adjusted accordingly based on the valuation, or on other relevant fair value indicators.

The primary Assets contributed to Prisma Energy were direct and indirect equity interests in international operating companies (“Operating Companies”), direct and indirect equity interests in management companies that perform operations, maintenance and administrative services (“Service Companies”), direct and indirect equity interests in intermediate holding companies (“Holding Companies”), and accounts and notes receivable previously held by Enron from these Companies.

The internal funding structure for the initial development and/or acquisition of the Operating Companies was either through cash contributed by Enron to the Holding Companies, or through intercompany notes between Enron and the Holding Companies or through intercompany notes directly with the Operating Companies. Additional intercompany payables to Enron were also incurred due to cash transfers, corporate allocations, and other intercompany activities. The terms of the notes and intercompany payables vary, and in many instances were non-interest bearing. Most of the intercompany notes receivable from the Companies that were held by Enron were either partially or fully transferred to PEI in exchange for shares. Any intercompany interest associated with these notes has been eliminated. Cash transfers to Enron subsequent to the Contribution Date as payment on these notes and intercompany balances, have been included in the amounts reflected as Distributions to Shareholder on the Consolidated Statement of Shareholders’ Equity and the Consolidated Statement of Cash Flows.


3.	SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation — The consolidated financial statements include the accounts of Prisma Energy International Inc., its wholly owned or controlled subsidiaries, and any variable interest entities (“VIE”) for which Prisma Energy is the primary beneficiary. Investments in subsidiaries in which the Company has the ability to exercise significant influence but not control, and investments in VIEs for which Prisma Energy is not the primary beneficiary, are accounted for using the equity method of accounting. Investments in which the Company does not have significant influence are accounted for using the cost method. All intercompany accounts and transactions have been eliminated.

The Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, in January 2003 and a subsequent revision in December 2003 (“FIN 46(R)”). The primary objective of FIN 46(R) is to provide guidance on the identification of and financial reporting for, entities over which control is achieved through means other than through voting rights. Such entities are referred to as VIEs. FIN 46(R) requires a company to consolidate a VIE if that company is the primary beneficiary. The primary beneficiary of a VIE is the company that has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both.

Use of Estimates — The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these

F-102

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

financial statements relate to useful lives and carrying values of long-lived assets, carrying value and impairments of equity method investments, primary beneficiary determination for the Company’s investments in VIEs, determination of functional currency, valuation allowances for receivables, the recoverability of deferred regulatory assets, environmental liabilities, the outcome of pending litigation, provision for income taxes, and fair value calculations of derivative instruments.

Foreign Currency — The Company translates the financial statements of its international subsidiaries from their respective functional currencies into the U.S. dollar in accordance with SFAS No. 52, Foreign Currency Translation. 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 at the end of the year. The revenues and expenses of such subsidiaries are translated into U.S. dollars at the average exchange rates for the year. 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 many of the international 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 Elektro in Brazil, Vengas in Venezuela, and Promigas in Colombia.

Revenue Recognition — The Company’s consolidated revenues are attributable to sales and other revenues associated with the transmission and distribution of power and LPG, sales from the generation of power, and revenues from providing administrative, operations and maintenance services to unconsolidated affiliates and to the Shareholder.

Power distribution sales to final customers are recognized when power is provided. Billings for these sales are made on a monthly basis. Revenues that have been earned but not yet billed are accrued based upon the estimated amount of energy delivered during the unbilled period and the historical average of the billing rates for each category of customer. Differences between estimated and actual unbilled revenues are recognized in the following month. 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.

The Company recognizes revenue when it is realized or realizable, earned, and when collectibility is reasonably assured. Beginning in 2002, EPE entered into discussions with its sole customer to renegotiate its power purchase agreement. The Company determined that the amended power purchase agreement for EPE should be considered a lease in accordance with SFAS No. 13, Accounting for Leases, and the guidance in EITF No. 01-8, Determining When an Arrangement Contains a Lease. The lease inception date was July 1, 2005. The Company recognizes revenue on the net investment in direct financing lease over the term of the power purchase agreement based on a constant periodic rate of return. Contingent rentals are recognized as received.

All other revenues are recognized when products are delivered or services are rendered.

Deferred Revenue — Applicable revenues are recognized based on the lesser of (1) the amount billable under the contract or (2) an amount determined by the kilowatt-hour 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.

F-103

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

except that it includes the dilutive effect of the assumed exercise of potentially dilutive securities, including the effects of outstanding restricted stock units and securities issuable under the Company’s stock-based incentive plans. Potentially dilutive securities, including outstanding stock units, are excluded in calculating earnings per share if their inclusion is anti-dilutive. All reference to earning per share is on a diluted basis unless otherwise noted.

Basic and diluted earnings per share were as follows:


	249 Day
	Period Ended
	September 6,
	2006

Basic earnings per share computation
Numerator
Net Income (in millions)	$	164
Denominator
Average number of common shares outstanding (in millions)		1

Net income per share	$	159.39

Diluted earnings per share computation
Numerator
Net income (in millions)	$	164
Denominator
Average number of common shares outstanding (in millions)		2

Net Income per share	$	71.96

Property, Plant, and Equipment — Expenditures for maintenance costs and repairs are charged to expense as incurred.


Power generation equipment			5 - 30 years
Pipelines			21 - 40 years
Machinery and equipment			5 - 50 years

Deferred Financing Costs — Financing costs are deferred and amortized over the related period using the effective interest rate method or the straight-line method when it does not differ materially from the effective interest method.

Income Taxes — In accordance with SFAS No. 109, Accounting for 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 enters into various derivative transactions in order to hedge its exposure to commodity, foreign currency, and interest rate risk. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, the Company reflects all derivatives as either assets or liabilities on the 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, which requires that a company must formally

F-104

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

document, designate, and assess the effectiveness of the hedge. Changes in the fair value of a derivative that is highly effective and qualifies as a cash flow hedge are reflected in accumulated other comprehensive income and recognized in income when the hedged transaction occurs. Any ineffectiveness is recognized in income immediately. Changes in the fair value of hedges of a net investment in a foreign operation are reflected as cumulative translation adjustments in other comprehensive income. Many contracts of the Company that would otherwise have been accounted for as derivative instruments do not meet derivative classification requirements due to the fact that they are not readily convertible to cash.

Pension Benefits — Employees in the United States and in many of the foreign locations are covered by various retirement plans provided by PEI or the respective Operating Companies. The types of plans include defined contribution and savings plans, and defined benefit plans. The Company accounts for defined benefit pension plans in accordance with SFAS No. 87, Employers’ Accounting for Pensions. Expenses related to the defined benefit pension 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 as further discussed in Note 14, Benefit Plans. Expenses attributable to the defined contribution and savings plans are recognized as incurred.

Stock-Based Compensation — The Company adopted a long-term equity incentive compensation plan during 2004 and applies the fair value method of accounting for stock awards issued under the plan in accordance with FASB No. 123(R), Share-Based Payment. The fair value of the award is determined at the date of the share grant and compensation expense is recognized over the required vesting period.

Regulatory Assets and Liabilities — The Company has certain operations that are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The Company capitalizes incurred allowable costs as deferred regulatory assets if there is a probable expectation that future revenue equal to the costs incurred will be billed and collected through increases in the tariff. If future recovery of costs is not considered probable, the deferred regulatory asset is recognized as expense. Regulatory liabilities are recorded for amounts expected to be passed to the customer as refunds or reductions on future billings.


4.	CASH AND CASH EQUIVALENTS

Supplemental cash flow information is as follows:


	249 Day
	Period Ended
	Sept. 6, 2006
	(U.S. dollars
	in millions)

Cash paid during the period for:
Interest	$	95
Income taxes		64

Cash paid for interest includes payments to Enron of $6 million during the 249 day period ended September 6, 2006. Additionally, cash paid for interest includes payments to AEIL of $9 million for the 249 day period ending September 6, 2006.


5.	REGULATORY ASSETS AND LIABILITIES

Elektro operates in the Brazilian electricity sector, which is subject to regulation by Agência Nacional de Energia Elétrica — ANEEL (“ANEEL”). The rate-setting structure is designed to maintain the economic and financial balance of the concession and to transfer the concessionaire’s productivity gains to the consumers. The tariff structure provides for recovery of Elektro’s allowable costs, including those incurred as a result of government-mandated power rationing measures imposed during 2001. Tariffs are reset every four years and have an annual readjustment for inflation of controllable costs and the pass through of non-controllable costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Additionally, Elektro is entitled to an extraordinary tariff review, in the event of significant changes in the cost structure, in order to maintain the economic and financial equilibrium of the concession.

Deferred Tariff Increase — In the August 2003 tariff review, ANEEL allowed Elektro a tariff increase of 28.69%, of which 20.25% was effective immediately with the remainder to be applied in three annual installments effective August 2004, 2005, and 2006, which will be recovered in 2007.

Recovery of Losses From Rationing Program — During 2001, the Federal Government of Brazil instituted an electricity rationing program in response to an energy shortage caused by low rainfall, reduced reservoir levels and Brazil’s significant dependence on electricity generated from hydrological resources. The rationing resulted in losses for the Company and other distribution companies in Brazil. In December 2001, electricity concessionaires reached an industry-wide agreement, the Electric Sector General Agreement, with the Federal Government granting increased rates to distribution companies to provide recovery for losses incurred as a result of the rationing program. The impact of the increased rates was recorded to revenues with a corresponding recognition of a deferred regulatory asset. The deferred asset represents the amount expected to be recovered over the next 24 months, in accordance with EITF No. 92-7, Accounting by Rate Regulated Utilities for the Effects of Certain Alternative Programs.

Free Energy — Following the privatization of power companies in Brazil at the end of the 1990’s, long-term power supply contracts between generation companies and distribution companies were cancelled and replaced with new contracts (“Initial Contracts”). Free Energy refers to power produced by generation plants that was not committed to Initial Contracts.

The Brazilian electricity market has a reallocation mechanism that attributes a level of assured power to each generation plant and distributes any surplus among the generating plants that are producing less than their specific level of assured power. During the rationing program in 2001, the national electric system operator ordered a sharp reduction in the power generated by plants that operated under the Initial Contracts. This reduction resulted in a financial exposure for these plants because they were forced to purchase power through the wholesale market in order to satisfy their requirements under their Initial Contracts. The Electric Sector General Agreement stipulated a limit for this financial exposure by setting a price cap for the Free Energy purchased during the rationing period. The difference between (1) the wholesale energy market prices during the rationing period owed to the Power Generation plants producing Free Energy, and (2) the capped price, is being reimbursed by the local distribution companies on a monthly basis and passed-through to the energy tariffs of the final consumers.

Parcel A — As a part of the Electric Sector General Agreement, the distribution companies obtained the right to recover price variations for non-controllable costs (“Parcel A” costs). Distribution companies are permitted to pass the Parcel A costs through to the customers via future rate adjustments. Parcel A costs are limited by the concession contracts to the cost of purchased power and certain other costs and taxes not controlled by the Company. The regulatory asset for Parcel A refers to increases in Parcel A costs between January and October 2001, which Elektro will recover by the end of 2007 through the extraordinary tariff increase mechanism.

Tracking Account for Variations in Parcel A — The Parcel A tracking account mechanism (“CVA”) was established to record monthly price variations, from October 2001 onwards, for non-controllable costs between annual tariff adjustments. In each annual tariff adjustment, there is a tariff increase or decrease, for the following twelve months, to reconcile for the accumulated gain or loss of the CVA. Interest is applied if an increase is realized.

Recoverable Revenue Taxes — In accordance with the Concession Agreement and local law, Elektro has the right to tariff adjustments for increases in certain taxes on revenues to support various social programs. These taxes include Employees Social Integration Program (“PIS”), Government Employees Savings Program (“PASEP”), and Tax for Social Security Financing (“COFINS”). Through August 2005, Elektro recognized

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

such tax increases as regulatory assets and will receive recovery of the deferred asset through the annual tariff adjustments in 2005 and 2006. Elektro began recovering such tax increases through direct charges to its consumers in August 2005 and expects full recovery by August 2008.

Energy Savings Program — Elektro’s concession agreement reflects an industry-wide requirement of an annual obligation to invest 1% of net operating revenue in programs to reduce energy losses and for technological research and development in the power sector. This regulatory charge is included in the tariff collected from the customers. Elektro has invested in public lighting programs, projects for primary education, and several studies on how to improve the use of electric energy in Brazil. The Company recognizes 1% of its net operating revenues as a liability for the energy savings program. The liability is then reduced by the operating expenses and depreciation related to this program as they are incurred.

Low Income Customers — A certain classification known as “low income customers” includes residential customers whose consumption is below certain specified limits. These low-income customers have the right to lower tariffs. After the low-income system was implemented, the law changed the criterion for “low income” which generated a surplus to Elektro. This surplus will be redistributed to Elektro’s customers in each annual tariff adjustment.


6.	INVESTMENT IN DIRECT FINANCING LEASE

The power purchase agreement between EPE and Furnas was amended in July 2005. In accordance with SFAS No. 13, Accounting for Leases, and the guidance in EITF No. 01-8, Determining When An Arrangement Contains a Lease (“EITF 01-8”), the Company determined that the power purchase agreement should be accounted for as an in-substance finance lease. The lease inception date was July 1, 2005. The Company has also determined that the power purchase agreement entered into by Trakya should be accounted for as an operating lease under EITF 01-8 as of November 2004.

Future minimum lease payments on direct financing leases are $19 million in 2006, $23 million in 2007, $22 million in 2008, $20 million in 2009, $20 million in 2010, and $112 million thereafter. Future minimum rentals on noncancellable operating leases are $170 million in 2006, $167 million in 2007, $154 million in 2008, $170 million in 2009, $55 million in 2010 and $580 million thereafter.


7.	INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Prisma Energy’s equity earnings from unconsolidated affiliates for the 249 day period ended September 6, 2006 are as follows:


	249 Day
	Period Ended
	Sept. 6, 2006
	(U.S. dollars
	in millions)

Accroven	$	3
GTB		4
Promigas		14
Subic		4
Transredes		10

	$	35

The Company adopted the requirements of FIN 46(R), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, effective January 1, 2004. The Company determined that the Cuiaba, Trakya and Corinto entities are VIEs. The Company has ownership interests and notes receivable with Cuiaba, which based on analysis, will absorb a majority of the entity’s expected losses, receive a majority of the entity’s

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

expected residual returns, or both. The Company has a majority equity position and is closely associated with Trakya’s operations through its operations and management agreement. Therefore the Company has determined that it is the primary beneficiary for the Cuiaba and Trakya entities. One Cuiaba company, Gasbol, was accounted for under the equity method of accounting prior to the adoption of FIN 46(R). The Company has an ownership interest and notes receivable from Corinto but has determined that it is not the primary beneficiary.

Summarized financial data for investments accounted for under the equity method is as follows:


	249 Day
	Period Ended
	Sept. 6, 2006
	(U.S. dollars
	in millions)

Statement of Income
Renues	$	452
Net income		109

The Company provides administrative, operations and maintenance services to some of the Operating Companies on a contracted basis. Revenues recognized for services provided to unconsolidated affiliates were $3 million for the 249 day period ended September 6, 2006.


8.	LONG TERM DEBT

Long-term debt balances and related interest rates by borrower as of December 31, 2005, are as follows. Interest rates reflected in the table are year-end rates.


	2005
	(U.S. dollars
	in millions)

Elektro, Brazilian real debentures, 11.80% to 20.65%	$	321
Elektro, Brazilian real notes, 5.00% to 15.75%		55
Trakya, U.S. dollar notes, 7.9% to 9.8%		139
Cuiaba, U.S. dollar notes to other shareholders, 0% to 10%		123
Nowa Sarzyna, U.S. dollar loans, 6.28%		91
PQP, U.S. dollar notes, 6.47% to 10.66%		70
BLM, U.S. dollar notes, 7.81% to 8.31%		41
BLM, short term financing		6
Vengas, Venezuelan bolivar loans, 15.4%		19
Other		5

The long-term debt held by the Operating Companies is nonrecourse and is not a direct obligation of the Parent Company. Many of the financings are secured by the assets and a pledge of ownership of shares of the individual Operating Companies. The terms of the long-term debt include certain financial and non-financial 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.

Enron had historically provided payment guarantees and other credit support for the long-term debt of some of the Operating Companies. The Enron bankruptcy created defaults under these financings. The guarantees have not been replaced, but the defaults were cured through additional financial restrictions placed on the Operating Companies including the funding of additional reserves.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Elektro — During 2005, Elektro implemented a restructuring of its debt, including both third party and intercompany financing arrangements, and capital investments. In October 2005, Elektro raised $332 million (R$750 million) through a public debenture offering in Brazil. The public debentures in the amount of R$750 million were issued in three series that mature in equal installments in 2009, 2010, and 2011. The debentures accrue interest based on 11.8% per year and are indexed to IGP-M (Brazil market general price index) for the first series, and based on CDI (Brazil interbank interest rate) plus 1.65% per year for the second and third series. Interest payments are due annually for the first series, and due semi-annually 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.

Elektro has also been provided financing by Banco Nacional de Desenvolvimento Econômica e Social (the National Bank of Economic and Social Development) and by Eletrobrás, the Brazilian state-owned electric company. These financings were provided for various capital expenditure and regulatory programs including energy rationing and the tracking account for Parcel A. These loans have maturities from 2006 through 2016 and accrue interest based on the Selic rate (Brazil central bank overnight lending rate) + 1% per year, RGR (Global Reversion Reserve fund rate) + 5% per year, or TJLP (Brazil long term interest rate) + spreads from 3.2% to 6.0%. These financings are secured either by pledge of funds or by bank letters of guarantee.

A summary of the relevant interest rates and indices for Brazil as of December 31, 2005, were as follows:


	2005

TJLP		9.75	%
Selic		19.05
CDI		19.00
RGR		—

Trakya — The financing consists of Export-Import Bank of the United States (“EXIM”), Overseas Private Investment Corporation (“OPIC”), and commercial bank loans. These loans bear various interest rates including fixed rates of 7.95%, interest rates based on a certificate interest rate plus 3.2%, and interest based on six-month LIBOR. Trakya was required to enter into interest rate swap agreements on the LIBOR based loan for a fixed rate of 7.90%. Principal payments are due semi-annually with final maturity in 2008. Interest payments are due either quarterly or semi-annually. All assets of Trakya are pledged as collateral under its loan facilities. The loan facilities also require reserves for debt service, debt payment, and maintenance.

Cuiaba — The financing for EPE, Gasmat, and Gasbol consists of shareholder loans. The loans consist of several promissory notes bearing fixed interest rates of 0%, 6% and 10% and are unsecured. Principal and interest payments are due annually with final maturities from 2015 through 2017. EPE, Gasmat and Gasbol have the right to prepay the notes. EPE and Gasmat also have the ability to roll over the notes if unable to repay the debt in any given year.

Nowa Sarzyna — The financing consists of a commercial bank syndicated loan bearing a floating interest rate based on LIBOR + variable margin in the range of 1.25% and 1.68%. Nowa Sarzyna entered into an interest rate swap agreement for a fixed rate of interest of 6.28%. Principal and interest payments are due semi-annually with final maturity in 2015. The loan is secured by all the noncurrent assets of Nowa Sarzyna. The loan requires reserves for debt service and maintenance. The bank also required a special reserve of $10 million be established, which may, under certain conditions be released on December 31, 2006.

PQP — The financing for PQP includes bonds and certificates of participation with the United States Secretary of Transportation Maritime Administration (“MARAD”) and OPIC bearing fixed interest rates of 6.47% and 10.66%. Principal and interest payments are due semi-annually with final maturity in 2012. The loans are secured by PQP’s power plant barges and moveable assets and the shares of PQP. The loan facilities

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PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

require reserves for debt service, major maintenance, and insurance. A special escrow reserve was also established as required by MARAD. The balance of the escrow reserve as of December 31, 2005, was $14 million. Under certain conditions, this escrow reserve may be released in five equal installments beginning December 31, 2005.

BLM — In June 2005, BLM refinanced all of its existing bank debt, which was previously due to mature between 2006 and 2007. The new syndicated bank loans are divided into two tranches. Tranche A is a $28 million senior secured term loan with an interest rate of LIBOR + 4% for the first two years and LIBOR + 4.5% thereafter. Principal and interest for Tranche A is payable quarterly until maturity in 2012. Tranche B is a $15 million subordinated loan with a bullet maturity in 2012 and bears an interest rate of LIBOR + 3.5%. Both tranches are collateralized by the assets of BLM, and the Tranche A lenders benefit from a pledge of Prisma Energy’s 51% indirect ownership interest in BLM. The Republic of Panama guarantees Tranche B. As collateral for the guarantee, the five 115 kV substations located inside the BLM plant facility have been mortgaged in favor of the Republic of Panama. Both Tranches have mandatory prepayment provisions with cash sweeps.

As of December 31, 2005, BLM also had short-term borrowings of $6 million that were repaid in January 2006. Under the loan agreement with the senior lenders, BLM is authorized to enter into short-term financing of up to $11 million for fuel purchases secured with accounts receivable. Subsequent to December 31, 2005, BLM entered into an agreement for a line of credit for $8 million, which must be utilized solely for the purchase of fuel. This facility is also secured by the accounts receivable of BLM. BLM’s senior lenders have capped the combined outstanding amounts at any time under both the short-term financing and the line of credit to $16 million.

Vengas — The Vengas financing is an unsecured loan agreement with a Venezuelan syndicate of banks. The loan, which is denominated and payable in Venezuelan bolivars, bears interest at 90% of the Venezuelan active market rate (“TAM”). Principal and interest are payable monthly with final maturity in 2007.

Aggregate maturities of the principal amounts of long-term debt obligations for the next five years and in total thereafter are as follows:


	(U.S. dollars
	in millions)

2006	$	122
2007		93
2008		82
2009		140
2010		139
Thereafter		294

Total	$	870


9.	INTEREST INCOME

As discussed in Note 7, the long-term receivables from Furnas accrue interest based on the Selic rate. Additionally, under the terms of the agreement, retroactive interest was allowed to be applied to the balances that were outstanding since 2002. Interest income recognized on these receivables was $5 million for the 249 day period ended September 6, 2006.

Monetary index adjustments based on indicators, such as interest or inflation rates, are utilized in Brazil to maintain the value of assets and to update liabilities in order to compensate creditors for loss of value over time. The regulator allows Elektro to utilize the monetary indexation mechanism to adjust its regulatory assets and liabilities. Additionally, Brazilian tax authorities require that amounts related to contingent tax payments

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PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

be adjusted. Income recognized for monetary index adjustments included in interest income was $13 million for the 249 day period ended September 6, 2006.


10.	OTHER INCOME (EXPENSE) — NET


	249 Day
	Period Ended
	Sept. 6, 2006
	(U.S. dollars
	in millions)

Income from right of reimbursement	$	45
Expenses from interest and penalties		(6	)
Write-off of loan to related party		(14	)
Other — net		1

	$	26

In relation to its long-term receivable with CDE, SECLP recognizes income and offsetting expense, related to its right of reimbursement of taxes, associated interest, and surcharges related to the noncurrent liability.


11.	INCOME TAXES

PEI 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 in the countries in which operations are conducted and income is earned. Variations also arise when income earned and taxed in a particular country or countries fluctuates from year to year.

Income Tax Provision — The provision for income taxes on income from continuing operations is comprised of the following:


	249 Day
	Period Ended
	Sept. 6, 2006
	(U.S. dollars
	in millions)

Current:
Cayman Islands	$	—
Foreign		125

Total current		125

Deferred:
Cayman Islands		—
Foreign		84

Total deferred		84

Provision for income taxes	$	209

Income from continuing operations before minority interest and taxes was $394 million for the 249 day period ended September 6, 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Effective Tax Rate Reconciliation — A reconciliation of the Company’s income tax rate to its effective tax rate as a percentage of income before taxes is as follows:


	249 Day
	Period Ended
	Sept. 6, 2006

Statutory tax rate — Cayman Island		—	%
Taxes of foreign earnings		53.05
Tax credits		—
Valuation allowance and other adjustments		—

Effective tax rate		53.05	%

The Company has received tax assessments from various taxing authorities and is currently at varying stages of appeals and /or litigation regarding these matters. The Company has provided for the amounts it believes will ultimately result from these proceedings. The Company believes it has substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. While the Company has provided for the taxes that it believes will ultimately be payable as a result of these assessments, the aggregate assessments at December 31, 2005 are approximately $82 million in excess of the taxes provided for in these consolidated financial statements.

Income tax returns are subject to review and examination in the various jurisdictions in which the Company operates. In accordance with the guidance in SFAS No. 5, Accounting for Contingencies, the Company accrues for taxes in certain situations where it is probable that the taxes ultimately payable will exceed the amounts reflected in the filed tax returns, even though formal assessments have not yet been received. While the Company cannot predict or provide assurance as to the final outcome, the Company does not believe it is probable that such taxes will be ultimately payable and does not expect the liability, if any, resulting from existing or future assessments to have a material impact on its consolidated financial position, results of operations or cash flows.

The Company had net operating losses expire in 2005 in the amount of $1 million. The Company has net operating loss carryforwards in several jurisdictions that expire between 2006 and 2013. The tax-effected amount of these net operating loss carryforwards was $4 million at December 31, 2005. 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 $205 million at December 31, 2005.

The Company had no tax credits expire in 2005. The Company has tax credits in several jurisdictions that will expire between 2006 and 2010. The amount of these credits was $0.1 million at December 31, 2005. The Company also has credits in jurisdictions in which the credit will never expire. The amounts of these credits were $25 million at December 31, 2005.

The Company is subject to changes in tax laws, treaties and regulations in and between the countries in which it operates. A material change in these tax laws, treaties or regulations could result in a higher or lower effective tax rate on the Company’s worldwide earnings. For example, Turkey enacted Law No. 5520, published on June 21, 2006, which lowers its corporate income tax rate from 30% to 20% effective January 1, 2006. While this will not affect current tax expense for the 249 day period ended September 6, 2006 the change in law resulted in an extraordinary charge in Trakya, which showed an increase in net income taxes of $56.6 million for the 249-day period ended September 6, 2006 resulting from a writedown in value of the deferred tax assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


12.	RELATED PARTY TRANSACTIONS

The Company and Enron have entered into various agreements for services to be provided to each other. Since its formation in July 2003, Prisma Services has provided administrative, operations and maintenance services to Enron for the management of certain of its international businesses and for the winding up of other Enron related matters. The Company received revenue from Enron for management services for the Assets through the date that each of the Assets was contributed to Prisma Energy. Revenues recognized for services provided to Enron were $2 million for the 249 day period ended September 6, 2006.

Enron provides services to the Company through a Transition Services Agreement (“TSA”) that was effective as of August 31, 2004. Under the TSA, Enron provides certain direct and indirect services to Prisma Energy. Charges include (i) direct costs such as rent, information technology, and employee benefits, (ii) direct services such as payroll administration, tax, legal, accounting services, and (iii) fixed monthly fees for office facilities, information technology support, treasury management, risk assessment and control services, and accounting system usage.

Prior to the effective date of the TSA, corporate allocations from Enron were based on both a direct and an indirect allocation of expenses. The direct expenses included charges for rent and information technology services. The indirect allocation was calculated utilizing a methodology approved by the bankruptcy court based on relative average assets and revenues.

Expenses included in the Consolidated Statements of Income for direct and indirect corporate allocations from Enron were $1 million for the 249 day period ended September 6, 2006.

The Company’s U.S. based and expatriate employees participate in Enron employee benefit programs, including health insurance and savings plans. The expense for these benefits was $2 million for the 249 day period ended September 6, 2006.

Many of the Company’s U.S. based and expatriate employees were also participants in the Enron Corp Cash Balance Plan. Following the Enron bankruptcy, the Pension Benefit Guaranty Corporation, which is a federal corporation that insures defined benefit pension plans, filed claims for unfunded benefit liabilities related to this plan and the pension plans of other Enron affiliates (“Pension Plans”). The underfunding obligation for its employees of $2 million was paid to Enron in May 2006, and Prisma Energy has no remaining obligations for these Pension Plans.

The Company leased office space for its Houston headquarters through a sublease agreement with Enron signed on October 31, 2003. Enron elected to have Prisma Energy enter into a direct agreement with the landlord for the lease of the space on substantially the same terms and conditions as Enron’s master lease. The terms of both the sublease and the master lease agreements were for 62 months expiring in April 2009. Rent expense included in the expense allocations from Enron was $0.4 million for the 249 day period ended September 6, 2006.

The Company has notes and accounts receivable from Enron, which have been allowed as bankruptcy claims. These receivables have been adjusted to an estimated recovery value. The Company has received payments of $63 million from Enron affiliates for allowed bankruptcy claims during the 249 day period ended September 6, 2006. Subsequent to December 31, 2005, in conjunction with the initial closing for the sale of Prisma Energy, the Company received payments of $6 million for the outstanding balances on receivables for administrative and other services.

Historically, the internal funding structure for the development and/or acquisition of the Operating Companies was either through cash contributed by Enron to the Holding Companies, or through intercompany notes between Enron and the Holding Companies or the Operating Companies. The terms of the notes vary and in many instances the smaller intercompany transactions were non-interest bearing. Some of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

intercompany notes held by Enron were either partially or fully transferred to Prisma Energy in exchange for shares in conjunction with the transfer of the related Operating Companies.

Prisma Energy entered into a $1 billion credit agreement dated May 23, 2006, with AEIL consisting of Tranche A, a $600 million amortizing loan that matures on June 29, 2011, and Tranche B, a $400 million bullet loan that matures on June 27, 2013. Tranche A accrues interest at LIBOR + 3.5% or the rate established by the senior credit agreement agent as its base rate + 2.5%, and Tranche B accrues interest at LIBOR + 4.5% to 5.0% prior to Conversion date and LIBOR + 7.5% to 8.5% after Conversion date. Conversion date means the earlier of (a) May 23, 2008 (the second anniversary of the Closing Date of the credit agreement), or (b) the Early Conversion Date. The Early Conversion date means the date that is six months after a consent cannot be obtained for the Second Closing or the AEIL lenders determine in good faith that the Second Closing will not occur. The Closing Date under the credit agreement occurred on May 25, 2006, when AEIL purchased 49% of the Prisma Energy shares held by Enron. The Second Closing date is when the remaining shares of Prisma Energy held by Enron are purchased by AEIL under the terms of the Share Purchase Agreement. AEIL has certain pledges over the capital securities held by Prisma Energy and its subsidiaries. As of September 6, 2006, Prisma Energy has drawn $1 billion under this facility. The purpose of the credit agreement was to inject funds into Prisma Energy to allow a dividend to Enron (as part of PEI acquisition by AEIL) and to fund the Company’s minimum bid regarding the Promigas outstanding shares held by the affiliates of Enron as further described below.

In addition to the $727 million dividend of funds from the Credit Agreement, the Company paid dividends of $802 million to Enron from existing cash balances and cash flow generated from the operating companies during the 249-day period ended September 6, 2006.

Restrictive Covenants — The $1 billion credit agreement with AEIL includes numerous restrictive covenants for Prisma Energy, its wholly owned subsidiaries and in certain instances some of the Operating Companies, depending upon the specific covenant. A breach of any of these covenants could result in an acceleration of the debt. The Company was in compliance with all covenants during the 249-Day period ended September 6, 2006.


13.	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.

Long-Term Incentive Plans — Effective January 1, 2006, PEI adopted the provisions of FASB Statement No. 123(R), which requires the measurement and recognition of compensation expense for all share-based payment awards to employees and directors based on estimated fair values. The adoption of FASB Statement No. 123(R) did not have a material impact on the Company’s results of operations, cash flows or financial position. In 2004, PEI adopted a long-term incentive compensation plan (“Stock Incentive Plan”) that provides awards to certain directors, officers, and key employees of the Parent Company and its subsidiaries. The maximum number of stock units that can be awarded under the Stock Incentive Plan is 4 million stock units, and the number of stock units granted to any individual participant cannot exceed 2 million stock units. The Stock Incentive Plan allows for grants in the form of, or in any combination of stock options, stock appreciation rights, restricted stock awards, share units, and cash awards. The Compensation Committee of PEI’s board of directors administers the Stock Incentive Plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In 2006, Enron and certain of its subsidiaries signed a Share Purchase Agreement dated May 23, 2006 (and subsequently amended and restated by the Share Purchase Agreement dated June 9, 2006), with AEIL for the sale of 100% of the outstanding equity of PEI in a two-staged transaction, as further described in Note 1, Organization and Formation. The Stock Incentive Plan of PEI remained in place after the change in control of the Company.

The third party-developed “enterprise value” based model is a fair value based method of accounting for stock-based compensation that was used by PEI prior to January 1, 2006, and continued to be used to approximate the fair value of the stock options until such time as a third-party valuation of PEI was completed as a result of the change in control letter as of October 6, 2006, as described in detail below, which established a value of $32.05 per unit for PEI’s units effective May 1, 2006.

PEI has adopted the provisions of FASB Statement No. 123(R) using the modified prospective transition method. In accordance with this method, the consolidated financial statements as of and for the 249 day period ended September 6, 2006, reflect the impact of FASB Statement No. 123(R). Under the modified prospective transition method, share-based compensation expense for the 249 day period ended September 6, 2006, includes compensation expense for all share-based compensation awards granted prior to, but for which the requisite service had not yet been performed, as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of FASB Statement No. 123. Compensation cost for the portion of awards for which the requisite service has not been rendered that are outstanding as of the required effective date is recognized as the date the requisite service is rendered on or after the required effective date.

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 have time-based vesting and some of which have performance based vesting. For the units that will vest based on time, 93,159 units vest over a 36-month period from October 1, 2004, through September 30, 2007. The number of units that will vest based on performance is 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. None of the performance-based units will vest, unless the minimum performance goals set out in the grant agreements are attained and the maximum number of units that can vest is 419,170. If the target performance goals set out in the grant agreements are met, 279,446 units would vest. The performance goals under the performance-based grants were changed as a result of the acquisition of PEI, and the vesting schedules under these grants were extended. The estimated market price of each performance-and time-based unit on the grant date was $25 per unit.

PEI also granted share units in 2005. The time-based grant of 51,481 units vests over a 36-month period ending December 31, 2007. None of the performance-based units will vest, unless the minimum performance goals set out in the grant agreements are attained and the maximum number of units that can vest is 224,081. If the target performance goals set out in the grant agreements are met, 154,444 units would vest. The estimated market price of each performance- and time-based unit on the grant date was $27.00 per unit. In addition, 6,808 share unit grants were approved for PEI’s non-employee directors for 2005 to be issued upon the distribution of units of PEI pursuant to the Enron Plan of Reorganization. The awards granted in 2005 provide that, in the event of a change in control, these awards will be canceled and converted into awards under PEI’s Sales Incentive Plan, discussed below.

On May 22, 2006, an acknowledgement was signed by the Stock Incentive Plan participants and Enron Corp. to modify the Stock Incentive Plan that eliminated the discretion of the Compensation Committee to grant dividend equivalent units and instead provide that dividend equivalent rights would be granted with respect to the shares of common stock underlying the units (the “Acknowledgement”). This Acknowledgement also provided that dividend equivalent rights could be paid only in the form of additional units (and not in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

cash as previously provided). Under FASB Statement No. 123(R), the terms of the Acknowledgement resulted in a modification of the Stock Incentive Plan, because PEI was deemed under FASB Statement No. 123(R) to have issued a new instrument of equal or greater value than the previous instrument that existed. Thus, the awards granted under the Stock Incentive Plan were also modified and revalued as of May 22, 2006, the grant date of the dividend equivalent rights.

The dividend equivalent rights have the same vesting rights as the time- and performance-based share units that they are derived from and are classified as equity. Those dividend equivalent rights are included in the time- and performance-based shares activity tables below.

On May 25, 2006, AEIL acquired 49% of the outstanding shares of PEI from Enron and certain of its subsidiaries. AEIL subsequently acquired the remaining outstanding PEI shares on September 7, 2006. The closing of Stage 2 of the acquisition constituted a change of control under the Stock Incentive Plan, as a result of which the end of the performance period was changed to September 2006 and the vesting period of all of the performance-based awards made under the Stock Incentive Plan was extended by an additional nine months.

Compensation expense recognized for the Long-Term Incentive Plans is $12 million for the 249 day period ending September 6, 2006 Summarized time-based share unit award activity, for the 249 day period ended September 6, 2006, is as follows:


			Weighted-		Aggregate
			Average		Intrinsic
	Units		Grant Price		Value
					(In millions)

Beginning of Period, December 31, 2005		144,640	$	25.72	$	4
Granted		155,646		32.05		5
Exercised
Forfeited
Outstanding at Sept. 6, 2006		300,286	$	28.90	$	9
Exercisable at Sept. 6, 2006		153,895	$	28.52	$	4

Summarized performance-based share unit award activity, for the 249 days ended September 6, 2006, is as follows:


			Weighted-
			Average
			Grant
Performanced-Based Restated Units	Units		Price

Nonvested, Dec. 31, 2005		503,752	$	25.62
Granted		601,733		31.28
Exercised		—		—
Forfeited		—		—

Vested at Sept. 6, 2006		—	$	—

Nonvested at Sept. 6, 2006		1,105,485	$	28.70

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of additional information about share units that are outstanding and exercisable at September 6, 2006, is as follows:


					Weighted-Average
					Remaining
			Weighted-Average		Contractual Life
Share Units Outstanding	Units		Grant Price		(In Years)

Performance based		1,105,485	$	28.70		.47
Time based		300,286		28.90		.93

Total Values at Sept. 6, 2006		1,405,771	$	28.74		.58

As of September 6, 2006, there was $21 million of total unrecognized compensation cost related to nonvested units. This cost is expected to be recognized over a weighted-average period of .58 years.

As a Cayman Islands entity, the Company does not realize any tax benefits from the granting or exercising of these options.

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”). The excess of Enron’s realized value over defined threshold amounts, and the calendar year in which a change of control becomes effective, determines the amount to be distributed as Cash Awards (“Cash Award Fund”). Cash Awards vest 50% upon the effectiveness of a change of control and 50% on the first anniversary of such change in control. All vested Cash Awards have been and shall be settled and paid as soon as practicable after becoming vested.

In 2006, Enron signed a Share Purchase Agreement dated May 23, 2006 (and subsequently amended and restated by the Share Purchase Agreement dated June 9, 2006), with AEIL and PEI for the sale of 100% of the outstanding equity of PEI in a two-staged transaction, as further described in Note 1, Organization and Formation. The closing of Stage 2 of this transaction triggered a change in control under the Sales Incentive Plan. The Cash Award funds available for distribution under the Sales Incentive Plan in connection with the transaction are $84 million. Compensation expense recognized for the Sales Incentive Plan was $0 for the 249 day period ended September 6, 2006


14.	BENEFIT PLANS

Elektro Plans — Elektro sponsors two supplementary retirement and 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 plan was created, the existing participants were allowed to transfer to the new plan. Participants that transferred were given the right to receive a balanced benefit proportional to their years of participation in the PBSBP plan. Participants could elect to contribute to the ESPRP plan or to just retain their eligible benefits from the PBSBP plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other Plans — A subsidiary of the Company also participates in a multi-employer noncontributory defined benefit retirement plan that covers all of its employees in the Philippines. The projected benefit obligation, the fair value of plan assets, net periodic benefit cost, and employer contributions to this plan are insignificant (projected benefit obligation is $0.4 million as of December 31, 2005) due to the small number of participants. The Company provides a defined contribution benefit plan to all of its U.S.-based and expatriate employees. The plan was maintained through Enron. 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 benefit plans for its expatriate employees and 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.

Expense recognized for all of the Company’s benefit plans was $1 million for the 249 day period ended September 6, 2006.


15.	FAIR VALUE OF 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 approximate 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 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.

The Company has entered into various derivative transactions in order to hedge its exposure to commodity and interest rate risk and reflects all derivatives as either assets or liabilities on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective and qualifies for hedge accounting treatment are reflected in accumulated other comprehensive income and recognized in income when the hedged transaction occurs. The interest rate swaps are in place through the maturity of the long-term debt in 2015.

The ineffective portion of the interest rate swaps qualifying for hedge accounting starting in 2005 recognized as income during the 249 day period ended September 6, 2006 was $1 million.

PQP enters into agreements to hedge its exposure to fluctuations related to fuel prices. These derivatives did not qualify for hedge accounting treatment; therefore, income of $3 million was recognized during the 249 day period ended September 6, 2006.


16.	COMMITMENTS

Power Purchases — Since its privatization in July 1998, Elektro’s market has been supplied by pre-existing power purchase agreement obligations. Legislation subsequent to the privatization required that the volumes under these pre-existing contracts would decrease in 25% increments each year, starting on January 2003 through December 31, 2005. In order to cover its needs for 2003 and 2004, Elektro amended these contracts to cover the 2003 and 2004 decrease while guaranteeing 100% pass-through to its tariffs. The regulations did not allow amendments to the pre-existing contracts beyond December 31, 2004.

Earlier power sector models and regulations in Brazil established a phase-out transition from the regulated Initial Contracts to freely negotiated bilateral contracts. In a shift towards a more regulated environment, a new law was enacted during 2004 to establish rules and conditions for distribution companies to buy energy to comply with market obligations. The new law does not allow distribution companies to enter into freely negotiated bilateral contracts to buy energy except for contracts signed prior to enactment of the law. Among

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

other things, the new legislation requires that distribution companies are obligated to cover any short position through annual public auctions that are controlled and organized by the federal government.

The power purchase agreements resulting from these auctions are non-negotiable adhesion contracts that are regulated by the government in every aspect except for volume and price. The purchase price for the distribution company is established from the bidding process and is fully passed through to the customer. The distribution company notifies the federal government of the quantity it needs to purchase and the price is determined by offers by the generators and independent power producers. In the event the offer is lower than the demanded volume, the federal government holds other auctions to balance the supply and demand.

In order to mitigate load forecast uncertainties, distribution companies have the right to relinquish up to 4% of each contracted volume once a year without penalty. A long position of up to 3% of a distribution company’s total load is allowed to be fully passed-through to tariffs. If the distribution company foresees that it becomes short in the following year, it may buy additional energy of up to 1% of its total load of the previous year at an annual auction with full tariff pass-through, or it may buy energy through the wholesale market mechanism. Through this mechanism, distribution companies can purchase energy from other distribution companies that have a surplus of energy.

If a distribution company is short due to a miscalculation of the area of service demand in relation to its load therefore not contracting a sufficient volume, it pays the higher price of (i) the prevailing spot price and (ii) a reference price determined in the auction that set the price. Purchasing energy to remedy such short positions subjects the distribution company to penalties.

In order to comply with the new regulations, Elektro purchased energy in the auctions to replace the pre-existing contracts and to cover the estimated market growth for the eight-year term contracts. In addition, in order to avoid downside penalties for underestimating the future load, a percentage was added to the expected volume. Such additional volume may be reduced via the 4% per contract rule stated above if not needed.

Future commitments under these power purchase contracts as of December 31, 2005, are as follows:


	(U.S. dollars
	in millions)

2006	$	469
2007		462
2008		468
2009		374
2010		398
Thereafter		3,347

Total	$	5,518

Fuel Purchases — Trakya has signed a take-or-pay agreement with the Turkish state-owned monopoly for their supply of gas. The agreement has an initial term ending in October 2014 and may be extended to 2019 subject to the availability of gas. The take-or-pay obligation is based on an approximate level of gas consumption that would be required for Trakya to meet most of its annual net generation requirements under its energy sales agreement.

Nowa Sarzyna has a take-or-pay fuel supply agreement with the Polish state-owned oil and gas monopoly with a 20-year term through March 2018. Nowa Sarzyna is obligated to pay for a minimum annual contracted off-take equal to 90% of the minimum quantity of 180 million cubic meters per year.

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TBS has a gas supply agreement that contains a take-or-pay provision for 55% of the daily contract quantity with a five-year make up period. The maximum daily contract quantity of the contract is 83,665 MMBtu/day. The contract expires in May 2019.

PQP has a long-term fuel supply agreement for heavy fuel oil. The contract expires in February 2013.

Expense recognized under these fuel purchase agreements was $124 million in the 249 day period ended September 6, 2006. Future commitments under these fuel purchase agreements as of December 31, 2005, are as follows:


	(U.S. dollars
	in millions)

2006	$	287
2007		295
2008		283
2009		291
2010		282
Thereafter		2,482

Total	$	3,920

Gas Transportation Agreement — TBS has a gas transportation agreement with GTB with a 25-year term ending September 27, 2027. The maximum daily transported quantity of the contract is 80,762 MMBtu/day with 100% ship-or-pay. Estimated payments to be made under this agreement are $5 million for each of the next five years and $69 million thereafter. The total future commitments under this agreement are $94 million.

Equipment — EPE signed two nine-year contracts for the supply of parts and maintenance services for its combustion turbines. Estimated payments to be made under these contracts are $17 million in 2006, $1 million in 2007, $11 million in 2008, $2 million in 2009, $1 million in 2010 and $43 million thereafter. The total future commitments under this agreement are $75 million.

Other — Several of the Company’s subsidiaries have entered into various long-term contracts. These contracts are mainly for office rent, administration, operation and commercial support. Estimated payments to be made under these contracts are $3 million in 2006, $3 million in 2007, $3 million in 2008, $2 million in 2009, $1 million in 2010 and $4 million thereafter. The total future commitments under this agreement are $16 million.


17.	CONTINGENCIES

Letters of Credit — In the normal course of business, Prisma Energy and certain of its 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 subsidiaries’ intended business purpose. As of December 31, 2005, $51 million in letters of credit, bank guarantees, and performance bonds was outstanding, of which $47 million was fully cash collateralized.

Enron had historically provided guarantees and other credit support for some of the Operating Companies. As discussed in Note 8, defaults under several of the financing agreements were owed through additional financial restrictions placed on the Operating Companies. In other instances, Prisma Energy will have to replace the credit support as further discussed below.

Under a sponsor undertaking agreement, Prisma Energy is obligated to provide, or cause to be provided, all performance bonds, letters of credit, or guarantees required under the service agreement between Accroven

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and its customer, PDVSA-Gas. In February 2006, Prisma Energy’s board of directors approved the execution of a reimbursement agreement with a bank to issue four new letters of credit totaling approximately $21 million. Accroven is required to reimburse Prisma Energy for any payment made in connection with the letters of credit.

Enron financed part of its equity investment in Corinto through an arrangement with MARAD. MARAD required Enron to purchase Corinto’s long-term debt with MARAD (less any amounts already deposited in a reserve fund) in the event that Enron’s corporate rating fell to BB plus or below. MARAD filed a proof of claim against Enron alleging Enron’s breach of the purchase agreement because Enron’s rating fell below BB plus. This issue is still under negotiation as part of the Enron bankruptcy claims process. The Company is committed to reimburse Enron for any amounts up to $11 million that Enron pays related to the MARAD claim. The Company has rights to recover a portion of any amounts paid to Enron from the other shareholders of Corinto, but there is no assurance that these amounts would be collected. The outstanding balance on the Corinto debt (less amounts in the reserve fund — approximately $6 million) as of December 31, 2005, is $20 million. The claim is currently in the discovery phase; however, the Company does not believe that the currently expected outcome of this claim will have a material adverse effect on its financial condition, results of operations, or liquidity.

TBG and its shareholders were provided shareholder parent undertakings. The guaranty provided by one of the Company’s subsidiaries was in the total amount of approximately $17 million. However, TBG cannot call more than approximately $4 million under the guaranty, since the Company has already complied with its capital commitment obligations. The remaining $4 million under the guaranty can be called only under limited circumstances. Transredes provided a similar shareholder parent undertaking for TBG and its shareholders. The remaining guaranty for Transredes is approximately $12 million. The Company does not believe that the exposure under these guarantees will have a material adverse effect on its financial condition, results of operations, or liquidity.

Political Matters:

Turkey — Since the election of the current Turkish government in November 2002, Trakya and the other Turkish thermal power projects have been under pressure from the Ministry of Energy and Natural Resource (“MENR”) to renegotiate their current contracts. The primary aim of the MENR is to reduce what it views as excess return paid to the projects by the State Wholesale Electricity and Trading Company under the existing power purchase agreements. Prisma Energy and the other shareholders of Trakya developed a proposal and presented it to the MENR in April 2006. The MENR has not formally responded to the proposal, but even if accepted, the implementation of the restructuring is not expected to occur before the end of 2007 due to the time that will be required for a coordinated interaction among multiple government agencies. The Company does not believe that the currently expected outcome under the restructuring will have a material adverse effect on its financial conditions, results of operations, or liquidity.

Trakya is in negotiations with MENR regarding a decrease in Trakya’s tariff due to a decrease in the Turkish statutory tax rate. The Company has accrued approximately $5 million related to this issue and does not believe that the currently expected outcome of these negotiations will materially exceed this amount or would have a material adverse effect on its financial conditions, results of operations, or liquidity.

Bolivia — On May 1, 2006, the Bolivian government purported to nationalize the hydrocarbons industry under Supreme Decree No. 28701. The Decree, among other things, anticipates, through future action, the nationalization of the shares necessary for the state-run oil and gas company, Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), to control at least 50% plus one share of certain named companies, including Transredes. Further actions would be necessary for the government to expropriate the shares in Transredes held by the Company. No significant impact on operations at Transredes, GTB and TBG has occurred since the purported nationalization. The Company is currently evaluating the commercial impact that these recent

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political events in Bolivia could have on Cuiaba in Brazil. An interim gas supply agreement (GSA) between TBS and YPFB was executed on June 22, 2007, which contemplates a reduction in the gas supply to Cuiaba through 2009. Negotiations for a definitive GSA, as well as negotiations with Furnas (Cuiaba’s off-taker) and ANEEL are ongoing. The Company does not believe that the currently expected outcome of these events will have a material adverse effect on its business, financial condition, results of operations, or liquidity, but the final outcome of these events remains uncertain.

BLM — Panama’s National Dispatch Center (“NDC”) has taken the position that BLM’s limited fuel inventory in the months of January and February 2006, in addition to the fact that the combined cycle unit was taken off-line for almost a week in March 2006 as a result of a lightning strike, translates into a non-compliance of BLM’s availability commitments under its capacity reserve contracts. Therefore, the NDC reversed BLM’s reserve capacity sales for the months of January through March, and disallowed BLM from selling reserve capacity beginning May 11, 2006. BLM believes the position of the NDC is in contravention of the regulations, including rulings issued by the NDC in similar cases last year. BLM has presented its arguments to the NDC, the regulator, and members of the electricity commission formed by the office of the Presidency of Panama, and has filed a formal appeal of NDC’s decision before the regulator. BLM is currently awaiting the ruling. Pending its final decision on the merits, the regulator ordered the NDC to temporarily reinstate BLM’s reserve capacity contracts on June 14, 2006. If the regulator ultimately does not rule in favor of BLM, this issue could result in a material adverse effect under BLM’s financing and a potential default of BLM’s loans. On March 14, 2007, the Company sold its 51% indirect interest in BLM.

Litigation:

The Company’s subsidiaries are involved in a number of legal proceedings, mostly civil, regulatory, contractual, tax, and labor, and personal injury claims and suits, in the normal course of business. The Company’s subsidiaries have accrued for litigation and claims in accordance with SFAS 5, Accounting for Contingencies. As of December 31, 2005, the Company has accrued $81 million for claims and suits. This amount has been determined based on managements’ assessment of prevailing or losing in some of the particular cases, and based on the Company’s general experience with these particular types of cases. Although the ultimate outcome of such matters cannot be predicted with certainty, the Company 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 the Company’s financial statements. It is possible, however, that some matters could be decided unfavorably to the Company and that the Company could be required to pay damages or to make expenditures in amounts that could be material, but cannot be estimated at September 6, 2006.

Elektro — As a Brazilian power distribution company, Elektro is a party to a number of lawsuits. The nature of these suits can generally be described in three categories. Civil cases include suits involving the suspension of power to nonpaying customers, suits involving workers or the public that incur 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, and social integration taxes. Labor suits include various issues, such as labor accidents, overtime calculations, vacation issues, hazardous work and severance payments. The total number of suits was more than 4,000.

Elektro has three separate ongoing lawsuits stemming from lawsuits filed in 1999 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 payable by it. These cases are currently pending. The Company has accrued approximately $39 million related to this issue and does not believe that the currently expected outcome under these lawsuits will exceed this amount or will have a material adverse effect on its financial condition, results of operations, or liquidity.

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Promigas — A class action suit is pending against Promigas whereby plaintiffs seek to recover $5 million in damages resulting from a pipeline explosion caused by terrorists in October 2001. While the matter is still in the initial stage, the Company does not believe that the currently expected outcome will have a material adverse effect on its financial condition, results of operations, or liquidity. No reserves in respect to this claim have been established.

SECLP Limited Partnership — In 1995, a demand for arbitration was filed against SECLP in connection with SECLP’s alleged breach of a settlement agreement arising from a nuisance dispute over SECLP’s power plant in Puerto Plata, Dominican Republic, which was decided in favor of the plaintiff. In August 2006, a Dominican Republic appeals court ruled against SECLP, upholding the award of approximately $11 million, including accrued interest and in March 2009 the Dominican Republic Supreme Court rejected SECLP’s appeal and upheld the lower court’s ruling. The final amount of the award is currently being determined. The Company has accrued $10 million for this claim and does not believe the currently expected outcome will have a material adverse effect on its financial condition, results of operations, or liquidity.


18.	RISKS AND UNCERTAINTIES

Regulatory, Political and Operations Risk — The revenues of some of the Operating Companies are dependent on tariffs or other regulatory authorities to periodically review the prices such businesses charge customers and the other terms and conditions under which services and products are offered. Other Operating Companies rely on long-term contracts with governmental or quasi-governmental entities for all or substantially all of their revenues. Past and potential regulatory intervention and political pressures may lead to tariffs that are not compensatory or otherwise undermine the value of the long-term contracts entered into by the Company.

The political and social conditions in many of the geographic regions where AEI’s businesses are located, including Latin America, present many risks, such as civil strife, guerilla activities, insurrection, border disputes, leadership succession, turmoil, war, expropriation, and nationalization.

Concentration of Customers and Suppliers — Many of the Operating Companies individually rely upon one or a limited number of customers that provide all or substantially all of the business’ revenue. Many of these businesses also rely on a limited number of suppliers to provide natural gas, liquid fuel, LPG, and other services required for the operation of the business. In certain cases, the financial performance of these Operating Companies is dependent upon the continued performance by a customer or supplier under their long-term purchase or supply agreements. One customer under long-term power purchase agreements accounted for 13% of the Company’s consolidated revenues in 2006. The Operating Company that sold power to this customer is part of the Power Generation segment of the Company. The Company’s reportable segments are discussed further in Note 19. The loss of, or a significant modification of, one or more of the long-term purchase or supply agreements could have a material adverse impact on the Company’s results of operations and financial condition.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


19.	SEGMENT AND GEOGRAPHIC INFORMATION

The Company manages, operates and owns interest in energy infrastructure businesses through a diversified portfolio of companies worldwide. Historically, it has not reported segment information as it was a private entity. In accordance with Statement of Financial Accounting Standards No. 131 “Financial Reporting for Segments of a Business Enterprise” (FAS 131), we are presenting segment information for the first time.

As a result of the purchase of the Company by AEI closing on September 6, 2006, the segment information presented below reflects those segments reported by AEI. Such segments are based primarily on both PEI and AEI’s services and customers, operations and production processes, cost structure and channels of distribution and regulatory environment. The operating segments reported below are the segments of AEI for which separate financial data is available and for which operating results are evaluated regularly by AEI’s Chief Executive Officer, the Chief Financial Officer and the Chief Operating Officer, who together are the Chief Operating Decision Maker, in deciding how to allocate resources and in assessing performance of AEI. Due to the timing of acquisitions and the nature of our historical operations, certain segments presented below do not reflect results. The Company has presented five reportable segments: Power Distribution, Power Generation, Natural Gas Transportation, Natural Gas Distribution, and Retail Fuel as described below.

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 our concession agreements, our electric distribution companies are entitled to a full pass-through of non-controllable 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 — The 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 our 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 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 business distributes and sells gasoline, LPG and CNG. These businesses service both owned and affiliated retail outlets with a fleet of bulk-fuel distribution vehicles. 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 and operating expenses (including depreciation and amortization, taxes other than income, and losses on disposition of assets). Operating income also includes equity in earnings of unconsolidated affiliates due to our integral operations in these affiliates.

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Headquarter and Other expenses include corporate interest, general and administrative expenses related to corporate staff functions and/or initiatives — primarily executive management, finance, legal, human resources, information systems, staff incentive payments and certain businesses which are immaterial for the purposes of separate segment disclosure. It also includes the effects of eliminating transactions between segments including certain generation facilities, on one side, and distributors and/or gas services on the other, and inter-company interest and management fee arrangements between the operating segments and corporate.

The table below presents Revenues by business segment. Segment eliminations for intercompany transactions between segments are included in Headquarters and Other. There are no Natural Gas Distribution segment revenues as this segment relates primarily to Promigas, which is an equity investment (U.S. dollars in millions):


	249 Days Ended
	Sept. 6, 2006
	(In millions)

Power Distribution	$	735
Power Generation		632
Natural Gas Transportation		53
Natural Gas Distribution		—
Retail Fuel		47
Headquarter and Other		(53	)

Total Revenues	$	1,414

The table below presents summarized financial data about our reportable segments:


							Nat.			Nat.
	Power			Power			Gas.			Gas.		Retail			Headquarters
249 Days Ended Sept. 6, 2006	Dist.			Gen.			Trans.			Dist.		Fuel			and Other			Total
	(In millions)

Operating income	$	228		$	118		$	43		$	3	$	11		$	(38	)	$	365
Equity in earnings		—			4			17			3		4			7			35
Depreciation/Amortization		25			29			5			—		3			1			63
Interest income		48			19			4			—		—			11			82
Interest expense		(59	)		(34	)		(15	)		—		(6	)		18			(96	)
Capital expenditures		(67	)		(1	)		—			—		(4	)		—			(72	)

The table below presents revenues of the Company’s consolidated subsidiaries by geographical location for the 249 days ended September 6, 2006. 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.

F-125

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Revenues
	249 Days Ended
	Sept. 6, 2006

Brazil	$	875
Dominican Republic		100
Panama		78
Guatemala		97
Turkey		233
Other		31

Total	$	1,414


20.	SUBSEQUENT EVENTS

Acquisition of PEI — On October 12, 2005, Ashmore Energy International Limited (“AEIL,” formerly known as Elektra Energy International Limited) was formed by Ashmore Investment Management Limited (“Ashmore”) to act as a holding company for certain energy-related assets acquired by the Ashmore Funds, including Elektra, and to act as a platform to acquire PEI and the 15 operating businesses in which PEI had a substantive interest. In 2006, AEIL acquired PEI from Enron Corp. and certain of its subsidiaries (collectively, “Enron”) 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 51% of the economic interest.

Promigas — On May 23, 2006, the Company dividended a Holding Company that holds shares representing a 33.04% ownership interest in Promigas to Enron. In accordance with the Share Purchase Agreement between Enron, AEIL, and PEI, Enron commenced a public auction of these Promigas shares through the Colombian Stock Exchange shortly after the Second Closing. In December 2006, the Company purchased these shares based on the terms established in a pre-bid agreement along with an additional 9.94% ownership interest for an aggregate amount of $510 million.

The Company was required to maintain a portion of the proceeds received from the $1 billion loan in a separate cash collateral account, which were used solely for the purpose of funding the acquisition of the Promigas shares.

SECLP — On February 27, 2007, AEI increased its ownership interest in SECLP from 85% to 100% through an acquisition of the interest held by its joint venture partners for approximately $11 million, subject to adjustments based upon the actual net assets of the businesses at the acquisition date. In conjunction with AEI’s purchase of SECLP, AEI also increased its ownership interest in Smith/Enron O&M Limited Partnership from 50% to 100% through an acquisition of the interest held by its joint venture partners for approximately $3 million, subject to adjustments based upon the actual net assets of the businesses at the acquisition date.

F-126

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Elektro — In December 2006, the Brazilian National Social Security Institute notified Elektro about several labor and pension issues raised during a two-year inspection. The penalty amount notified is approximately $24 million. The Company believes it has a meritorious defense to this claim and will defend it vigorously; however, there can be no assurance that it will be successful in its efforts. No reserves in respect to this claim have been established.

Trakya — During 2005, Trakya was subject to a formal tax investigation covering the period July 2003 to September 2005. In May 2006 (following the completion of the tax investigation), Trakya was presented with summary reports assessing significant additional tax payments plus interest and penalties. Trakya applied to the Reconciliation Committee of Ministry of Finance and, on November 22, 2006, reached an agreement with the Turkish tax authorities that resulted in a net payment of TRY 12 million including interest in full settlement for all tax issues raised in the tax investigation. Consequently, the Company incurred additional taxes and interest in the amount of U.S. $15 million in December 2006.

Sociedad de Inversiones en Energía (SIE) — On December 5, 2006, Promigas signed an Integration Agreement and a Shareholders Agreement in which it agreed to exchange its shares of Gazel S.A., which is 100% owned by Promigas, for an incremental 16.81% equity participation in Sociedad de Inversiones en Energía (“SIE”). After the transaction is completed, Promigas will own a 54% direct interest in SIE. Promigas has historically accounted for SIE under the equity method of accounting. Once the transaction is consummated, Promigas will consolidate SIE. The transaction is subject to regulatory approval.

PQP — In August and September 2007, AEI acquired a 25% additional indirect interest in PQP by exercising its right of first refusal under an agreement with subsidiaries of Globeleq Ltd. Subsequently, AEI acquired an additional 20% indirect interest in PQP from Centrans Energy Services (“Centrans”). Upon closing of the transactions, AEI increased its indirect ownership in PQP from 55% to 100%.

Corinto — In August and September, AEI acquired a 30% indirect interest in Corinto by exercising its right of first refusal under an agreement with subsidiaries of Globeleq Ltd. Subsequently, AEI sold half of the interest acquired through the right of first refusal exercise to Centrans. Upon closing of the transactions, AEI increased its indirect ownership in Corinto from 35% to 50%.

Vengas — On October 4, 2007, AEI and Petroleos de Venezuela (“PDVSA”) signed a purchase agreement pursuant to which AEI agreed to sell its entire share in Vengas S.A. (“Vengas”) to PDVSA GAS S.A. The transaction is expected to close in the fourth quarter of 2007.

Cuiaba Integrated Project — On October 1, 2007, the Company received a notice from Furnas purporting to terminate the power purchase agreement as a result of the current lack of gas supply from Bolivia. The Company disagrees with Furnas’ position and is vigorously opposing Furnas’ efforts to terminate the agreement. If the Company is unable to secure an adequate supply of gas to EPE or find acceptable alternative sources of fuel supply, or the Company is unable to satisfactorily resolve our dispute with Furnas, the operations of the Cuiaba Integrated Project will be materially adversely effected. Under these circumstances, there will be a corresponding impact on the Company’s financial performance and cash flows. The Company is unable, at this time, to predict the ultimate impact or duration of the current issues at the Cuiaba Integrated Project.

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. Legislation has recently been passed that would allow for power generators producing under long-term contracts to voluntarily terminate their contracts subject to payment of compensation for stranded costs. The legislation became effective as of August 4, 2007. Stranded costs compensation would be based upon the capital expenditures incurred before May 1, 2004, which could not be recovered from future sales in the free market, and would be paid in quarterly installments. The maximum compensation attributable to Nowa Sarzyna under the current proposal would be 1.12 billion Polish zloty (approximately $384 million).

F-127

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The European Commission recently completed the formal proceedings to investigate whether the Polish government’s plans and whether the long-term contracts themselves constitute illegal state aid. Pursuant to the European Commission’s decision dated September 25, 2007, long-term contracts were declared as illegal state aid. In the same decision the above-mentioned Polish legislation allowing for termination of long-term contracts upon compensation was declared to be a state aid measure compatible with relevant EU legislation. In the decision Poland has been obliged to terminate the long-term contracts by the end of 2007 (such termination becoming effective as of April 1, 2008) and the entities which voluntarily terminate their contracts within that period will not be obliged to return the aid already received. The entities that do not elect to terminate their long-term contracts will be obliged to return state aid received after May 1, 2004 and it is possible that they would not be entitled to continue the performance of their long-term contracts. The Company is still analyzing the legislation as well as its economical consequences, before deciding whether it will voluntarily terminate its contract. The Company believes that, if it decides to terminate the long-term contract in line with the above legislation, the currently expected outcome under the above restructuring will not have any material adverse effect on its financial condition, results of operations, or liquidity.

Elektro — During Elektro’s August 2007 tariff review, Elektro’s tariff for residential and small commercial customers was reduced by 20.65% and the tariffs for large customers were reduced between 13.57% and 21.62% depending on their load modulation. The average reduction considering all customer segments was 17.2%.

******

F-128


		Page

ITEM 13.	Defaults, Dividend Arrearages and Delinquencies		164
ITEM 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds		165
ITEM 15.	Controls and Procedures		166
ITEM 16A.	Audit Committee Financial Expert		167
ITEM 16B.	Code of Ethics		168
ITEM 16C.	Principal Accountant Fees and Services		169
ITEM 16D.	Exemptions from the Listing Standards for Audit Committees		170
ITEM 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		171
ITEM 17.	Financial Statements		172
ITEM 18.	Financial Statements		173
ITEM 19.	Exhibits		174
EX-1.1: AMENDED AND RESTATED ARTICLES OF ASSOCIATION OF AEI
EX-1.2: AMENDED AND RESTATED MEMORANDUM OF ASSOCIATION OF AEI
EX-2.1: AMENDED AND RESTATED REGISTRATION RIGHTS AGREEMENT
EX-4.1: CREDIT AGREEMENT
EX-4.2: INCENTIVE PLAN
EX-4.3: SALES INCENTIVE PLAN
EX-4.4: STOCK INCENTIVE PLAN
EX-4.5: DISTRIBUTION CONCESSION CONTRACT
EX-4.6: DISTRIBUTION FIRST AMENDMENT TO CONCESSION CONTRACT
EX-4.7: DISTRIBUTION SECOND AMENDMENT TO CONCESSION CONTRACT
EX-4.8: DISTRIBUTION THIRD AMENDMENT TO CONCESSION AGREEMENT
EX-4.9: SECOND AMENDED AND RESTATED SHAREHOLDERS AGREEMENT
EX-4.10: 2006 RESTRICTED STOCK AGREEMENT
EX-8.1: LIST OF SUBSIDIARIES
EX-15.1: CONSENT OF DELOITTE & TOUCHE LLP


TETAŞ		Türkiye Elektrik Ticaret ve Taahut A.S., the Turkish state-run electricity contracting and trading company

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

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

Tongda		Tongda Energy Private Limited, our Chinese Natural Gas Distribution business

Total		Total S.A., a French integrated oil and gas company

Trakya		Trakya Elektrik Uretim ve Ticaret A.S., our Turkish power plant

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 Petroliferos Fiscales Bolivianos, the Bolivian state-owned energy company


			Page

	Introduction			iii
	Business of AEI			iii
	Non-GAAP Financial Measures			iv
	Presentation of Information			vi
	Forward Looking Statements			vii
	Glossary of Technical Terms			viii
	Glossary of Defined Terms			x
ITEM 1.	Identity of Directors, Senior Management and Advisers			1
	A.	Directors and Senior Management		1
	B.	Advisers		1
	C.	Auditors		1
ITEM 2.	Offer Statistics and Expected Timetable			2
ITEM 3.	Key Information			3
	A.	Selected Financial Data		3
	B.	Capitalization and Indebtedness		10
	C.	Reasons for the offer and use of proceeds		10
	D.	Risk Factors		11
ITEM 4.	Information on the Company			27
	A.	History and Development of the Company		27
	B.	Business Overview		31
	C.	Organizational Structure		84
	D.	Property, Plant and Equipment		87
ITEM 4A.	Unresolved Staff Comments			89
ITEM 5.	Operating and Financial Review and Prospects			90
	A.	Operating Results		101
	B.	Liquidity and Capital Resources		127
	C.	Research and Development, Patents and Licenses, Etc.		134
	D.	Trend Information		134
	E.	Off-balance Sheet Arrangements		136
	F.	Tabular Disclosure of Contra ctual Obligations		137
ITEM 6.	Directors, Senior Management and Employees			138
	A.	Directors and Senior Management		138
	B.	Compensation		142
	C.	Board Practices		142
	D.	Employees		146
	E.	Share Ownership		146
ITEM 7.	Major Shareholders and Related Party Transactions			150
	A.	Major Shareholders		150
	B.	Related Party Transactions		150
	C.	Interests of Experts and Counsel		151
ITEM 8.	Financial Information			152
	A.	Consolidated Statements and Other Financial Information		152
	B.	Significant Changes		152
ITEM 9.	The Offer and Listing			153
	A.	Offer and Listing Details		153
	B.	Plan of Distribution		153
	C.	Markets		153
	D.	Selling Shareholders		153
	E.	Dilution		153
	F.	Expenses of the Issue		153
ITEM 10.	Additional Information			154
	A.	Share Capital		154
	B.	Memorandum and Articles of Association		154
	C.	Material Contracts		156
	D.	Exchange Controls		158
	E.	Taxation		158
	F.	Dividends and Paying Agents		160
	G.	Statement by Experts		160
	H.	Documents on Display		160
	I.	Subsidiary Information		160
ITEM 11.	Quantitative and Qualitative Disclosures about Market Risk			161
ITEM 12.	Description of Securities other than Equity Securities			163


(1)		We acquired our 90.00% interest in EDEN in 2007. The transaction is subject to local anti-trust approval. For additional details on the acquisition, see “Item 4. Information on the Company — A. History and Development.”

(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)		On November 28, 2008, we acquired a 28.00% equity interest in Emgasud. On December 23, 2008 we made a second capital contribution, thereby increasing our ownership interest to 31.89%.

(4)		On January 2, 2008, Promigas contributed its ownership interests in its wholly-owned subsidiary Gazel to SIE in exchange for additional shares of SIE. SIE subsequently transferred Gazel to its subsidiary Terpel. We currently own 24.95% of SIE-Terpel and 24.95% of SIE-Gazel.


	Page

Unaudited Condensed Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007		F-2
Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2007		F-3
Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007		F-4
Notes to Condensed Consolidated Financial Statements as of and for the nine months ended September 30, 2008 and 2007		F-5


	Page

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		F-35
Consolidated Balance Sheets as of December 31, 2007 and 2006		F-36
Consolidated Statements of Operations for the years ended December 31, 2007 and 2006		F-37
Consolidated Statements of Cash Flows for the years ended December 31, 2007 and 2006		F-38
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2007 and 2006		F-39
Notes to Consolidated Financial Statements		F-40
Schedule II Valuation and Qualifying Accounts		F-94


	Page

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		F-95
Consolidated Statement of Income for the 249-Day period ended September 6, 2006		F-96
Consolidated Statement of Shareholders’ Equity for the 249-Day period ended September 6, 2006		F-97
Consolidated Statement of Cash Flows for the 249-Day period ended September 6, 2006		F-98
Notes to Consolidated Financial Statements		F-99


			Additions						Deductions
	Balance at		Charged
	Beginning		to Costs									Balance at
	of the		and		Translation		Acquisitions		Amounts			the End of
Million of Dollars (U.S.)	Period		Expenses		Adjustment		of Business		Written of			the Period

Allowance for lease receivables:
For the year ended December 31, 2006	$	—	$	—	$	—	$	—	$	—		$	—
For the year ended December 31, 2007		—		40		—		—		—			40

Allowance for accounts receivable:
For the year ended December 31, 2006	$	5	$	5	$	—	$	35	$	(6	)	$	39
For the year ended December 31, 2007		39		9		5		5		(12	)		46