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As filed with the Securities and Exchange Commission on October 14, 2009

Registration No. 333-161420

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 3

Form F-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

AEI

(Exact name of Registrant as specified in its charter)


Cayman Islands (State or other jurisdiction of incorporation or organization)		4931 (Primary Standard Industrial Classification Code Number)		98-0405613 (I.R.S. Employer Identification Number)

AEI

Clifton House

75 Fort Street

P.O. Box 190GT

George Town, Grand Cayman

Cayman Islands

(345) 949-4900

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

AEI Services LLC

700 Milam, Suite 700

Houston, TX 77002

Attn: General Counsel

(713) 345-5200

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:


G. David Brinton Jonathan Zonis Clifford Chance US LLP 31 West 52^nd Street New York, New York 10019 (212) 878-8000		Robert B. Williams Milbank, Tweed, Hadley & McCloy LLP 1 Chase Manhattan Plaza New York, New York 10005 (212) 530-5000

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE


	Proposed
	Maximum
	Aggregate	Amount of
Title of Each Class of Securities to be Registered	Offering Price⁽¹⁾⁽²⁾	Registration Fee⁽³⁾

Ordinary shares $0.002 par value	$862,500,000	$48,127.50


(1)		Includes offering price of shares which the underwriters have the option to purchase.
(2)		Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933, as amended.
(3)		Previously paid.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED OCTOBER 14, 2009

50,000,000 Ordinary Shares

This is an initial public offering of the ordinary shares of AEI. We are offering 16,666,667 ordinary shares, and the selling shareholders are offering 33,333,333 ordinary shares. We will not receive any of the proceeds from the ordinary shares sold by the selling shareholders.

Prior to this offering, there has been no public market for our ordinary shares. The initial public offering price of the ordinary shares is expected to be between $14.00 and $16.00 per share. Our ordinary shares have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol “AEI.”

Our ordinary shares are registered pursuant to Section 12(g) of the Securities Exchange Act of 1934, as amended, pursuant to a registration statement on Form 20-F which became effective on March 31, 2009.

The underwriters have the option to purchase up to an additional 7,500,000 shares from the selling shareholders at the initial public offering price less the underwriting discounts and commissions.

Investing in our ordinary shares involves risks. See “Risk Factors” on page 11.

Underwriting

Proceeds to

Discounts and

Proceeds to

Selling

Price to Public

Commissions

Issuer

Shareholders

Per Share

Total

Delivery of the ordinary shares will be made on or about , 2009.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


Joint Global Coordinators		Joint Bookrunners


Goldman, Sachs & Co.	Credit Suisse	Citi	J.P. Morgan

Co-Managers


Banco Itaú	Deutsche Bank Securities	Morgan Stanley	UBS Investment Bank

The date of this prospectus is , 2009

TABLE OF CONTENTS


	Page

Prospectus Summary		1
The Offering		6
Summary Historical Financial Data		8
Risk Factors		11
Non-GAAP Financial Measures		26
Forward-Looking Statements		27
Use of Proceeds		28
Dividend Policy		29
Capitalization		30
Dilution		31
Exchange Rates		32
History and Development		33
Selected Consolidated Financial Data		35
Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Business		93
Economic and Regulatory Aspects of the Countries Where We Do Business		154
Environmental Considerations		165
Management		166
Principal and Selling Shareholders		177
Related Party Transactions		180
Description of Share Capital		181
Ordinary Shares Eligible for Future Sale		184
Taxation		186
Underwriting		189
Conflict of Interest		191
Enforcement of Civil Liabilities		199
Legal Matters		200
Experts		201
Where You Can Find More Information		202
Glossary of Technical Terms		203
Glossary of Defined Terms		205
Index to the Financial Statements		F-1
Unaudited Proportional Financial Metrics		A-1
Unaudited Reconciliation of Non-GAAP Measures		A-2
EX-1.1
EX-4.1
EX-5.1
EX-8.2
EX-10.11
EX-23.1

Through and including , 2009 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to sell only the shares offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

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PROSPECTUS SUMMARY

This summary highlights selected information about us and our ordinary shares that we and the selling shareholders are offering. Before investing in the ordinary shares, you should read this entire prospectus carefully for a more complete understanding of our business and this offering, including our audited consolidated financial statements and the related notes, and the sections entitled “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus. In this prospectus, the terms “AEI,” “we,” “us,” “our” and “our company” means AEI and its subsidiaries, unless otherwise indicated. Capitalized terms are defined in the “Glossary of Defined Terms” and technical terms are defined in the “Glossary of Technical Terms” included elsewhere in this prospectus.

Our Business

We own and operate essential energy infrastructure assets in emerging markets. We operate in 19 countries in Latin America, Central and Eastern Europe and Asia in Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel. We operate or have joint control of more than 50 businesses and have investments in more than ten others. Our businesses are diversified across the following five business segments (information is as of June 30, 2009 unless otherwise indicated):

For the year ended December 31, 2008, we generated consolidated operating income of $813 million, net income attributable to AEI of $158 million and Adjusted EBITDA of $1,044 million. For the six months ended June 30, 2009, we generated consolidated operating income of $413 million, net income attributable to AEI of $168 million and Adjusted EBITDA of $552 million. The following 2008 Adjusted EBITDA charts by country and by segment are based on our 2008 audited financial statements, included elsewhere in this prospectus.


⁽¹⁾		As a percentage of 2008 Adjusted EBITDA excluding Headquarters and Other. See “Non-GAAP Financial Measures” for the definition of Adjusted EBITDA and “Selected Financial Data” for the reconciliation of Adjusted EBITDA to GAAP measures.

We exclusively focus on emerging markets because they have higher rates of GDP growth as well as low base levels of per capita energy consumption compared to developed economies. We believe that growth in our markets will drive increases in overall and per capita energy consumption and require significant additional investments in energy infrastructure assets creating investment opportunities with attractive rates of return. Emerging markets growth is primarily driven by industrialization and urbanization. Global Insight, a leading global source of economic information, is predicting annual growth of 5.8% for countries which are not members of the Organization for Economic Cooperation and Development, or OECD, for the period 2010-2019 versus 2.3% for OECD countries over the same period.

Our Competitive Strengths

We believe that the following competitive strengths distinguish us from our competitors and are critical to the continued successful execution of our strategy. You should read this discussion of our competitive strengths in conjunction with our discussion in “—Competitive Challenges and Summary Risk Factors” below and in “Business—Our Competitive Strengths.”

Exclusive focus in emerging markets.

We focus on these markets because we believe they have greater growth in energy demand and related infrastructure requirements as compared to more developed economies.

Well positioned across multiple countries, regions and segments of the energy infrastructure industry.

Stable and flexible financial profile to support growth.

We have a moderate level of debt and a stable cash flow, which provides us with rapid and efficient access to capital when we identify compelling growth opportunities. We generate the vast majority of our earnings from our regulated and contracted businesses and well over half of our earnings are derived from countries with investment grade ratings.

Demonstrated capability to grow in a disciplined manner.

Operational excellence.

We have a recognized record for the reliable, responsible, efficient and safe operations of our businesses with company-wide power distribution line losses of 7.9%, power plant reliability of 97.33%, natural gas pipeline reliability of 100.00%, natural gas processing reliability of 99.72% and a Lost Time Incident Rate, or LTIR, for all our businesses of 0.35 in 2008.

Experienced management team with strong local presence.

Competitive Challenges and Summary Risk Factors

Among the competitive challenges and key risks we face in our businesses and in implementing our strategy are the following:


	•	we are exposed to overall macroeconomic, political and regulatory risks, including the possibility of volatility in exchange rates and inflation, reduction in tariffs and nationalization of our assets;

	•	most of our businesses are subject to significant governmental regulations;

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

	•	our revenues are dependent on the efficient and safe operation of our assets;

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	•	our ability to increase our revenues is dependent upon economic growth in the markets where we operate and growth in our energy demand and in our customer base in particular;

	•	our growth is dependent on the expansion of existing businesses, our ability to acquire and integrate new businesses and to develop greenfield projects;

	•	competition to acquire energy assets is strong;

	•	we may not be able to raise sufficient capital to fund our growth strategy;

	•	the operation of our business involves many risks, including the inability to obtain or renew required governmental concessions, permits and approvals, fuel spillage, seepage or release of hazardous materials; and

	•	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.

You should also carefully consider the matters described under “Risk Factors,” including that our business, results of operations and financial condition may be adversely affected by weakness in the general economy, the overall macroeconomic and political environment, the performance of the energy sector or other matters. One or more of these factors could negatively impact our results of operations and financial condition and our ability to implement our business strategy successfully.

Our Strategy

Our strategy is to own and operate essential energy infrastructure assets diversified across our existing lines of business in key emerging markets. We generally focus on businesses that are regulated and/or contracted that produce stable cash flows with strong local branding and management. We seek to grow our company by investing capital at attractive rates of return into organic expansion of existing businesses, acquisitions of new businesses or incremental interests in existing businesses and brownfield and greenfield development of new assets. We prefer investments that provide operational control or the ability to exert significant influence, or strategic non-control positions that offer the opportunity to gain control or significant influence over the investment in the future. We target opportunities that will reinforce our existing business lines or result in synergies with existing operations and seek to consolidate our significant presence in certain countries, build upon our early stage presence in other countries and enter key new countries. From January 1, 2007 through June 30, 2009, we have acquired new or additional interests in 19 businesses. We are also currently pursuing additional greenfield development opportunities. We have deployed capital in excess of $1.5 billion, including cash and, in certain cases, our ordinary shares, in connection with these activities.

In executing our strategy, we seek to:


	•	maximize the financial performance of our businesses;

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

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

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

	•	leverage our strong management teams and their relationships and market knowledge to effectively manage our businesses and pursue growth opportunities; and

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

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Our Segments and Businesses

The following summary table generally sets forth our subsidiaries and affiliates that operate as holding or primary operating companies by segment.⁽¹⁾


		AEI Ownership % as of
Business	Country	June 30, 2009⁽²⁾

*Power Distribution*
Chilquinta	Chile	50.00%
Delsur	El Salvador	86.41%
EDEN⁽³⁾	Argentina	90.00%
Elektra	Panama	51.00%
Elektro	Brazil	99.68%
EMDERSA⁽⁴⁾	Argentina	19.91%
Luz del Sur⁽⁵⁾	Peru	37.97%
*Power Generation*
Amayo	Nicaragua	12.72%
Corinto	Nicaragua	57.67%
DCL	Pakistan	60.22%
ENS	Poland	100.00%
EPE⁽⁶⁾	Brazil	50.00%
Emgasud⁽⁷⁾	Argentina	37.00%
Fenix⁽⁸⁾	Peru	85.00%
Jaguar⁽⁹⁾	Guatemala	100.00%
JPPC	Jamaica	84.42%
Luoyang	China	50.00%
PQP	Guatemala	100.00%
San Felipe	Dominican Republic	100.00%
Trakya⁽¹⁰⁾	Turkey	59.00%
Tipitapa	Nicaragua	57.67%
*Natural Gas Transportation and Services*
Accroven	Venezuela	49.25%
Centragas⁽¹¹⁾	Colombia	13.03%
Emgasud⁽⁷⁾	Argentina	37.00%
GBS⁽¹¹⁾	Colombia	49.37%
GOB⁽⁶⁾	Bolivia	50.00%
GOM⁽⁶⁾	Brazil	50.00%
GTB	Bolivia	17.65%
Promigas Pipeline⁽¹¹⁾	Colombia	52.13%
PSI⁽¹¹⁾	Colombia	50.46%
TBG	Brazil	4.21%
TBS⁽⁶⁾	Brazil	50.00%
Transmetano⁽¹¹⁾	Colombia	50.34%
Transoccidente⁽¹¹⁾	Colombia	35.96%
Transoriente⁽¹¹⁾	Colombia	13.73%

*Natural Gas Distribution*
BMG	China	70.00%
6 businesses in Hunan Province
3 businesses in Qinghai Province
3 businesses in Zhenjiang Province
1 business in Jiangxi Province
1 business in Liaoning Province
1 business in Heibei Province
1 business in Jilin Province
Cálidda	Peru	80.85%
Emgasud⁽⁷⁾	Argentina	37.00%
Gases de Occidente⁽¹¹⁾	Colombia	46.97%
Gases del Caribe⁽¹¹⁾	Colombia	16.16%
Surtigas⁽¹¹⁾	Colombia	52.08%
Tongda	China	100.00%
5 businesses in Jiangsu Province
3 businesses in Zhejiang Province
2 businesses in Jiangxi Province
2 businesses in Shandong Province
2 businesses in Guangdong Province
*Retail Fuel*
SIE^(11)(12)	Colombia, Ecuador, Panama, Chile, Mexico, Peru	24.96%

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(1)		The foregoing table does not include investments in companies we do not consider material, including in companies that do not operate in one of our reporting segments and investments in new companies which occurred after June 30, 2009. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments in 2009.”
(2)		Represents AEI’s net interest via direct and indirect ownerships.
(3)		We acquired our 90.00% interest in EDEN in 2007. The transaction remains subject to local anti-trust approval.


(4)		EMDERSA is the holding company of the power distribution companies EDESAL, EDELAR and EDESA. On August 27, 2009, we acquired an additional 4.5% of EMDERSA, on September 24, 2009, we acquired an additional 25.6% of EMDERSA and on October 13, 2009, we acquired an additional 27.09% of EMDERSA. As of the date of this prospectus, we own 77.11% of EMDERSA.


(5)		On September 8, 2009, we signed agreements with certain shareholders of Luz del Sur pursuant to which we agreed to acquire an additional interest of Luz del Sur in exchange for AEI shares. Closing of this transaction is subject to certain conditions, including the listing of our shares on an approved exchange, including the NYSE. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments in 2009.”
(6)		Part of the Cuiabá Integrated Project.
(7)		Emgasud is the holding company for five Power Generation businesses, one Natural Gas Transportation and Services and one Natural Gas Distribution business. The acquisition of special minority rights under Emgasud’s shareholder’s agreement remains subject to local anti-trust approval.
(8)		Fenix is the holding company for our power generation development project in Peru. As of the date of this prospectus, construction on this project has not commenced.
(9)		Jaguar is the holding company for our power generation development in Guatemala. As of the date of this prospectus, construction on this project has not commenced.


(10)		On August 27, 2009, we acquired an additional 31.00% of Trakya.
(11)		Interest is held through Promigas.
(12)		SIE operates two lines of business under the brand names Terpel and Gazel.

Our Corporate Information

We were incorporated in the Cayman Islands in June 2003. Our registered 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 prospectus and shall not be relied upon in determining whether to invest in our ordinary shares.

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THE OFFERING

The following is a brief summary of the terms of this offering. For a more complete description of our ordinary shares, see “Description of Share Capital” in this prospectus.


Issuer		AEI

Selling Shareholders		Some of our shareholders, including affiliates of certain of the underwriters, may sell shares in this offering. The selling shareholders are identified in “Principal and Selling Shareholders” in this prospectus. See also “Underwriting.”


Primary Offering		We are offering 16,666,667 ordinary shares.


Secondary Offering		The selling shareholders are offering 33,333,333 ordinary shares.


Offering Price		$ per share.


Option to Purchase Additional Ordinary Shares		The underwriters have the right to purchase from the selling shareholders an additional 7,500,000 ordinary shares within 30 days from the date of this prospectus.


Use of Proceeds		We estimate that the net proceeds to us in this offering (based on the midpoint of the range set forth on the cover page of this prospectus), after deducting the underwriters’ discounts and commissions and estimated expenses incurred in connection with this offering, will be $233 million.


		We intend to use the net proceeds from this offering for general corporate purposes, including to repay our revolving credit facilities. Certain of the underwriters and/or their affiliates are lenders to us under our revolving credit facilities and may receive their pro rata portion of any amounts repaid from the proceeds of this offering. See “Use of Proceeds” and “Underwriting.”

		We will not receive any proceeds from the sale of our ordinary shares by the selling shareholders or from the exercise of the underwriters’ option to purchase additional ordinary shares.


Share Capital Before and After Offering		Our issued and outstanding share capital consists of 244,117,724 ordinary shares as of the date of this prospectus. Immediately after the offering, we will have 260,784,391 ordinary shares issued and outstanding.


Voting Rights		Holders of our ordinary shares are entitled to one vote per ordinary share in all shareholders’ meetings. See “Description of Share Capital — Voting Rights.”

Dividends		We currently have no plans to pay dividends following the completion of this offering because we expect to retain our earnings for use in the development and expansion of our business. See “Dividend Policy.”

Lock-up Agreements		We have agreed with the underwriters, subject to certain exceptions, not to sell or dispose of any ordinary shares or securities convertible into or exchangeable or exercisable for any ordinary shares during the period commencing on the date of this prospectus until 180 days after the completion of this offering. Our selling shareholders, members of our board of directors, our executive officers and certain non-selling shareholders have agreed to substantially similar lock-up provisions, subject to certain exceptions. See “Underwriting.”

Proposed New York Stock Exchange Symbol		AEI

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SUMMARY HISTORICAL FINANCIAL DATA

The following table presents summary financial data for the periods indicated below. We have derived the historical earnings and cash flow data for the years ended December 31, 2006, 2007 and 2008, and the summary historical balance sheet data as of December 31, 2007 and 2008, from our audited consolidated financial statements included elsewhere in this prospectus. The summary historical balance sheet data as of December 31, 2006 has been derived from our audited balance sheet as of December 31, 2006 which is not included in this prospectus. The summary historical data as of and for the six months ended June 30, 2008 and 2009 are derived from our unaudited condensed consolidated financial statements included elsewhere in this prospectus. 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 “Use of Proceeds,” “Selected Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes, located elsewhere in this prospectus.


	For the Year			For the Year			For the Year			For the			For the
	Ended			Ended			Ended			Six Months			Six Months
	December 31,			December 31,			December 31,			Ended June 30,			Ended June 30,
	2006⁽¹⁾			2007			2008			2008			2009
	(In millions of $)

Statement of Operations Data:
Revenues	$	946		$	3,216		$	9,211		$	4,604		$	3,703
Cost of sales		566			1,796			7,347			3,642			2,816
Operations, maintenance, general and administrative expenses		193			630			894			449			364
Depreciation and amortization		59			217			268			132			129
Taxes other than income		7			43			43			26			21
Other charges		—			50			56			—			—
(Gain) loss on disposition of assets		7			(21	)		(93	)		(53	)		10
Equity income from unconsolidated affiliates		37			76			117			68			50

Operating income		151			577			813			476			413
Interest income		71			110			88			41			35
Interest expense		(138	)		(306	)		(378	)		(193	)		(159	)
Foreign currency transaction gain (loss), net		(5	)		19			(56	)		23			6
Gain (loss) on early retirement of debt		—			(33	)		—			—			3
Other income (expense) — net		7			(22	)		9			2			50

Income before income taxes		86			345			476			349			348
Provision for income taxes		(84	)		(193	)		(194	)		(119	)		(127	)

Income from continuing operations		2			152			282			230			221
Income from discontinued operations, net of tax		7			3			—			—			—
Gain from disposal of discontinued operations		—			41			—			—			—

Net income		9			196			282			230			221
Less: Net income-noncontrolling interests		(20	)		(65	)		(124	)		(124	)		(53	)

Net income (loss) attributable to AEI shareholders	$	(11	)	$	131		$	158		$	106			168

Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	155		$	686		$	508		$	172		$	296
Investing activities		(1,729	)		(1,151	)		(414	)		(275	)		(104	)
Financing activities		2,395			88			173			90			(412	)
Capital expenditures		(76	)		(249	)		(372	)		(140	)		(166	)
Other Financial Data:
Adjusted EBITDA⁽²⁾		217			823			1,044			555			552

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Presentation of Information

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

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

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


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

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

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

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

	•	“Pakistani rupees” or “PKR” 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;

	•	“Turkish lira” or “TL” 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 prospectus.

Market Data and Forecasts

This prospectus also contains data related to the economic conditions and energy industry in the markets in which we operate. Unless otherwise indicated, information in this prospectus concerning economic conditions and the energy industry is based on publicly available information from third party sources which we believe to be reasonable. The economic conditions and/or energy industry in the markets in which we operate may deteriorate and not grow at the rates projected by market data, or at all. The deterioration of the economic conditions and/or the failure of the energy industry in the markets in which we operate to grow at the projected rates may have a material adverse effect on our business, results of operations, financial condition and the market price of our ordinary shares. In addition, the rapidly changing nature of the economic conditions and energy industry subjects any projections or estimates to significant uncertainties. You should not place undue reliance on these forward looking statements.

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RISK FACTORS

You should carefully consider each of the following risks and all of the information set forth in this prospectus before deciding to invest in our ordinary shares. Our business, results of operations, financial condition or prospects could be adversely affected if any of these risks actually occurs, and as a result, the market price of our ordinary shares could decline and you could lose all or part of your investment. The risks described below are those known to us and that we currently believe could materially affect us. Additional risks not currently known to us or that we currently believe are immaterial also may impair our business, results of operations and financial conditions.

Risks Associated with the Countries in which We Operate

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

All of our operations and/or development activities are in emerging markets. 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, distribution and transportation of electricity, natural gas and liquid fuels. Energy demand is largely 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 and political and social stability in these emerging markets. Should economic conditions deteriorate in these countries or in emerging markets generally, our results of operations and financial condition may be adversely affected.

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

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


	•	consumption of electricity and natural gas;

	•	supply of electricity and natural gas;

	•	energy policy;

	•	subsidies and incentives;

	•	regulated returns and associated tariffs;

	•	labor laws;

	•	economic growth;

	•	currency fluctuations;

	•	inflation;

	•	exchange and capital control policies;

	•	interest rates;

	•	liquidity of domestic capital and lending markets;

	•	fiscal policy;

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	•	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 key infrastructure, including the hydrocarbon and electricity industries.

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

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

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


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

	•	termination of permits or concessions, and

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

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

Future fluctuations in the value of the local currencies relative to the U.S. dollar in the countries in which we operate may occur, and if such fluctuations were to occur in one or a combination of the countries in which we

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operate, our results of operations or financial condition could be adversely affected. For additional information regarding currency fluctuations, see “Exchange Rates.”

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

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

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

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

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

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

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

Future governmental economic measures, including interest rate increases, restrictions on tariff adjustments to offset inflation, intervention in foreign exchange markets and actions to adjust or fix currency values, may trigger or exacerbate increases in inflation, and consequently have an adverse impact on us. 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 results of operations or financial condition.

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

Bolivia has experienced political and economic instability that has resulted in significant changes in its general economic policies and regulations. On May 1, 2006, the Bolivian government nationalized the hydrocarbons industry pursuant to a Supreme Decree. Several subsequent decrees were issued and ultimately

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the Bolivian government registered 100% of our interest in Transredes, a gas distribution company of which we owned 50%, in the name of Yacimientos Petrolíferos Fiscales Bolivianos, or YPFB, the Bolivian state-owned energy company. In October 2008, we reached a settlement with the Bolivian government pursuant to which the Bolivian government paid us $120 million in two installments. The developments in Bolivia may increase the risk that our other assets in Bolivia, including Gas Transboliviano S.A., or GTB, and GasOriente Boliviano Ltda., or GOB, will be subject to nationalization without fair compensation.

Venezuela has nationalized a significant part of its hydrocarbon and electricity industries and changed its operation agreements to joint ventures with the state-owned oil company Petróleos de Venezuela, S.A., or PDVSA. On November 15, 2007, we sold our interests in Vengas S.A., or Vengas, to PDVSA Gas, S.A., a wholly-owned subsidiary of PDVSA, or PDVSA Gas. On September 11, 2009 we signed a non-binding Letter of Intent with PDVSA Gas pursuant to which we agreed to transfer our interest in Accroven to PDVSA Gas. Closing of the transaction is subject to negotiation of definitive documentation and receipt of third party consents. We cannot assure you that the sale will occur on the terms agreed in the Letter of Intent or at all.

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

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

Risks Relating to the Industries in which We Operate

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

We operate energy businesses in 19 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 and financial condition. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions in which we operate, particularly our regulated utilities where tariffs are subject to regulatory review or approval, could adversely affect our results of operations and financial condition. Such changes may include:


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

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

	•	changes in rules governing energy supply and purchase contracts;

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

	•	changes in rules governing dispatch order;

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

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

	•	changes in calculation of transportation/transmission rates; and

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

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

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

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

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

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

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

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


	•	warning notices;

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

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

	•	injunctions prohibiting investments in new facilities and equipment;

	•	restrictions to the operations of existing facilities and equipment;

	•	intervention by the authority granting our concession; and

	•	possible termination or non-renewal of our concession.

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In addition, governments have the power to terminate our businesses’ concessions prior to the end of the applicable concession term in the case of our bankruptcy or dissolution, by means of expropriation in the public interest or in the event our businesses fail to comply with applicable regulation. In this regard, we may not be able to renew our concessions at the end of the term of the concessions.

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 results of operations or financial condition.

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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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 these materials could adversely affect our financial condition or results of operations.

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


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

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

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

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

	•	should a neighboring government decide, for political reasons or otherwise, to curtail or interrupt the transportation of fuel or energy required by our businesses to operate, an alternate source for that fuel or energy may not be available, or become available, in sufficient time to preclude an interruption of our operations. For example, EPE, our Brazilian Power Generation business, has been unable to obtain a gas supply due to a lack of supply combined with a sharp increase in regional demand and has generally not been operational since August 2007. For additional information, see “Business — Power Generation — Cuiabá — Empresa Produtora de Energia Ltda. (EPE)” and “Business — Natural Gas Transportation and Services — Cuiabá — GasOcidente do Mato Grosso Ltda. (GOM), GasOriente Boliviano Ltda. (GOB) and Transborder Gas Services Ltd. (TBS).”

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,

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suspension of operations or imposition of criminal liability for non-compliance. Environmental laws and regulations can also impose strict liability for the environmental remediation of spills and discharges of hazardous materials and wastes and require us to indemnify or reimburse third parties for environmental damages. Compliance with changed or new environmental, health and safety regulations could require us to make significant capital investments in additional pollution controls or process modifications. These expenditures may not be recoverable and may consequently divert funds away from planned investments in a manner that could adversely affect our results of operations or financial condition.

Risks Related to Our Businesses

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

The operation of our business involves many risks, including:


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

	•	fuel spillage, seepage or release of hazardous materials;

	•	the unavailability of critical equipment or parts;

	•	the unavailability or interruptions of fuel or energy supply;

	•	work stoppages and labor unrest;

	•	social unrest;

	•	operation and critical equipment failures;

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

	•	forecasting errors for price and volume projections;

	•	decreases in energy consumption;

	•	severe weather and seasonal variations;

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

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

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

	•	working capital constraints;

	•	operating cost overruns;

	•	construction and operational delays or unanticipated cost overruns; and

	•	performance of services from subcontractors.

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

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

Our operating success depends in part on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity,

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including people in our international businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements.

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

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

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

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


	•	acquired businesses may not perform as expected;

	•	we may incur unforeseen obligations or liabilities;

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

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

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

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

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

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

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

All of our Power Generation businesses, except 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. A default by any of our key customers in our Power Generation or Natural Gas Transportation and Services businesses could materially and adversely affect our

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financial condition or results of operations. Our Power Distribution and Natural Gas Distribution businesses are impacted by the creditworthiness of our governmental, wholesale and retail residential customers.

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

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

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

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

Under Brazilian law, Elektro 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.

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

Some of our Power Generation and Power Distribution businesses buy and sell electricity in the wholesale spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. Additionally, we may be required to pay regulatory penalties for our Power Distribution businesses if regulators conclude that we did not contract for enough electricity. Typically, the open market wholesale prices for electricity are volatile and often reflect the 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 and we may not always engage in hedging transactions. In addition, businesses that engage in hedging transactions remain subject to market risks, including market liquidity and counterparty creditworthiness, and may also have exposure to market prices if counterparties do not produce volumes or otherwise comply with contractual obligations in accordance with the terms of the applicable hedging contracts.

We are subject to risks associated with climate change.

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

Financial Risks

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

From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by our operating cash flows. If our credit ratings, or those of our subsidiaries or those of the countries in which we operate, were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs would increase.

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

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number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such financing available, the lending institutions may also require sponsor guarantees for completion risks and governmental guarantees of certain business and sovereign related risks. However, financing from international financial agencies or governmental guarantees required to complete projects may not be available when needed, and if they are not, we may have to abandon these projects or invest more of our own funds which may not be in line with our investment objectives and would leave less funds for other investments and development projects.

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

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

Risks Associated with our Structure

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

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

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

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

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

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

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

As of June 30, 2009, the Ashmore Funds owned approximately 55% of our ordinary shares. Buckland Investment Pte Ltd. and funds managed by Eton Park owned approximately 22% and 6%, respectively, as of such date and other institutional investors, and members of management, directors and our employees and former employees owned the remaining ordinary shares. Consequently, the Ashmore Funds individually, and the Ashmore Funds, Buckland Investment Pte Ltd. and Eton Park or any combination of the three collectively, have significant influence over the determination of matters submitted to a vote of our shareholders, including in the election of our directors, the appointment of new management and the adoption of amendments to our Memorandum and Articles of Association. The ability of other shareholders to influence our management and policies may be severely limited, including with respect to mergers, amalgamations, consolidations or acquisitions, our acquisition or disposition of our ordinary shares or other equity securities and the payment of dividends or other distributions on our ordinary shares. Additionally, this concentration of ownership may delay, deter or prevent acts that would be favored by our other shareholders, such as change of control transactions that would result in the payment of a premium to our other shareholders.

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

Our shareholders and their affiliates may compete with us for investment opportunities, may invest in entities that directly or indirectly compete with us or companies in which they currently invest may begin competing with us. This could impair our ability to consummate transactions. We have no ability to control, nor will we necessarily be aware of, whether any of our shareholders currently compete with us or will in the future acquire interests in companies that will compete with us.

Risks Relating to this Offering

There is no existing market for our shares, and we do not know whether one will develop to provide you with adequate liquidity. If our stock price fluctuates after this offering, you could lose a significant part of your investment.

Prior to this offering, there has not been a public market for our shares. If an active trading market does not develop, you may have difficulty selling any of our shares that you buy. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the New York Stock Exchange, or the NYSE, or otherwise or how liquid that market might become. The initial public offering price for the shares will be determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our shares at prices equal to or greater than the price paid by you in this offering. In addition to the risks described above, the market price of our shares may be influenced by many factors, some of which are beyond our control, including:


	•	the failure of financial analysts to cover our shares after this offering or changes in financial estimates by analysts;

	•	actual or anticipated variations in our operating results;

	•	changes in financial estimates by financial analysts, or any failure by us to meet or exceed any such estimates, or changes in the recommendations of any financial analysts that elect to follow our ordinary shares or the ordinary or common shares of our competitors;

	•	announcements by us or our competitors of significant contracts or acquisitions;

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	•	future sales of our shares; and

	•	investor perceptions of us and the industries in which we operate.

In addition, the stock market in general has experienced substantial price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our shares, regardless of our operating performance. In the past, following periods of volatility in the market price of certain companies’ securities, securities class-action litigation has been instituted against these companies. Such litigation, if instituted against us, could adversely affect our financial condition or results of operations.

The initial public offering price per ordinary share is substantially higher than our net tangible book value per ordinary share immediately after the offering and you will incur immediate and substantial dilution.

The initial public offering price per ordinary share is substantially higher than our net tangible book value per ordinary share immediately after the offering. As a result, you may pay a price per share that substantially exceeds the tangible book value of our assets after subtracting our liabilities. Investors who purchase ordinary shares in the offering will be diluted by $8.50 per share after giving effect to the sale of ordinary shares in this offering. See “Dilution.” If we grant options in the future to our employees, and those options are exercised, or if other issuances of ordinary shares are made, there will be further dilution. We intend to issue ordinary shares to certain employees, including our executive officers, and to independent directors following completion of this offering. See “Management — Incentive Plans — Grants to Employees and Directors.”

Sales of substantial amounts of our shares in the public market, or the perception that these sales may occur, could cause the market price of our shares to decline.

Sales of substantial amounts of our shares in the public market, or the perception that these sales may occur, could cause the market price of our shares to decline. This could also impair our ability to raise additional capital through the sale of our equity securities. Under our Amended and Restated Memorandum and Articles of Association, we are authorized to issue up to five billion shares, of which 260,784,391 shares will be outstanding following this offering. Certain shareholders, our directors and executive officers and certain employees will enter into lock-up agreements, pursuant to which they are expected to agree, subject to certain exceptions, not to sell or transfer, directly or indirectly, any shares for a period of 180 days from the date of this prospectus. We cannot predict the size of future issuances of our shares or the effect, if any, that future sales and issuances of shares would have on the market price of our shares. In addition, 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, or Registration Rights Agreement. 240,476,759 shares are subject to these rights. In addition, holders of our PIK notes are entitled to convert such notes into 10,504,986 shares and are entitled to become parties to the Registration Rights Agreement. See “Ordinary Shares Eligible for Future Sale.”

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

We are incorporated under the laws of the Cayman Islands. Half 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 you 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, actions by minority shareholders 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

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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 the jurisdictions in which we operate against us or our directors or officers under the securities laws of other jurisdictions.

We have been advised by Walkers, our legal advisers as to Cayman Islands law, that the U.S. and the Cayman Islands do not currently have a treaty providing for the reciprocal recognition and enforcements of judgments in civil and commercial matters and that while a judgment for the payment of money rendered by any federal or state court in the U.S. based on civil liability may be enforceable at common law in the Cayman Islands, such enforcement will not be automatic or available in all circumstances. In particular, there is doubt as to the enforceability in the Cayman Islands, in original actions or in actions for enforcement of judgments of the U.S. courts, of liabilities predicated solely upon U.S. securities laws.

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NON-GAAP FINANCIAL MEASURES

The body of generally accepted accounting principles is commonly referred to as “GAAP.” For this purpose, a non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or the SEC, as one that purports to measure historical or future financial performance, financial position or cash flows but excludes or includes amounts that would not be so adjusted in the most comparable U.S. GAAP measure. From time to time we disclose non-GAAP financial measures, primarily Adjusted EBITDA and net debt. The non-GAAP financial measures described herein or in other documents we issue are not a substitute for the GAAP measures of earnings and liquidity.

We 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, noncontrolling 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 noncontrolling 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 financial analysts and other users of the financial statements, that Adjusted EBITDA can be useful as an objective and comparable measure of operating profitability because it excludes these elements of earnings that may not consistently provide information about the current and ongoing operations of existing assets. Accordingly, although Adjusted EBITDA and other non-GAAP measures as calculated by us may not be comparable to calculations of similarly titled measures used 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 and net debt. In addition, one of the factors for determining the level of our investment capacity utilizes Adjusted EBITDA and net debt as inputs. Finally, these metrics are analyzed and summarized for discussions or presentations to our equity and debt investors and financial analysts.

For the reconciliation of Adjusted EBITDA and net debt to GAAP measures, see “Selected Consolidated Financial Data” below. For additional non-GAAP information and reconciliations to GAAP measures, see Annex I and Annex II.

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FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are based on our current expectations, assumptions, estimates and projections about us and our industry. These forward-looking statements can be identified by words or phrases such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “intend,” “is/are likely to,” “may,” “plan,” “should,” “would,” or other similar expressions. The forward-looking statements included in this prospectus relate to, among others:


	•	general economic and business conditions in the countries where we operate;

	•	our goals and strategies;

	•	our future business development, financial condition and results of operations;

	•	relevant government policies and regulations relating to the energy industry;

	•	our ability to expand our production, our sales and distribution network and other aspects of our operations;

	•	our ability to stay abreast of market trends and technological advances;

	•	acquisitions and the integration of acquisitions;

	•	development of greenfield projects;

	•	fuel, energy and commodity prices and availability;

	•	currency exchange rate fluctuations;

	•	weather;

	•	future energy demand;

	•	trends in environmental regulations; and

	•	trends in energy supply and green energy.

These forward-looking statements involve various risks and uncertainties. Although we believe that our expectations expressed in these forward-looking statements are reasonable, our expectations may turn out to be incorrect. Our actual results could be materially different from our expectations. Important risks and factors that could cause our actual results to be materially different from our expectations are generally set forth in “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and other sections in this prospectus.

The forward-looking statements made in this prospectus relate only to events or information as of the date on which the statements are made in this prospectus. We undertake no obligation to update any forward-looking statements to reflect events or circumstances after the date on which the statements are made or to reflect the occurrence of unanticipated events.

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USE OF PROCEEDS

We expect to receive $233 million of net proceeds from the sale of shares by us in this offering, after deducting the underwriters’ discounts and commissions and estimated expenses incurred in connection with this offering, based on an assumed offering price of $15.00 per share, the mid-point of the range set forth on the cover page of this prospectus. An increase (decrease) of $1.00 in the price per share of $15.00 would increase (decrease) the gross proceeds in connection with this offering by $16,666,667. We will not receive any proceeds from the sale of our ordinary shares by the selling shareholders or from the exercise of the underwriters’ option to purchase additional shares because such additional shares consist solely of shares being sold by the selling shareholders in order to provide enhanced liquidity for them.

We anticipate using substantially all of the net proceeds of this offering to repay our revolving credit facilities, with these facilities remaining available for general corporate purposes. Any portion not used to repay our revolving credit facilities would be used for general corporate purposes. As of October 9, 2009, there was $260 million outstanding under the revolving credit facilities. For additional information on the revolving credit facilities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Parent Company Long-Term Debt — Credit Agreement.”

Certain of the underwriters and/or their affiliates are lenders to us under our revolving credit facilities and may receive their pro rata portion of any amounts repaid from the proceeds of this offering. See “Underwriting.”

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DIVIDEND POLICY

We currently have no plans to pay dividends following the completion of this offering because we expect to retain our earnings for use in the development and expansion of our business. Any future determination to pay dividends would be at the discretion of, and require the approval of, our board of directors, depending on our financial condition, results of operations, future prospects, capital requirements, restrictions contained in future financing instruments and other factors our board of directors deems relevant.

Under Cayman Islands law, we may declare cash dividends or make other distributions only out of profits lawfully available for the purpose, or out of our share premium account, which is the same as additional paid in capital, if we will thereafter have the ability to pay our debts in the ordinary course as they fall due. Cash dividends, if any, will be paid by us in U.S. dollars.

We are a holding company with no material assets other than the stock of our subsidiaries. All of our revenue-generating operations are conducted through our subsidiaries. Accordingly, almost all of our cash flow is generated by our subsidiaries. Our subsidiaries are separate and distinct legal entities and have no obligation to make any funds available to us, whether by dividends, fees, loans or other payments. Accordingly, our ability to pay dividends is dependent on the ability of our subsidiaries to distribute cash to us in the form of dividends, fees, principal, interest, loans or otherwise. Our subsidiaries may be obligated, pursuant to loan agreements, indentures or project financing arrangements, to satisfy certain obligations or other conditions before they may make distributions to us.

Our credit agreement prohibits us from paying dividends if an event of default has occurred under the agreement and if we cease to be in compliance with certain financial ratios as a result of making the dividend payment. Therefore, our ability to pay dividends on our ordinary shares will depend upon, among other things, our level of indebtedness at the time of the proposed dividend and whether we are in compliance with the covenants under our credit agreement. Our future dividend policy will also depend on the requirements of any future financing agreements to which we may be a party and other factors considered relevant by our board of directors. For a discussion of our cash resources and needs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity.”

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CAPITALIZATION

The following table sets forth our combined cash, cash equivalents and capitalization as of August 31, 2009 on an actual basis and as adjusted to give effect to the completion of this offering.

The table below should be read in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes included elsewhere in this prospectus.


	As of August 31, 2009
	Actual		As Adjusted
	(In millions of $)

Cash and cash equivalents	$	606	$	611

Restricted cash⁽¹⁾		271		271

Long-term debt, including current portion:
Debt held by parent company:
Senior credit facility		914		914
Revolving credit facility		123		—	⁽²⁾
Synthetic revolving credit facility		105		—	⁽²⁾
PIK note		190		190
Debt held by consolidated subsidiaries:⁽³⁾
Cálidda		43		43
Cuiabá		97		97
DCL		79		79
Delsur		67		67
EDEN		20		20
Elektra		119		119
Elektro		626		626
ENS		59		59
Luoyang		116		116
PQP		71		71
Promigas		1,074		1,074
Other		65		65

Total long-term debt, including current portion		3,768		3,540
Equity:
Ordinary shares, $0.002 par value: actual:
5,000,000,000 shares authorized; 237,650,270 and 254,316,937 issued and outstanding		—		1
Additional paid-in-capital		1,854		2,086
Retained earnings		494		494
Accumulated other comprehensive income		134		134

Total equity attributable to AEI		2,482		2,715
Equity attributable to noncontrolling interests		519		519

Total equity⁽⁴⁾		3,001		3,234

Total capitalization⁽⁴⁾	$	6,769		6,774


(1)		Includes $58 million of noncurrent restricted cash. As of August 31, 2009, our current restricted cash balance was $213 million.


(2)		As of October 9, 2009, there was $260 million outstanding, in the aggregate, under the revolving credit facility and the synthetic revolving credit facility.


(3)		Not guaranteed by AEI. See “Management’s Discussion and Analysis of Financial Condition and Result of Operations — Capital Resources and Liquidity — Subsidiaries’ Long-Term Debt Schedule.”


(4)		An increase (decrease) of $1.00 in the price per share of $15, which is the mid-point of the price range for the price per share, would represent an increase (decrease) of $17 million in total equity and total capitalization in the “As Adjusted” column.

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DILUTION

We have a net tangible book value of $5.97 per ordinary share. Our net tangible book value represents the amount of our total tangible assets (total assets excluding goodwill and intangible assets) less our total liabilities and noncontrolling interests, calculated at June 30, 2009, divided by 234,230,825, the total number of our ordinary shares outstanding at June 30, 2009.

After giving effect to the sale of 16,666,667 ordinary shares in this offering at an assumed initial public offering price of $15.00 per share, the mid-point of the range set forth on the cover page of this prospectus, and after deduction of the estimated discounts and commissions and estimated offering expenses payable by us, our net tangible book value estimated as of the date of this prospectus would have been approximately $1,631 million, or $6.50 per ordinary share. This represents an immediate increase in net tangible book value of $0.53 per ordinary share to our existing shareholders and an immediate pro forma dilution of $8.50 per ordinary share to purchasers of ordinary shares in this offering. Dilution for this purpose represents the difference between the price per ordinary share paid by these purchasers and net tangible book value per ordinary share immediately after the completion of the offering based on the June 30, 2009 net tangible value.

The following table illustrates this dilution to new investors purchasing ordinary shares, on a per share basis:


Assumed offering price per ordinary share	$	15.00
Net tangible book value per ordinary share as of June 30, 2009	$	5.97
Increase in net tangible book value per ordinary share attributable to new investors	$	0.53
Net tangible book value per ordinary share after the offering	$	6.50
Dilution per ordinary share to new investors	$	8.50
Percentage of dilution in net tangible book value per ordinary share		55.66	%

The following table sets forth, as of June 30, 2009, the total number of ordinary shares owned by existing shareholders and the average price per share paid by existing shareholders of common stock and new investors purchasing shares in this offering:


	Shares Owned/Purchased					Total Consideration					Average Price
	Number		Percent			Amount		Percent			Per Share
	(In millions of $, except % and per share data)
			%					%

Existing shareholders		234		93.4		$	1,828		88.0		$	7.81
New investors		17		6.6		$	250		12.0		$	15.00

Total				100.00	%	$	2,078		100.00	%

The data in the above table excludes 372,511 shares of common stock subject to options outstanding as of June 30, 2009 which have a price range of $11.18 to $16.70, all of which are fully vested and fully exercisable. In addition, the data in the above table excludes the shares of common stock subject to the PIK Notes conversion option. If these options were exercised at the average exercise price and the PIK Notes conversion option was exercised at the conversion rate in effect on June 30, 2009, the anti-dilution per share to new investors would be $0.57, representing a net tangible book value per ordinary share of $7.07. If these options are exercised as described above, new investors would own 6.3% of the total outstanding shares, and would have contributed 10.5% of our total paid-in capital at June 30, 2009.

Assuming the underwriters’ option to purchase additional shares is exercised in full, the net tangible book value per ordinary share after giving effect to the offering would be $6.67 per ordinary share. This would have an anti-dilutive effect of $0.17 per ordinary share.

Each $1.00 increase (decrease) in the offering price per ordinary share would increase (decrease) the net tangible book value after this offering by $0.07 per ordinary share.

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EXCHANGE RATES

A significant portion of our operating income is exposed to foreign currency exchange fluctuations. We are primarily exposed to fluctuation in the exchange rate between the U.S. dollar and the Brazilian real and the Colombian peso. The following table sets forth the annual high, low, average and period-end exchange rates for U.S. dollars for the periods indicated, expressed in Brazilian reais and Colombian pesos per U.S. dollar, respectively, and not adjusted for inflation. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Analysis of Market Risk — Foreign Exchange Rate Risk.”

Brazilian reais


			Average for
	Period-End		Period		Low		High
	(R$ per U.S. dollar)

Year ended December 31,
2004		2.65		2.93		2.65		3.21
2005		2.34		2.43		2.16		2.76
2006		2.14		2.18		2.06		2.37
2007		1.77		1.95		1.73		2.16
2008		2.34		1.84		1.56		2.50


	Low		High
	(R$ per U.S. dollar)

Month ended
April 2009		2.17		2.29
May 2009		1.97		2.15
June 2009		1.93		2.01
July 2009		1.87		2.01
August 2009		1.82		1.89
September 2009		1.78		1.90

Source: Central Bank of Brazil.

The exchange rate on October 12, 2009 was 1.74.

Colombian pesos


	Period-End		Average for Period		Low		High
	(COP per U.S. dollar)

Year ended December 31,
2004		2,390		2,628		2,316		2,779
2005		2,284		2,321		2,273		2,397
2006		2,239		2,359		2,225		2,634
2007		2,015		2,076		1,878		2,261
2008		2,234		1,965		1,652		2,392


	Low		High
	(COP per U.S. dollar)

Month ended
April 2009		2,283		2,544
May 2009		2,190		2,289
June 2009		2,015		2,189
July 2009		1,953		2,145
August 2009		1,988		2,050
September 2009		1,912		2,069

Source: Central Bank of Colombia.

The exchange rate on October 12, 2009 was 1,857.

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HISTORY AND DEVELOPMENT

Overview

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. Based in London, Ashmore’s business was founded by members of its team in 1992 as part of the Australia and New Zealand Banking Group. In 1999, Ashmore became independent with majority ownership by its employees. As of June 30, 2009, Ashmore managed over $24.9 billion in pooled funds, segregated accounts and structured products. Although a number of investors own interests in the Ashmore Funds, the investment decisions of the Ashmore Funds are controlled by Ashmore and the Ashmore Funds are considered entities under common control.

Formation of AEIL

On October 12, 2005, AEIL, 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.

In March 2006, certain Ashmore Funds transferred their previously acquired interest in Elektra 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.

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.

Acquisition of PEI by AEIL

In 2006, AEIL acquired PEI from Enron Corp. and certain of its subsidiaries for a purchase price of approximately $1.8 billion 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.

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.

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. To avoid delaying the Stage 1 closing of the acquisition of PEI immediately prior to such closing, in May 2006, PEI caused its wholly owned subsidiary to transfer, via a spin off, 33.03% of the outstanding shares of Promigas, or the Subject Promigas Shares, to EMHC Ltd.

- 33 -

SELECTED CONSOLIDATED FINANCIAL DATA

The following tables present summary financial data for AEI, the successor entity, and for both of our predecessor companies Elektra and PEI. We have derived the historical successor AEI earnings and cash flow financial data for the years ended December 31, 2006, 2007 and 2008, and historical balance sheet data as of December 31, 2007 and 2008, from our audited consolidated financial statements included elsewhere in this prospectus. We have derived historical balance sheet data as of December 31, 2006 and 2005 from our audited balance sheets not included in this prospectus. We have derived the historical predecessor Elektra financial data for the year ended December 31, 2004 and 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 in this prospectus. We have derived the historical predecessor PEI information for the years ended December 31, 2004 and 2005, and the 249-day period ended September 6, 2006 from the audited consolidated financial statements, of which only the 2006 audited consolidated financial statements are included in this prospectus. The summary historical data as of and for the six months ended June 30, 2008 and 2009 are derived from the AEI unaudited condensed consolidated financial statements included elsewhere in this prospectus. Our historical results for any prior period are not necessarily indicative of results to be expected for any future period.

The selected consolidated financial data for the periods and as of the dates indicated should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes, both of which are located elsewhere in this prospectus:

AEI and Elektra

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


	Elektra Noreste, S.A. (Predecessor)						AEI (Successor)
				For the
				275-Day
				Period
				from			For the 90-Day
	For the Year			January 1,			Period from			For the Year			For the Year			For the Year
	Ended			2005 to			October 3, 2005			Ended			Ended			Ended			For the Six			For the Six
	December 31,			October 2,			to December 31,			December 31,			December 31,			December 31,			Months Ended			Months Ended
	2004			2005			2005			2006⁽¹⁾			2007			2008			June 30, 2008			June 30, 2009
	(In millions of $)						(In millions of $ and shares, except per share data)

Statement of Operations Data:
Revenues	$	225		$	200		$	72		$	946		$	3,216		$	9,211		$	4,604		$	3,703
Cost of sales		152			140			53			566			1,796			7,347			3,642			2,816
Operating expenses:
Operations, maintenance, general and administrative expenses		31			22			7			193			630			894			449			364
Depreciation and amortization		10			9			3			59			217			268			132			129
Taxes other than income		—			1			—			7			43			43			26			21
Other charges		—			—			—			—			50			56			—			—
(Gain) loss on disposition of assets		—			1			—			7			(21	)		(93	)		(53	)		10
Equity income from unconsolidated affiliates		—			—			—			37			76			117			68			50

Operating income		32			27			9			151			577			813			476			413
Interest income		—			1			—			71			110			88			41			35
Interest expense		(4	)		(6	)		(3	)		(138	)		(306	)		(378	)		(193	)		(159	)
Foreign currency transactions gain (loss), net		—			—			—			(5	)		19			(56	)		23			6
Gain (loss) on early retirement of debt		—			—			—			—			(33	)		—			—			3
Other income (expense), net		—			—			—			7			(22	)		9			2			50

Income before income taxes		28			22			6			86			345			476			349			348
Provisions for income tax		(8	)		(7	)		(2	)		(84	)		(193	)		(194	)		(119	)		(127	)

Income from continuing operations		20			15			4			2			152			282			230			221
Income from discontinued operations, net of tax		—			—			—			7			3			—			—			—
Gain from disposal of discontinued operations, net of tax		—			—			—			—			41			—			—			—

Net income	$	20		$	15			4			9			196			282			230			221
Less: Net income — non-controlling interests		—			—			(2	)		(20	)		(65	)		(124	)		(124	)		(53	)
Net income attributable to Elektra Noreste S.A. shareholders		20			15

Net income (loss) attributable to AEI shareholders							$	2		$	(11	)	$	131		$	158		$	106		$	168

- 35 -


	Elektra Noreste, S.A. (Predecessor)						AEI (Successor)
				For the
				275-Day
				Period
				from			For the 90-Day
	For the Year			January 1,			Period from			For the Year			For the Year			For the Year
	Ended			2005 to			October 3, 2005			Ended			Ended			Ended			For the Six			For the Six
	December 31,			October 2,			to December 31,			December 31,			December 31,			December 31,			Months Ended			Months Ended
	2004			2005			2005			2006⁽¹⁾			2007			2008			June 30, 2008			June 30, 2009
	(In millions of $)						(In millions of $ and shares, except per share data)

Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	28		$	19		$	12		$	155		$	686		$	508			172			296
Investing activities		(16	)		(13	)		(6	)		(1,729	)		(1,151	)		(414	)		(275	)		(104	)
Financing activities		(7	)		(12	)		(5	)		2,395			88			173			90			(412	)
Capital expenditures		(18	)		(13	)		(6	)		(76	)		(249	)		(372	)		(140	)		(166	)
Other Financial Data:
Adjusted EBITDA⁽²⁾											217			823			1,044			555			552
Basic and diluted earnings per share:
Income (loss) from continuing operations attributable to AEI Shareholders											(0.09	)		0.42			0.73			0.50			0.73
Net income (loss) attributable to AEI Shareholders											(0.05	)		0.63			0.73			0.50			0.72
Weighted average shares outstanding											202			209			218			214			229


	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,		June 30,
	2004		2005		2006		2007		2008		2009
			(In millions of $)

Balance Sheet Data:
Property, plant and equipment (net)	$	221	$	228	$	2,307	$	3,035	$	3,524	$	3,842
Total assets		282		568		6,134		7,853		8,953		9,309
Long-term debt		95		90		2,390		2,515		3,415		2,915
Total debt		100		100		2,677		3,264		3,962		3,549
Net debt⁽²⁾		91		91		1,591		2,525		3,094		2,912
Total equity attributable to AEI		110		327		1,441		1,858		1,830		2,437


(1)		Includes Elektra on a consolidated basis for the entire year and PEI on the equity method basis from June to August and on the consolidated basis from September to December.
(2)		See “Non-GAAP Financial Measures” and the reconciliation table below.

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,			June 30,
	2004			2005			2006			2007			2008			2009
				(In millions of $)

Total debt	$	100		$	100		$	2,677		$	3,264		$	3,962			3,549
Less
Cash and cash equivalents		(7	)		(6	)		(830	)		(516	)		(736	)		(524	)
Current restricted cash		—			—			(117	)		(95	)		(83	)		(57	)
Non-current restricted cash		(2	)		(3	)		(139	)		(128	)		(49	)		(56	)

Net debt	$	91		$	91		$	1,591		$	2,525		$	3,094		$	2,912

- 36 -

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


							Natural Gas
	Power			Power			Transportation			Natural Gas			Retail
	Distribution			Generation			and Services			Distribution			Fuel			Other			Total
	(In millions of $)

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

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

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			Retail
	Distribution			Generation			and Services			Distribution			Fuel			Other			Total
	(In millions of $)

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

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

- 37 -

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		Retail
	Distribution			Generation			and Services		Distribution		Fuel		Other			Total
	(In millions of $)

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

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

The following table sets forth the reconciliation of net income to Adjusted EBITDA for AEI for the six months ended June 30, 2009 on a consolidated basis and by segment.


							Natural Gas
	Power			Power			Transportation		Natural Gas		Retail
	Distribution			Generation			and Services		Distribution		Fuel			Other			Total
	(In millions of $)

Net income (loss) attributable to AEI	$	135		$	47		$	28	$	23	$	5		$	(70	)	$	168
Depreciation and amortization		61			22			10		11		22			3			129
Net income (loss) — noncontrolling interests		6			(8	)		18		21		17			(1	)		53
Provision for income taxes		66			29			6		14		19			(7	)		127
Interest expense		41			24			20		9		25			40			159
Subtract:
Interest income		21			7			2		1		3			1			35
Foreign currency transaction gain (loss), net		(2	)		4			—		2		4			(2	)		6
Loss on disposition of assets		(10	)		—			—		—		—			—			(10	)
Gain on early retirement of debt		—			—			—		—		—			3			3
Other income (expense), net		46			4			9		—		(8	)		(1	)		50

Adjusted EBITDA	$	254		$	99		$	71	$	75	$	89		$	(36	)	$	552

The following table sets forth the reconciliation of net income to Adjusted EBITDA for AEI for the six months ended June 30, 2008 on a consolidated basis and by segment.


							Natural Gas
	Power			Power			Transportation			Natural Gas			Retail
	Distribution			Generation			and Services			Distribution			Fuel			Other			Total
	(In millions of $)

Net income (loss) attributable to AEI	$	87		$	51		$	22		$	17		$	27		$	(98	)	$	106
Depreciation and amortization		72			11			11			9			26			3			132
Net income (loss) — noncontrolling interests		6			(8	)		9			17			98			2			124
Provision for income taxes		54			4			20			14			27			—			119
Interest expense		75			20			22			11			26			39			193
Subtract:
Interest income		26			8			3			1			1			2			41
Foreign currency transaction gain (loss), net		4			9			(3	)		(1	)		14			—			23
Gain (loss) on disposition of assets		(11	)		—			—			—			78			(14	)		53
Other income (expense), net		(8	)		9			6			(2	)		(3	)		—			2

Adjusted EBITDA	$	283		$	52		$	78		$	70		$	114		$	(42	)	$	555

- 38 -

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
	(In millions of $)

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, net		74			95			17
Other income, net		82			71			26

Income before income taxes		522			710			394
Provision for income taxes		112			181			209

Net income		410			529			185
Less: Net income — noncontrolling interests		16			79			21

Net income attributable to PEI shareholders	$	394		$	450		$	164

Cash Flow Data:
Net cash 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 December 31,		As of December 31,
	2004		2005
	(In millions of $)

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 equity attributable to PEI		2,080		2,471


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

- 39 -

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
	(In millions of $)

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 PEI for the 249-day period ended September 6, 2006 on a consolidated basis and by segment:


						Natural Gas
	Power			Power		Transportation			Natural Gas
	Distribution			Generation		and Services			Distribution		Retail Fuel			Other			Total
	(In millions of $)

Net income (loss) attributable to PEI	$	142		$	29	$	18		$	3	$	12		$	(40	)	$	164
Depreciation and amortization		25			29		5			—		3			1			63
Net income — noncontrolling interests		—			13		8			—		—			—			21
Income tax expense		81			120		7			—		(2	)		3			209
Interest expense		59			34		15			—		6			(18	)		96
Subtract
Interest income from unconsolidated affiliates		—			—		2			—		—			—			2
Interest income		48			19		2			—		—			11			80
Foreign currency transaction, gain (loss), net		5			13		(1	)		—		—			—			17
Loss on disposition of assets		(6	)		—		—			—		—			—			(6	)
Other income (expense), net		2			37		1			—		—			(14	)		26

Adjusted EBITDA	$	258		$	156	$	49		$	3	$	19		$	(51	)	$	434

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			Total
	(In millions of $)

Net income (loss) attributable to PEI	$	215		$	116	$	58	$	23		$	19	$	19		$	450
Depreciation and amortization		33			56		8		—			4		—			101
Net income — noncontrolling 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 (loss), 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

- 40 -

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

This discussion should be read together with the “Selected Consolidated Financial Data,” the consolidated financial statements and PEI’s consolidated financial statements included elsewhere in this prospectus. Unless otherwise indicated, the financial data contained in this prospectus have been prepared in accordance with U.S. GAAP. See “Forward-Looking Statements” and “Risk Factors” for a discussion of factors that could cause future financial condition and results of operations to be different from those discussed below.

Interests in certain companies are accounted for under the equity method, which means that their net income or losses are included into consolidated profit and loss accounts in proportion to the ownership interest that is owned of the relevant company or entity during the respective periods. See Note 11 to the consolidated financial statements for the year ended December 31, 2008 and Note 10 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.

Overview

Our Business

We own and operate essential energy infrastructure assets in emerging markets. We group our businesses into five reporting segments: Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel.

For the years ended December 31, 2008, 2007 and 2006, we generated consolidated operating income of $813 million, $577 million and $151 million, respectively, net income attributable to AEI of $158 million, $131 million and net loss attributable to AEI of ($11 million), respectively and Adjusted EBITDA of $1,044 million, $823 million and $217 million, respectively. For the six months ended June 30, 2009, we generated consolidated operating income of $413 million, net income attributable to AEI of $168 million and Adjusted EBITDA of $552 million.

Our Reporting Segments

Our businesses consist of five reporting segments:

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

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

Our Natural Gas Transportation and Services businesses sell natural gas transportation capacity and related services to oil and gas producers, natural gas distribution companies and other large off-takers. Most of the businesses in this segment operate either through regulated concessions under a cost of service regulatory model or long-term contracts that provide for recovery of reasonable operating and administrative costs, incentives to continue cost reductions and make needed capital investments and a regulated rate of return.

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

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

Trends and Factors Affecting our Business

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

Energy Demand Growth in Our Markets. We currently operate in emerging markets in Latin America, Central and Eastern Europe and Asia. Growth in emerging markets, as measured by GDP growth, has consistently outpaced growth in developed markets in the last 15 years. Global Insight expects this trend to continue predicting annual growth of 5.8% for countries which are not members of the OECD for the period 2010-2019 versus 2.3% for OECD countries over the same period. Emerging markets growth is primarily driven by industrialization and urbanization. The correlation between GDP growth and energy consumption such as electricity is high and we expect the growth in emerging markets to drive energy consumption and the associated infrastructure needs. Moreover, the low base consumption level of energy in emerging markets as compared to developed markets provides for more growth potential in emerging markets and will continue to drive overall energy and infrastructure demand. According to the CIA World Factbook, U.S. electricity consumption per capita is currently more than four times Chile’s, more than five times China’s, more than five times Brazil’s, more than 14 times Colombia’s and more than 15 times Peru’s. Natural gas consumption growth in non-OECD countries is also expected to be stronger than that of OECD countries (46% vs. 16% growth from 2006 to 2020) according to the Energy Information Administration’s 2009 International Energy Outlook. We believe this increased consumption growth is primarily driven by increased gas penetration in these countries. Due to the constraints on many of the governments in emerging markets and limitations on 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, nongovernmental entities. This expected growth provides us with a significant opportunity to further expand and diversify our existing energy infrastructure assets and to grow through new brownfield and greenfield development opportunities.

The following table summarizes the electricity consumption growth rate in some of our principal markets:


	2006						2007						2008
				Electricity						Electricity						Electricity
				Consumption						Consumption						Consumption
	Real GDP			Growth			Real GDP			Growth			Real GDP			Growth
	Growth⁽¹⁾			Rate⁽²⁾			Growth⁽¹⁾			Rate⁽²⁾			Growth⁽¹⁾			Rate⁽²⁾

Brazil		4.0	%		3.1	%		5.7	%		3.1	%		5.1	%		5.2	%
Colombia		6.9	%		1.6	%		7.5	%		5.1	%		2.5	%		3.7	%
Turkey		6.9	%		9.3	%		4.7	%		6.4	%		1.1	%		3.3	%
Chile		4.6	%		5.8	%		4.7	%		4.7	%		3.2	%		0.1	%
Peru		7.7	%		32.7	%		8.9	%		9.4	%		9.8	%		9.0	%


(1)		International Monetary Fund World Economic Outlook Database, April 2009 (includes IMF Staff Estimates)
(2)		Global Insight, Instituto Nacional de Estadística and the U.S. Energy Information Administration.

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 to increase energy consumption by new industries and households as industrialization increases and standards of living improve.

Foreign Currency Changes. The local currencies in many emerging markets in which we operate fluctuate against the U.S. dollar. Depreciation and appreciation of the currencies relative to the U.S. dollar result in volatility in earnings and cash flows (measured in U.S. dollars) from some of our subsidiaries, particularly Elektro in Brazil and Promigas in Colombia. Future fluctuations in exchange rates relative to the U.S. dollar may have a material effect on our earnings and cash flows. In the first six months of 2009, we have seen a general appreciation of emerging market currencies against the U.S. dollar.

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Acquisitions and Future Greenfield Development. We have historically grown our business 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 affect the period comparison of our financial statements. We intend to continue growing our business through organic growth and additional acquisitions utilizing our cash on hand, financing where we deem the price acceptable, and our ordinary shares as currency, as well as through greenfield development. As a result of these growth initiatives, our future financial results will continue to reflect substantial changes compared to historical results. In addition, 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 timing 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 in an attempt 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 unclear what the ultimate regulatory structure will be. In most of these markets, the common trend has been to establish conditions that foster and rely on the participation of the private sector in providing the needed infrastructure to support the current growth pattern of energy consumption. We believe that this trend will continue in most of the markets that we serve.

Tariff Reviews. The tariffs of our regulated businesses, particularly those in the Power Distribution, Natural Gas Transportation and Services and Natural Gas Distribution segments, are periodically reviewed by regulators. These tariffs are reset 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.

Current Market Developments. Material declines in asset values held by financial institutions over the past two years have resulted in significant write-downs of financial assets. Reflecting concern about the stability of the financial markets generally and the strength of counterparties, many lenders and investors ceased to provide funding to even the most credit worthy borrowers or to other financial institutions. While there have been improvements in the conditions of the capital markets, if lack of available credit and lack of confidence in the financial markets persist, there may be a material and adverse effect on our financial condition and results of operations and our access to capital.

Commodity Price Changes. 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 operating income. These commodity price changes also affect our operations in several other ways; for example, steel and copper prices 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

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which we operate, identifying within the available and practical alternatives, energy solutions that have the least negative impact on the community.

Recent Developments in 2009

Since the date of our most recent audited financial statements, there have been a number of developments affecting our business, the most significant of which are described below:


	•	In January 2009, AEI and Centrans, a local Central American investment group, contributed their respective interests in various Nicaraguan power generation businesses to a common holding company, Nicaragua Energy Holdings. Currently, we own 57.67% and Centrans owns 42.33% of Nicaragua Energy Holdings, which indirectly owns 100.00% of Corinto and Tipitapa and a 22.05% interest in Amayo. Subject to obtaining consent from the other shareholder of Amayo, Centrans intends to contribute to Nicaragua Energy Holdings an additional interest indirectly representing 22.95% of Amayo. Following that contribution, we will own 51.6% and Centrans will own 48.40% of Nicaragua Energy Holdings. In addition, Centrans was given 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 50.00%.

	•	In January 2009, we terminated our restructuring agreement with CIESA, an Argentine company that currently holds a majority of the outstanding share capital of TGS. Pursuant to this agreement, the debt that we held in CIESA was to be converted into equity of CIESA, subject to the receipt of various regulatory approvals prior to an agreed deadline. After extending this deadline twice, we terminated this agreement due to the fact that the requested approvals were not obtained. Following the termination, CIESA brought an action in New York against us seeking to avoid their payment obligations under the debt. Separately, in February 2009, we filed a petition in Argentina for the involuntary bankruptcy liquidation of CIESA, and this process is ongoing. See “Business — Legal Proceedings” for additional information. We currently hold an option to acquire, indirectly, an approximately 10% equity interest in CIESA. We acquired the option on September 3, 2009 in conjunction with the acquisition of certain other assets in exchange for a combination of cash and ordinary shares of AEI. If we choose to exercise this option, closing of the transaction will be subject to regulatory approvals in Argentina. On September 25, 2009, we acquired a 7.65% interest in TGS in exchange for ordinary shares of AEI.

	•	The build, operate and transfer agreement, or BOT agreement, between Subic and National Power Corporation of the Philippines, or NPC, expired on schedule in February 2009 and the plant was turned over to NPC.


	•	On May 29, 2009, we acquired a 19.91% interest in EMDERSA, an Argentine power distribution holding company, in exchange for a combination of cash and ordinary shares of AEI. On August 27, 2009, we acquired an additional 4.50% interest in EMDERSA for a cash purchase price of approximately $7 million; on September 24, 2009, we acquired an additional 25.61% of EMDERSA for approximately $41 million; and on October 13, 2009, we acquired an additional 27.09% of EMDERSA for approximately $43 million. As a result of these transactions, as of the date of this prospectus, we own 77.11% of the outstanding shares of EMDERSA. In connection with our acquisition of control of EMDERSA, we are required under Argentine law to make a tender offer for the remaining outstanding shares of EMDERSA and have initiated this process. We expect this tender offer to close in late 2009.


	•	On June 17, 2009, we made a third capital contribution to Emgasud of $15 million, which increased our ownership interest in Emgasud to 37.00%. In addition, the agreement pursuant to which we acquired our interest in Emgasud provides for the acquisition by us or our affiliates of up to a total 63.10% interest in Emgasud through our contribution of certain assets to Emgasud, subject to certain conditions including local regulatory and antitrust approvals.

	•	In August 2009, we purchased $15 million in principal amount of 19% senior unsecured convertible note due in July 2012 from Emgasud. The proceeds of this note are to be used to complete the development of the Energía Distribuida power generation project and related

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		investments and for working capital and other operating expenses. The note is unsecured and is structurally subordinate to the senior secured bonds of Emgasud, but our consent is required for Emgasud to incur any additional debt.


	•	On August 27, 2009, we acquired an additional 31.00% interest in Trakya as a result of which we own 90.00% of Trakya.

	•	As of September 8, 2009, we signed agreements with certain shareholders of Luz del Sur pursuant to which we will acquire an additional 13.65% in Luz del Sur in exchange for 7,225,958 AEI shares. The closing of this transaction is subject to certain conditions, including the listing of our shares on an approved exchange, including the NYSE. Under a shareholders agreement with Sempra, Sempra has the right to participate pro rata in this acquisition. If Sempra exercises this right, we will only acquire an additional 6.82% of Luz del Sur. If Sempra does not participate, then we will be required to launch a tender offer that may result in us acquiring up to a further 10.35% (in addition to 13.65%) in Luz del Sur.

	•	On September 11, 2009, we signed a non binding Letter of Intent with PDVSA Gas pursuant to which we agreed to transfer our interest in Accroven to PDVSA Gas. Closing of this transaction is subject to negotiation of definitive documentation and the receipt of third party consents.


	•	On September 23, 2009, we signed an agreement to acquire, at a price of approximately US$15 million, a 49% interest in NBT Baicheng New Energy Development Co., Ltd., a company that owns a 49.5MW wind farm under construction in the Jilin Province of China. The closing of the acquisition is expected to occur in 2009, subject to the satisfaction of certain conditions, including NBT Baicheng having obtained certain local government permits and having reached certain milestones with respect to obtaining financing. Upon the consummation of this transaction, we will control the board and will appoint key management personnel for NBT Baicheng.

Critical Accounting Policies and Estimates

This “Management’s Discussion and Analysis of Financial Condition and Results of Operations” is based upon AEI’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, accruals for income taxes, accruals for long-term employee benefit costs such as pension and other postretirement costs, foreign currency translation and measurement and contingencies. Inherent in such policies are certain key assumptions and estimates made by management. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates, which by their nature bear the risk of change related to the ability to accurately forecast a future event and its potential impact. Management periodically updates its estimates used in the preparation of the consolidated financial statements based on its latest assessment of the current and projected business and general economic environment. These critical accounting policies have been discussed with the Audit Committee of the Board of Directors. Significant accounting policies are summarized in Note 2 to the consolidated financial statements for the year ended December 31, 2008.

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 it is determined that we are the primary beneficiary. Investments in entities where we hold an ownership interest of at least 20%, and which we neither control nor are the primary beneficiary but for which we exercise significant influence, are accounted for under the equity method of accounting. Other investments, in which we own less than a 20% interest, unless we can clearly exercise significant influence over operating and financing policies, are recorded at cost. The consolidated financial statements are presented in accordance with U.S. GAAP.

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Acquisition Accounting

The purchase method of accounting is used for accounting for acquired businesses and 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 acquisitions include the following:

For acquired 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 Power 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 three to 50 years. Depreciation and amortization expense of these assets under the straight-line method over their estimated useful lives totaled $268 million in 2008 and $129 million for the six months ended June 30, 2009. If the useful lives of the assets were found to be shorter than originally estimated, depreciation and amortization charges would be accelerated over the revised useful life.

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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 of 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 the wholesale and retail sale of gasoline and CNG.

Revenues from the sale of energy are recognized in the period in which the energy is delivered. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. 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 PPA based on a constant periodic rate of return. Contingent rentals are recognized as received. Further information on the accounting for direct financing leases can be found in Note 13 to the consolidated financial statements. 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 $77 million at June 30, 2009.

Regulatory Assets and Liabilities

For regulated entities, assets and liabilities that result from the regulator rate-making process are recorded, which would not be recorded under U.S. GAAP in the case of non-regulated entities. We capitalize incurred allowable costs as deferred regulatory assets if it is probable that future revenue at least equal to the costs incurred will be billed and collected through approved rates. If future recovery of costs is not considered probable, the incurred cost is recognized as an expense. Regulatory liabilities are recorded for amounts expected to be passed to the customer as refunds or reductions on future billings. Regulatory assets totaled $120 million and regulatory liabilities totaled $116 million at June 30, 2009.

Income Taxes

We operate through various subsidiaries in many countries throughout the world. Deferred tax assets and liabilities are recognized based on the estimated future tax effects of differences between the financial statement and tax bases of assets and liabilities given the enacted tax laws. Income taxes have been provided based upon the tax laws and rates of the countries in which operations are conducted and income is earned. The need for a deferred tax asset valuation allowance is evaluated by assessing whether it is more likely than not that deferred tax assets will be

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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, 2008 funded status. A one percentage point reduction in the assumed discount rates would increase our benefit obligation for pensions and other postretirement benefits by approximately $33 million, and would reduce our net income by approximately $3 million. Based on the market value of plan assets at December 31, 2008, a one percentage point decrease in the expected rate of return on plan assets assumption would decrease our net income by approximately $2 million.

In certain countries, including Colombia, El Salvador, Guatemala, Nicaragua and Panama, local labor laws require us to pay severance indemnities to employees when their employment is terminated. In Argentina, EDEN is required to pay certain benefits to employees upon retirement. We accrue these benefits based on historical experience and third party evaluations.

Foreign Currency

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

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We have determined that the functional currency for some subsidiaries is the U.S. dollar due to their operating, financing, and other contractual arrangements. For the periods presented, the businesses that are considered to have their local currency as the functional currency are EDEN, Emgasud S.A., or Emgasud, and EMDERSA in Argentina; Tongda Energy Private Limited, or Tongda, BMG and Luoyang in China; Elektro in Brazil; DHA Cogen Limited, or DCL, in Pakistan; Elektrocieplownia Nowa Sarzyna Sp.z.o.o., or ENS, in Poland; Chilquinta in Chile; Luz del Sur in Peru; and certain operating companies of Promigas in Colombia.

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

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 21 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.

Recent Accounting Policies

In September 2006, the FASB issued 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 statements of operations. We adopted the remaining requirements of SFAS No. 157 on January 1, 2009 and the adoption will impact the recognition of nonfinancial assets and liabilities in future business combinations and the future determinations of impairment for nonfinancial assets and liabilities.

In February 2007, the FASB issued 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 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 have elected not to adopt the fair value option for any eligible assets nor liabilities.

In December 2007, the FASB issued Statement No. 141 (Revised 2007), Business Combinations, or 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 nature and financial effects of the business combination. We adopted SFAS No. 141R on January 1, 2009 and are applying the provisions to business combinations entered into subsequent to that date.

In December 2007, the FASB issued 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

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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 have incorporated the changes in our financial statement presentation for all periods presented.

In November 2008, the FASB issued EITF Issue No. 08-6, Equity Method Investment Accounting Considerations, or EITF Issue No. 08-6. EITF Issue No. 08-6 establishes that the accounting application of the equity method is affected by the accounting for business combinations and the accounting for consolidated subsidiaries, which were affected by the issuance of SFAS No. 141R and SFAS No. 160. EITF Issue No. 08-6 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years, consistent with the effective dates of SFAS No. 141R and SFAS No. 160. We adopted EITF Issue No. 08-6 on January 1, 2009 and are applying the provisions to any future equity method investments.

Although past transactions would have been accounted for differently under SFAS No. 141R, SFAS No. 160 and EITF Issue No. 08-6, application of these statements in 2009 will not affect historical amounts.

In March 2008, the 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. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009 and we incorporated the changes in our financial statements.

In April 2009, the FASB issued FASB Staff Position (“FSP”) FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which requires disclosures about fair value of financial instruments in interim reporting periods of publicly traded companies that were previously only required to be disclosed in annual financial statements. The provisions of FSP FAS 107-1 and APB 28-1 are effective for interim and annual periods ending after June 15, 2009. We have incorporated the additional disclosure requirements in our financial statements for the quarter ended June 30, 2009.

In April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This FSP provides additional guidance on estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for an asset or liability have significantly decreased in relation to normal market activity for the asset or liability. FSP FAS 157-4 also provides guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009 and we have incorporated the additional disclosure requirements in our consolidated financial statements beginning with the quarter ended June 30, 2009.

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” which amends current other-than-temporary impairment guidance for debt securities to make it more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This FSP does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual periods ending after June 15, 2009. We have incorporated the additional disclosure requirements in our consolidated financial statements beginning with the quarter ended June 30, 2009.

In May 2009, the FASB issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions of SFAS No. 165 are effective for interim and annual periods ending after June 15, 2009. We adopted SFAS No. 165 as of June 30, 2009 and there was no significant impact on our consolidated financial statements.

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relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement in transferred financial assets. The provisions of SFAS No. 166 are effective for interim and annual reporting periods beginning after November 15, 2009. We will adopt this Statement on January 1, 2010 and apply this Statement and related disclosure provisions to transfers occurring on or after the effective date.

In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 amends certain requirements of FASB Interpretation No. 46 (Revised December 2003), “Consolidation of Variable Interest Entities” to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. The provision of SFAS No. 167 are effective for interim and annual reporting periods beginning after November 15, 2009. We will adopt this Statement on January 1, 2010 and have not determined the impact, if any, on our consolidated financial statements.

In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification TM and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 replaced FASB Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles” and identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will adopt this Statement for the interim period ending September 30, 2009 and incorporate the new codification in its consolidated financial statements. While the adoption of SFAS No. 168 will not have an impact on our consolidated financial statements, SFAS No. 168 will impact the reference to authoritative and non-authoritative accounting literature within the notes.

Discussion of Results of Operations

As discussed in “History and Development,” 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 was acquired in two stages, accounted for as a purchase step acquisition, as follows:


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

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

In addition, during 2007, 2008 and the first six months of 2009, we completed a series of acquisitions and divestitures (see Notes 1 and 3 to the consolidated financial statements for the year ended December 31, 2008 and the unaudited condensed consolidated financial statements for the six months ended June 30, 2009).

As a result, our historical consolidated financial statements are not directly comparable because:


	•	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, 2008 and 2009.

Included below is a discussion comparing AEI’s 2008, 2007 and 2006 audited results, as well as a discussion comparing the six months ended June 30, 2009 and 2008 unaudited results.

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.

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

Revenues


	•	Power Distribution revenues are derived primarily from contracts with retail customers in the residential, industrial and commercial sectors. These revenues are based on tariffs which are reviewed by the applicable regulator on a periodic basis, and recognized upon delivery. In addition to a reasonable rate of return on regulatory assets and other amounts, tariffs include a pass-through of nearly all wholesale energy costs included in our Power Distribution cost of sales. 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 capacity and energy primarily under long-term contracts to large off-takers. Certain contracts contain decreasing rate schedules, which results in revenues being deferred due to differences between the amounts billed to customers and the average revenue stream over the life of the contract.

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

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

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

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, significant costs are not incurred in the Natural Gas Transportation and Services businesses because we do not purchase the commodities being transported.

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

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include the salaries and benefits of the personnel in that office as well as professional services contracted on behalf of the entire organization that do not pertain or relate to a particular business or group of businesses.

Foreign Currency

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

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


	December 31,						June 30,
	2006		2007		2008		2008		2009

Period-end exchange rates:
Brazilian real		2.14		1.77		2.40		1.61		1.96
Colombian peso		2,240		2,044		2,253		1,903		2,090


	For the Six Months Ended June 30,
	2008		2009

Average period exchange rates:
Brazilian real		1.70		2.18
Colombian peso		1,862		2,350


	For the Year Ended December 31
	2006		2007		2008

Average period exchange rates:
Brazilian real		2.18		1.95		1.83
Colombian peso		2,424		2,120		1,990

Source: Bloomberg financial website for June 2009 and December 2008; OANDA Corporation financial website for other periods presented.

AEI Results of Operations

The results of the following businesses are reflected in the results of continuing operations in the periods indicated. For additional information, see “— Critical Accounting Policies and Estimates — Basis of Presentation.”


	For the Year Ended December 31,			For the Six Months Ended June 30,
	2006	2007	2008	2008	2009

Power Distribution
Chilquinta	—	Equity Method⁽⁷⁾	Equity Method	Equity Method	Equity Method
Delsur	—	Consolidated⁽⁷⁾	Consolidated	Consolidated	Consolidated
EDEN	—	Consolidated⁽⁷⁾	Consolidated	Consolidated	Consolidated
Elektra	Consolidated	Consolidated	Consolidated	Consolidated	Consolidated
Elektro	Consolidated⁽¹⁾	Consolidated	Consolidated	Consolidated	Consolidated
EMDERSA	—	—	—	—	Equity Method⁽¹⁰⁾
Luz del Sur	—	Equity Method⁽⁷⁾	Equity Method	Equity Method	Equity Method

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	For the Year Ended December 31,			For the Six Months Ended June 30,
	2006	2007	2008	2008	2009

Power Generation
Amayo	—	—	—	—	Equity Method^(10)(11)
BLM⁽²⁾	Consolidated⁽¹⁾	—	—	—	—
Corinto	Equity Method⁽¹⁾	Consolidated⁽³⁾	Consolidated	Consolidated	Consolidated⁽¹¹⁾
Cuiabá — EPE	Consolidated⁽¹⁾	Consolidated	Consolidated	Consolidated	Consolidated
DCL	—	—	Consolidated⁽⁸⁾	—	Consolidated
ENS	Consolidated⁽¹⁾	Consolidated	Consolidated	Consolidated	Consolidated
Emgasud	—	—	Equity Method⁽⁸⁾	—	Equity Method⁽¹²⁾
Fenix	—	—	Consolidated⁽⁸⁾	Consolidated	Consolidated
Jaguar	—	—	Consolidated⁽⁸⁾	Consolidated	Consolidated
JPPC	—	Consolidated⁽⁷⁾	Consolidated	Consolidated	Consolidated
Luoyang	—	—	Consolidated⁽⁸⁾	Consolidated	Consolidated
PQP	Consolidated⁽¹⁾	Consolidated	Consolidated	Consolidated	Consolidated
San Felipe	Consolidated⁽¹⁾	Consolidated	Consolidated	Consolidated	Consolidated
Subic	Equity Method⁽¹⁾	Equity Method	Equity Method	Equity Method	—
Tipitapa	—	—	Consolidated⁽⁸⁾	Consolidated	Consolidated⁽¹¹⁾
Trakya	Consolidated⁽¹⁾	Consolidated	Consolidated	Consolidated	Consolidated
Natural Gas Transportation and Services
Accroven	Equity Method⁽¹⁾	Equity Method	Equity Method	Equity Method	Equity Method
Centragas⁽⁵⁾	Equity Method⁽⁴⁾	Equity Method	Equity Method	Equity Method	Equity Method
Cuiabá — GOB/GOM/TBS	Consolidated⁽¹⁾	Consolidated	Consolidated	Consolidated	Consolidated
GBS⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
GTB	Equity Method⁽¹⁾	Equity Method	Cost Method⁽⁶⁾	Cost Method	Cost Method
Promigas	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
PSI⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
TBG	Cost Method⁽¹⁾	Cost Method	Cost Method	Cost Method	Cost Method
Transmetano⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
Transoccidente⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
Transoriente⁽⁵⁾	Equity Method⁽⁴⁾	Equity Method	Equity Method	Equity Method	Equity Method
Transredes	Equity Method⁽¹⁾	Equity Method	Cost Method⁽⁶⁾	Cost Method	Cost Method
Natural Gas Distribution
BMG	—	Cost Method⁽⁷⁾	Consolidated	Consolidated	Consolidated
Cálidda	—	Consolidated⁽⁷⁾	Consolidated	Consolidated	Consolidated
Gases de Occidente⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
Gases del Caribe⁽⁵⁾	Equity Method⁽⁴⁾	Equity Method	Equity Method	Equity Method	Equity Method
Surtigas⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
Tongda	—	Consolidated⁽⁷⁾	Consolidated	Consolidated	Consolidated
Retail Fuel
Gazel⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated
SIE⁽⁵⁾	Equity Method⁽⁴⁾	Equity Method	Consolidated⁽⁹⁾	Consolidated	Consolidated
Other
Promitel⁽⁵⁾	Equity Method⁽⁴⁾	Consolidated	Consolidated	Consolidated	Consolidated


(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.

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(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 3 to the consolidated financial statements for the year ended December 31, 2008.
(7)		The Company’s initial interest was acquired during 2007.
(8)		The Company’s initial interest was acquired during 2008.
(9)		On January 2, 2008, Promigas contributed its ownership interests in Gazel to SIE in exchange for additional shares of SIE. As a result of this transaction, Promigas’ ownership in SIE increased from 37.19% as of December 31, 2007 to 54% with SIE owning 100% of Gazel. See Note 3 to consolidated financial statements for year ended December 31, 2008.
(10)		The Company’s initial interest was acquired during 2009.
(11)		During the first quarter of 2009, as part of the Nicaragua Energy Holdings (“NEH”) transaction, AEI’s ownership in Corinto increased from 50% to 57.67% and AEI’s ownership in Tipitapa decreased from 100% to 57.67%. See Note 3 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.
(12)		In June 2009, the Company increased its ownership in Emgasud S.A. from 31.89% to 37.00%. See Note 3 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.

Three Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008

The following discussion compares AEI’s results of continuing operations for the three months ended June 30, 2009 to the three months ended June 30, 2008.

Revenues

The table below presents our consolidated revenues by significant geographical location for the three months ended June 30, 2009 and 2008. Revenues are reported in the country in which they are earned.


	For the Three Months Ended June 30,
	2008		2009
	Millions of dollars (U.S.)

Colombia	$	1,037	$	826
Brazil		368		287
Chile		369		206
Panama		258		146
Turkey		51		76
El Salvador		43		57
Guatemala		62		50
China		28		34
Dominican Republic		77		38
Argentina		28		28
Other		113		108

Total revenues	$	2,434	$	1,856

The following table reflects revenues by segment:


	For the Three Months Ended June 30,
	2008			2009
	Millions of dollars (U.S.)

Power Distribution	$	538		$	455
Power Generation		283			237
Natural Gas Transportation and Services		48			51
Natural Gas Distribution		145			154
Retail Fuel		1,441			982
Headquarters/Other/Eliminations		(21	)		(23	)

Total revenues	$	2,434		$	1,856

Revenues decreased by $578 million to $1,856 million for the three months ended June 30, 2009 compared to $2,434 million for the three months ended June 30, 2008. The decrease was primarily due to the decrease in revenues at SIE ($465 million), Elektro ($68 million), San Felipe ($39 million) and Elektra ($29 million) as described below, partially offset by the increase in revenues at Trakya ($25 million) and Delsur ($14 million) as described below.

Power Distribution

Revenues from the Power Distribution segment decreased by $83 million to $455 million for the three months ended June 30, 2009 compared to $538 million for the three months ended June 30, 2008. The decrease was primarily due to decreased revenues at Elektro ($68 million) and Elektra ($29 million), partially offset by the increased revenues at Delsur ($14 million). The decreased revenues at Elektro were primarily due to the devaluation of the Brazilian real relative to the U.S. dollar. The decreased revenues at Elektra were primarily due to lower

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pricing ($32 million) as a result of the monthly and bi-annual tariff adjustments to the energy cost component of its customer tariff driven by lower fuel cost. The increased revenues at Delsur were primarily due to higher pricing ($16 million) as a result of the elimination of the government subsidy to power generators.

Power Generation

Revenues from the Power Generation segment decreased by $46 million to $237 million for the three months ended June 30, 2009 from $283 million for the three months ended June 30, 2008. The decrease was primarily due to decreased revenues at San Felipe ($39 million), PQP ($12 million), ENS ($11 million), Corinto ($7 million) and JPPC ($6 million), partially offset by additional revenues from the acquisition of interests in Tipitapa ($6 million) and increased revenues at Trakya ($25 million). The decreased revenues at San Felipe and Corinto were primarily due to lower fuel prices which were passed on to their customers and lower generation volume as a result of lower dispatch orders primarily due to higher availability of hydro generation. The decreased revenues at PQP and JPPC were primarily due to lower fuel prices which were passed on to their customers, partially offset by higher generation volume as a result of higher dispatch orders primarily due to the unavailability of other generation units. The decreased revenues at ENS were primarily due to the devaluation of the Polish Zloty relative to the U.S. dollar. The increased revenues at Trakya were primarily due to higher generation volume compared to the second quarter of 2008 which was lower due to major plant maintenance, partially offset by lower fuel prices which were passed on to its customers.

Natural Gas Transportation and Services

Revenues from the Natural Gas Transportation and Services segment increased by $3 million to $51 million for the three months ended June 30, 2009 compared to $48 million for the three months ended June 30, 2008. The increase was primarily due to higher revenues generated at the ancillary service business at Promigas as a result of a favorable tariff increase in June and December of 2008.

Natural Gas Distribution

Revenues from the Natural Gas Distribution segment increased by $9 million to $154 million for the three months ended June 30, 2009 compared to $145 million for the three months ended June 30, 2008. The increase was primarily due to increased revenues at Cálidda ($5 million) and BMG ($6 million). The increased revenues at Cálidda were primarily due to the higher volume distributed as a result of an increased customer base. The increased revenues at BMG were primarily due to increased connection fee and construction fee revenues as a result of an increased customer base.

Retail Fuel

Revenues from the Retail Fuel segment decreased by $459 million to $982 million for the three months ended June 30, 2009 compared to $1,441 million for the three months ended June 30, 2008. The decrease was primarily due to decreased revenues at SIE ($465 million). The decreased revenues at SIE were primarily due to the devaluation of the Colombian and Chilean pesos based on the average rates for the second three months of each year relative to the U.S. dollar, lower retail fuel prices passed on to customers and generally lower aviation fuel prices which are based on regulatory set rates.

Cost of Sales

The following table reflects cost of sales by segment:


	For the Three Months Ended June 30,
	2008			2009
	Millions of dollars (U.S.)

Power Distribution	$	333		$	291
Power Generation		218			169
Natural Gas Transportation and Services		4			4
Natural Gas Distribution		92			98
Retail Fuel		1,310			881
Headquarters/Other/Eliminations		(26	)		(25	)

Total cost of sales	$	1,931		$	1,418

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Cost of sales decreased by $513 million to $1,418 million for the three months ended June 30, 2009 compared to $1,931 million for the three months ended June 30, 2008. The decrease was primarily due to the decrease in cost of sales at SIE ($435 million), San Felipe ($46 million), Elektra ($30 million) and Elektro ($24 million) as described below, partially offset by the increase in cost of sales at Delsur ($15 million) and Trakya ($13 million) as described below.

Power Distribution

Cost of sales for the Power Distribution segment decreased by $42 million to $291 million for the three months ended June 30, 2009 compared to $333 million for the three months ended June 30, 2008. The decrease was primarily due to decreased cost of sales at Elektra ($30 million) and Elektro ($24 million), partially offset by increased cost of sales at Delsur ($15 million). The decreased cost of sales at Elektra was primarily due to lower average price of purchased electricity ($34 million) as a result of decreased fuel costs. The decreased cost of sales at Elektro was primarily due to the devaluation of the Brazilian real relative to the U.S. dollar ($37 million), partially offset by higher energy prices and transportation charges ($15 million). The increased cost of sales at Delsur was primarily due to the higher average price of purchased electricity ($16 million) as a result of the elimination of the government subsidy to power generators.

Power Generation

Cost of sales for the Power Generation segment decreased by $49 million to $169 million for the three months ended June 30, 2009 compared to $218 million for the three months ended June 30, 2008. The decrease was primarily due to decreased cost of sales at San Felipe ($46 million), PQP ($7 million), Corinto ($6 million) and ENS ($5 million), partially offset by increased cost of sales at Trakya ($13 million) and the additional cost of sales from the acquisition of an interest in Tipitapa in June 2008 ($4 million). The decreased cost of sales at San Felipe and Corinto was primarily due to lower fuel prices and reduced generation due to lower dispatch orders primarily due to higher availability of hydro generation. The decreased cost of sales at PQP was primarily due to the lower fuel prices, partially offset by higher generation volume primarily due to the unavailability of other generation units. The decreased cost of sales at ENS was primarily due to the devaluation of the Polish Zloty relative to the U.S. dollar ($7 million). The increased cost of sales at Trakya was primarily due to higher generation volume compared to the second quarter of 2008 which was lower due to major plant maintenance, partially offset by lower fuel prices.

Natural Gas Transportation and Services

Cost of sales for the Natural Gas Transportation and Services segment were $4 million for the three months ended June 30, 2009 and 2008 primarily associated with Promigas and TBS which incur marginal costs for the purchase of gas and management services.

Natural Gas Distribution

Cost of sales for the Natural Gas Distribution segment increased by $6 million to $98 million for the three months ended June 30, 2009 compared to $92 million for the three months ended June 30, 2008. The increase was primarily due to the increased cost of sales at Cálidda primarily due to higher distribution volume as a result of an increased customer base.

Retail Fuel

Cost of sales for the Retail Fuel segment decreased by $429 million to $881 million for the three months ended June 30, 2009 compared to $1,310 million for the three months ended June 30, 2008. The decrease was primarily due to the decreased cost of sales at SIE ($435 million) as a result of the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar and a decrease in fuel prices.

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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 Three Months Ended June 30,
	2008		2009
	Millions of dollars (U.S.)

Power Distribution	$	80	$	64
Power Generation		38		16
Natural Gas Transportation and Services		18		15
Natural Gas Distribution		19		26
Retail Fuel		43		49
Headquarters/Other/Eliminations		23		17

Total operations, maintenance and general and administrative expenses	$	221	$	187

Operations, maintenance and general and administrative expenses decreased by $34 million to $187 million for the three months ended June 30, 2009 compared to $221 million for the three months ended June 30, 2008. The overall general decrease was in part due to the appreciation of the U.S. dollar and AEI’s focus on conserving cash in response to the global economic crisis. This effort resulted in a decrease in operations, maintenance and general and administrative expenses across most areas of the Company. The decrease was primarily due to decreases at Trakya ($22 million) and Elektro ($11 million) as described below. In addition, the operations, maintenance and general and administrative expenses at the parent level decreased by $6 million as a result of the decreased expenses for outside services and professional fees.

Power Distribution

Operations, maintenance and general and administrative expenses for the Power Distribution segment decreased by $16 million to $64 million for the three months ended June 30, 2009 compared to $80 million for the three months ended June 30, 2008. The decrease was primarily due to decreases at Elektro ($11 million) and EDEN ($5 million). The decrease at Elektro was primarily due to the devaluation of the Brazilian real relative to the U.S. dollar and reduced operations, maintenance and general and administrative expenses in many areas as a result of the increased focus on conserving cash. The decrease at EDEN ($5 million) was primarily associated with the reversal of a previously accrued penalty provision related to operations that was authorized by the Argentine government in May 2009.

Power Generation

Operations, maintenance and general and administrative expenses for the Power Generation segment decreased by $22 million to $16 million for the three months ended June 30, 2009 compared to $38 million for the three months ended June 30, 2008. The decrease was primarily due to a decrease at Trakya ($22 million) as a result of the absence of cost related to major plant maintenance performed during the second quarter of 2008.

Natural Gas Transportation and Services

Operations, maintenance and general and administrative expenses for the Natural Gas Transportation and Services segment decreased by $3 million to $15 million for the three months ended June 30, 2009 compared to $18 million for the three months ended June 30, 2008. The decrease was primarily due to the decreases at Promigas and its subsidiaries as a result of the devaluation of the Colombia peso relative to the U.S. dollar.

Natural Gas Distribution

Operations, maintenance and general and administrative expenses for the Natural Gas Distribution segment increased by $7 million to $26 million for the three months ended June 30, 2009 compared to $19 million for the three months ended June 30, 2008. The increase was primarily due to increases in provisions for doubtful accounts and outside services at one of Promigas’ subsidiaries and an increase in professional fees at other subsidiaries.

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Retail Fuel

Operations, maintenance and general and administrative expenses for the Retail Fuel segment increased by $6 million to $49 million for the three months ended June 30, 2009 compared to $43 million for the three months ended June 30, 2008. The increase was primarily due to the increased operations, maintenance and general and administrative expenses at SIE as a result of an increase in maintenance and operating lease expenses due to an increase in the number of gas stations and higher rental expenses, partially offset by the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar.

Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the Three Months Ended June 30,
	2008		2009
	Millions of dollars (U.S.)

Power Distribution	$	37	$	32
Power Generation		5		11
Natural Gas Transportation and Services		6		5
Natural Gas Distribution		5		5
Retail Fuel		25		14
Headquarters/Other/Eliminations		2		2

Total depreciation and amortization expenses	$	80	$	69

Total depreciation and amortization expenses decreased by $11 million to $69 million for the three months ended June 30, 2009 compared to $80 million for the three months ended June 30, 2008. The decrease was primarily due to the decreased depreciation and amortization expenses at Elektro ($6 million) as a result of the devaluation of the Brazilian real relative to the U.S. dollar.

(Gain) Loss on Disposition of Assets

During the three months ended June 30, 2009, AEI recorded a net loss on disposition of assets totaling $5 million compared to a net loss of $15 million for the three months ended June 30, 2008. The loss in 2009 was primarily related to the ordinary course sale of operating equipment of Elektro. During the three months ended June 30, 2008, AEI recognized a loss of $14 million on the sale of debt securities of Gas Argentina S.A.

Equity Income from Unconsolidated Affiliates

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


	For the Three Months Ended June 30,
	2008		2009
	Millions of dollars (U.S.)

Power Distribution	$	20	$	18
Power Generation		2		—
Natural Gas Transportation and Services		8		4
Natural Gas Distribution		3		3
Retail Fuel		—		—
Headquarters/Other/Eliminations		—		(2	)

Total equity income from unconsolidated affiliates	$	33	$	23

Equity income from unconsolidated affiliates decreased by $10 million to $23 million for the three months ended June 30, 2009 compared to $33 million for the three months ended June 30, 2008. The decrease was primarily due to the decreased equity income at Transredes ($4 million), Chilquinta ($2 million) and Subic ($2 million). Transredes is no longer accounted for as an equity investment due to the nationalization of Transredes during the second quarter of 2008. The decreased equity income at Chilquinta was primarily due to the devaluation of the Chilean Peso relative to the U.S. dollar. The decreased equity income at Subic was primarily due to the expiration of BOT between Subic and NPC in February 2009, which required the Company to turn over the plant to the NPC.

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Operating Income

As a result of the factors discussed above, AEI’s operating income for the three months ended June 30, 2009 decreased by $15 million to $190 million compared to $205 million for the three months ended June 30, 2008. The following table reflects the contribution of each segment to operating income in the comparative periods:


	For the Three Months Ended June 30,
	2008			2009
	Millions of dollars (U.S.)

Power Distribution	$	102		$	80
Power Generation		19			40
Natural Gas Transportation and Services		29			29
Natural Gas Distribution		33			27
Retail Fuel		56			33
Headquarters/Other/Eliminations		(34	)		(19	)

Total operating income	$	205		$	190

Interest Income

Interest income was $18 million for both of the three months ended June 30, 2009 and 2008. Of the interest income earned during the three months ended June 30, 2009 and 2008, 56% 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 decreased by $21 million to $80 million for the three months ended June 30, 2009 compared to $101 million for the three months ended June 30, 2008. The decrease was primarily due to the decreased interest expense at Elektro, Promigas and the parent level, partially offset by increased interest expense at various operating companies. Interest expense at Elektro decreased by $13 million to $11 million due primarily to lower interest rates and the devaluation of the Brazilian real relative to the U.S. dollar. Interest expense at Promigas decreased by $10 million to $22 million due primarily to the lower interest rate on variable rate debt and the devaluation of the Colombian peso relative to the U.S. dollar based on the average exchange rates in the second quarter of 2009 when compared to the average rates in the same quarter of 2008. Interest expense at the parent level decreased by $3 million to $28 million due primarily to the conversion of PIK notes and lower interest rates on variable rate debt.

Foreign Currency Transaction Gain (Loss), Net

Total foreign currency transaction gains were $45 million for the three months ended June 30, 2009 compared to foreign currency transaction losses of $7 million for the three months ended June 30, 2008. During the three months ended June 30, 2009, the foreign currency transaction gains were primarily associated with U.S. dollar denominated debt instruments ($152 million as of June 30, 2009) held by Promigas and certain of its subsidiaries as a result of the appreciation of the Colombian peso relative to the U.S. dollar in the second quarter of 2009. During the three months ended June 30, 2008, the foreign currency transaction losses were primarily associated with the U.S. dollar denominated debt instruments ($305 million as of June 30, 2008) held by Promigas and certain of its subsidiaries as a result of the devaluation of the Colombian peso relative to the U.S. dollar, partially offset by foreign currency gains due to the revaluation of a portion of the lease investments at EPE, accounted for as a lease through December 31, 2008, as a result of the appreciation of the Brazilian real relative to the U.S. dollar.

Other Income (Expense)

AEI recognized $56 million of other income for the three months ended June 30, 2009 compared to $5 million of other expense for the three months ended June 30, 2008. The income recognized in 2009 was primarily due to a reversal of a provision in the second quarter. Elektro had previously accrued approximately $49 million associated with the calculation of the required social contribution on revenue and the contribution to the government social integration program. In May 2009, a newly enacted Brazilian law revoked a previous law which resulted in a change in the methodology by which such contributions should be calculated. See Note 4 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.

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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 June 30, 2009 and 2008 was $51 million and $41 million, respectively. The estimated effective income tax rate for the three months ended June 30, 2009 and 2008 was 22.0% and 37.3%, respectively. The decrease in the effective tax rate for the second quarter of 2009 was primarily due to the reversal of San Felipe accruals for uncertain tax positions due to the expiration of the statute of limitations and the reversal of a provision at EDEN due to the expiration of a statute of limitations. The effective tax rate exceeds the Cayman statutory rate of 0% primarily due to losses generated by the Company in its Cayman Island and certain of its Brazilian subsidiaries for which no tax benefit has been provided.

Noncontrolling Interests

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


	For the Three Months Ended June 30,
	2008			2009
	Millions of dollars (U.S.)

Promigas	$	8		$	51
Cuiaba		2			(4	)
Trakya		(2	)		5
DCL		—			(2	)
Elektra		2			3
Other		8			3

Total net income — noncontrolling interests	$	18		$	56

Net income — noncontrolling interests increased by $38 million to $56 million for the three months ended June 30, 2009 compared to $18 million for the three months ended June 30, 2008. The increase was primarily due to higher consolidated income for subsidiaries with noncontrolling interests, particularly Promigas and Trakya for the second quarter of 2009, partially offset by the losses incurred during the second quarter of 2009 at Cuiaba and DCL, each of which has noncontrolling interests.

Net Income Attributable to AEI

As a result of the factors discussed above, net income attributable to AEI for the three months ended June 30, 2009 was $125 million compared to net income attributable to AEI of $51 million for the three months ended June 30, 2008.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

The following discussion compares AEI’s results of continuing operations for the six months ended June 30, 2009 to the six months ended June 30, 2008.

Revenues

The table below presents our consolidated revenues by significant geographical location for the six months ended June 30, 2009 and 2008. Revenues are reported in the country in which they are earned. Intercompany revenues between countries have been eliminated in Other.

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	For the Six Months Ended June 30,
	2008		2009
	(In millions of $)

Colombia	$	1,970	$	1,612
Brazil		732		598
Chile		709		415
Panama		410		279
Turkey		161		202
El Salvador		82		107
Guatemala		110		87
China		46		71
Dominican Republic		122		70
Argentina		56		59
Other		206		203

Total revenues	$	4,604	$	3,703

The following table reflects revenues by segment:


	For the Six Months Ended June 30,
	2008			2009
	(In millions of $)

Power Distribution	$	1,055		$	917
Power Generation		557			507
Natural Gas Transportation and Services		102			99
Natural Gas Distribution		271			302
Retail Fuel		2,663			1,925
Headquarters/Other/Eliminations		(44	)		(47	)

Total revenues	$	4,604		$	3,703

Revenues decreased by $901 million to $3,703 million for the six months ended June 30, 2009 compared to $4,604 million for the six months ended June 30, 2008. The decrease was primarily due to the decrease in revenues at SIE ($749 million), Elektro ($116 million), San Felipe ($52 million), Elektra ($50 million) and PQP ($23 million) as described below, partially offset by acquisitions ($31 million) made in 2008 and the increase in revenues at Trakya ($41 million) and Delsur ($25 million) as described below.

Power Distribution

Revenues from the Power Distribution segment decreased by $138 million to $917 million for the six months ended June 30, 2009 compared to $1,055 million for the six months ended June 30, 2008. The decrease was primarily due to decreased revenues at Elektro ($116 million) and Elektra ($50 million), partially offset by the increased revenues at Delsur ($25 million). The decreased revenues at Elektro were primarily due to the devaluation of the Brazilian real relative to the U.S. dollar ($154 million), partially offset by higher pricing ($33 million) as a result of both a favorable tariff adjustment that occurred in August 2008 and an unfavorable 2007 tariff review that was definitively implemented in 2009. The decreased revenues at Elektra were primarily due to lower pricing ($53 million) as a result of the monthly and bi-annual tariff adjustments to the energy cost component of its customer tariff as a result of lower fuel costs. The increased revenues at Delsur were primarily due to higher pricing ($25 million) as a result of the elimination of the government subsidy to power generators.

Power Generation

Revenues from the Power Generation segment decreased by $50 million to $507 million for the six months ended June 30, 2009 from $557 million for the six months ended June 30, 2008. The decrease was primarily due to decreased revenues at San Felipe ($52 million), PQP ($23 million), ENS ($13 million), Corinto ($12 million) and JPPC ($12 million), partially offset by additional revenues from the acquisition of interests in Luoyang ($11 million) and Tipitapa ($15 million) and the increased revenues at Trakya ($41 million). The decreased revenues at San Felipe and Corinto were primarily due to lower fuel prices which were passed on to their customers and lower generation volume as a result of lower dispatch orders primarily due to higher availability of hydro generation. The decreased revenues at PQP and JPPC were primarily due to lower fuel prices which were passed on to their customers, partially offset by higher generation volume as a result of higher dispatch orders primarily due to unavailability of other generation units. The decreased revenues at ENS were primarily due to the devaluation of the Polish zloty relative to the U.S. dollar, partially offset by the stranded cost and fuel cost compensation obtained from

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the Polish government as a result of the voluntary termination of its Power Purchase Agreement (“PPA”) effective on April 1, 2008. The increased revenues at Trakya were primarily due to higher generation volume compared to the second quarter of 2008 which was lower due to major plant maintenance.

Natural Gas Transportation and Services

Revenues from the Natural Gas Transportation and Services segment decreased by $3 million to $99 million for the six months ended June 30, 2009 compared to $102 million for the six months ended June 30, 2008. The decrease was primarily due to lower revenues generated at Promigas as a result of lower transportation volume primarily due to lower industrial and generation demand for gas, partially offset by higher revenues generated at the ancillary service business at Promigas as a result of a favorable tariff increase in June and December of 2008.

Natural Gas Distribution

Revenues from the Natural Gas Distribution segment increased by $31 million to $302 million for the six months ended June 30, 2009 compared to $271 million for the six months ended June 30, 2008. The increase was primarily due to increased revenues at Promigas’ subsidiaries ($12 million), Cálidda ($9 million) and BMG ($11 million). The increased revenues at Promigas’ subsidiaries were primarily due to higher distribution volumes as a result of higher customer demand and higher distribution tariffs, partially offset by the devaluation of the Colombian peso relative to the U.S. dollar. The increased revenues at Cálidda were primarily due to the higher volume distributed as a result of an increased customer base. The increased revenues at BMG were primarily due to our acquisition of an additional interest in BMG on January 30, 2008 ($5 million) and the increased revenues as a result of the increased connection fee and construction fee revenues ($6 million).

Retail Fuel

Revenues from the Retail Fuel segment decreased by $738 million to $1,925 million for the six months ended June 30, 2009 compared to $2,663 million for the six months ended June 30, 2008. The decrease was primarily due to the devaluation of the Colombian and Chilean pesos based on the average rates for the first six months of each year relative to the U.S. dollar and lower retail fuel prices passed on to customers and generally lower aviation fuel prices which are based on regulatory set rates.

Cost of Sales

The following table reflects cost of sales by segment:


	For the Six Months Ended June 30,
	2008			2009
	(In millions of $)

Power Distribution	$	648		$	563
Power Generation		438			371
Natural Gas Transportation and Services		7			7
Natural Gas Distribution		173			191
Retail Fuel		2,428			1,735
Headquarters/Other/Eliminations		(52	)		(51	)

Total cost of sales	$	3,642		$	2,816

Cost of sales decreased by $826 million to $2,816 million for the six months ended June 30, 2009 compared to $3,642 million for the six months ended June 30, 2008. The decrease was primarily due to the decrease in cost of sales at SIE ($700 million), San Felipe ($66 million), Elektro ($56 million), Elektra ($50 million) and PQP ($20 million) as described below, partially offset by the increase in cost of sales at Trakya ($29 million) and Delsur ($25 million) as described below.

Power Distribution

Cost of sales for the Power Distribution segment decreased by $85 million to $563 million for the six months ended June 30, 2009 compared to $648 million for the six months ended June 30, 2008. The decrease was primarily due to decreased cost of sales at Elektro ($56 million) and Elektra ($50 million), partially offset by increased cost of sales at Delsur ($25 million). The decreased cost of sales at Elektro was primarily due to the devaluation of the Brazilian real relative to the U.S. dollar ($82 million), partially offset by higher energy prices and

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transportation charges ($23 million). The decreased cost of sales at Elektra was primarily due to a lower average price of purchased electricity ($56 million) as a result of decreased fuel costs. The increased cost of sales at Delsur was primarily due to the higher average price of purchased electricity ($25 million) as a result of the elimination of the government subsidy to power generators.

Power Generation

Cost of sales for the Power Generation segment decreased by $67 million to $371 million for the six months ended June 30, 2009 compared to $438 million for the six months ended June 30, 2008. The decrease was primarily due to the decreased cost of sales at San Felipe ($66 million), PQP ($20 million), Corinto ($12 million), ENS ($8 million) and JPPC ($7 million), partially offset by the increased cost of sales at Trakya ($29 million) and the additional cost of sales from the acquisition of interests in Tipitapa ($11 million) and Luoyang ($8 million) during June and February 2008, respectively. The decreased cost of sales at San Felipe and Corinto was primarily due to lower fuel prices and reduced generation volume due to lower dispatch orders primarily due to higher availability of hydro generation. The decreased cost of sales at PQP and JPPC was primarily due to the lower fuel prices, partially offset by higher generation volume primarily due to unavailability of other generation units. The decreased cost of sales at ENS was primarily due to the devaluation of the Polish zloty relative to the U.S. dollar ($14 million), partially offset by higher gas prices ($6 million). The increased cost of sales at Trakya was primarily due to higher generation volume compared to the second quarter of 2008 which was lower due to major plant maintenance.

Natural Gas Transportation and Services

Cost of sales for the Natural Gas Transportation and Services segment were $7 million for the six months ended June 30, 2009 and 2008 associated with Promigas and TBS which incur marginal costs for the purchase of gas and management services.

Natural Gas Distribution

Cost of sales for the Natural Gas Distribution segment increased by $18 million to $191 million for the six months ended June 30, 2009 compared to $173 million for the six months ended June 30, 2008. The increase was primarily due to the increased cost of sales at Promigas subsidiaries ($9 million) and Cálidda ($7 million). The increased cost of sales at Promigas’ subsidiaries was primarily due to higher customer demand and higher natural gas wellhead prices, partially offset by the devaluation of the Colombian peso relative to the U.S. dollar. The increased cost of sales at Cálidda was primarily due to higher distribution volume as a result of an increased customer base.

Retail Fuel

Cost of sales for the Retail Fuel segment decreased by $693 million to $1,735 million for the six months ended June 30, 2009 compared to $2,428 million for the six months ended June 30, 2008. The decrease was primarily due to the decreased cost of sales at SIE ($700 million) as a result of the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar and a decrease in fuel 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 Six Months Ended June 30,
	2008		2009
	(In millions of $)

Power Distribution	$	160	$	130
Power Generation		67		38
Natural Gas Transportation and Services		32		28
Natural Gas Distribution		35		39
Retail Fuel		109		92
Headquarters/Other/Eliminations		46		37

Total operations, maintenance and general and administrative expenses	$	449	$	364

Operations, maintenance and general and administrative expenses decreased by $85 million to $364 million for the six months ended June 30, 2009 compared to $449 million for the six months ended

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June 30, 2008. The overall general decrease was in part due to the appreciation of the U.S. dollar and AEI’s focus on conserving cash in response to the global economic crisis as described above. The decrease was primarily due to decreases at Elektro ($26 million), Trakya ($23 million) and SIE ($19 million) as described below. In addition, the operations, maintenance and general and administrative expenses at the parent level decreased by $9 million as a result of the decreased expenses for outside services and professional fees.

Power Distribution

Operations, maintenance and general and administrative expenses for the Power Distribution segment decreased by $30 million to $130 million for the six months ended June 30, 2009 compared to $160 million for the six months ended June 30, 2008. The decrease at Elektro ($26 million) was primarily due to the devaluation of the Brazilian real relative to the U.S. dollar and reduced operations, maintenance and general and administrative expenses in many areas as a result of the increased focus on conserving cash. The decrease at EDEN ($5 million) was primarily associated with the reversal of a previously accrued penalty provision related to operations that was authorized by the Argentine government in May 2009.

Power Generation

Operations, maintenance and general and administrative expenses for the Power Generation segment decreased by $29 million to $38 million for the six months ended June 30, 2009 compared to $67 million for the six months ended June 30, 2008. The decrease was primarily due to a decrease at Trakya ($23 million) as a result of major plant maintenance performed during the second quarter of 2008.

Natural Gas Transportation and Services

Operations, maintenance and general and administrative expenses for the Natural Gas Transportation and Services segment decreased by $4 million to $28 million for the six months ended June 30, 2009 compared to $32 million for the six months ended June 30, 2008. The decrease was primarily due to decreases at Promigas and its subsidiaries as a result of the devaluation of the Colombian peso relative to the U.S. dollar.

Natural Gas Distribution

Operations, maintenance and general and administrative expenses for the Natural Gas Distribution segment increased by $4 million to $39 million for the six months ended June 30, 2009 compared to $35 million for the six months ended June 30, 2008. The increase was primarily due to an increase in professional fees at certain subsidiaries.

Retail Fuel

Operations, maintenance and general and administrative expenses for the Retail Fuel segment decreased by $17 million to $92 million for the six months ended June 30, 2009 compared to $109 million for the six months ended June 30, 2008. The decrease was primarily due to the decreased operations, maintenance and general and administrative expenses at SIE as a result of the devaluation of the Colombian and Chilean pesos relative to the U.S. dollar, partially offset by an increase in maintenance and operating lease expenses due to the increase in the number of gas stations and higher rental expenses.

Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the Six Months Ended
	June 30,
	2008		2009
	(In millions of $)

Power Distribution	$	72	$	61
Power Generation		11		22
Natural Gas Transportation and Services		11		10
Natural Gas Distribution		9		11
Retail Fuel		26		22
Headquarters/Other/Eliminations		3		3

Total depreciation and amortization expenses	$	132	$	129

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Total depreciation and amortization expenses decreased by $3 million to $129 million for the six months ended June 30, 2009 compared to $132 million for the six months ended June 30, 2008. The decrease was primarily due to the decreased depreciation and amortization expenses at Elektro ($12 million) as a result of the devaluation of the Brazilian real relative to the U.S. dollar, partially offset by the additional depreciation and amortization expenses from acquisitions made in 2008 ($5 million) and the increased depreciation and amortization expenses at EPE ($3 million) as a result of the termination of lease accounting treatment for its power supply agreement as of December 31, 2008.

(Gain) Loss on Disposition of Assets

During the six months ended June 30, 2009, AEI recorded a net loss on disposition of assets totaling $10 million compared to a net gain of $53 million for the six months ended June 30, 2008. The loss in 2009 was primarily related to the ordinary course sale of operating equipment of Elektro. During the six months ended June 30, 2008, AEI recognized a gain of $74 million on the sale of 46% of Gazel when exchanged for a 17% additional interest in SIE, partially offset by a loss of $14 million on the sale of debt securities of Gas Argentina S.A. See Note 5 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.

Equity Income from Unconsolidated Affiliates

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


	For the Six Months Ended
	June 30,
	2008			2009
	(In millions of $)

Power Distribution	$	38		$	33
Power Generation		5			2
Natural Gas Transportation and Services		17			11
Natural Gas Distribution		8			6
Retail Fuel		1			—
Headquarters/Other/Eliminations		(1	)		(2	)

Total equity income from unconsolidated affiliates	$	68		$	50

Equity income from unconsolidated affiliates decreased by $18 million to $50 million for the six months ended June 30, 2009 compared to $68 million for the six months ended June 30, 2008. The decrease was primarily due to the decreased equity income at Transredes ($8 million), Chilquinta ($5 million) and Subic ($3 million). Transredes is no longer accounted for as an equity investment due to the nationalization of Transredes during the second quarter of 2008. The decreased equity income at Chilquinta was primarily due to the devaluation of the Chilean peso relative to the U.S. dollar. The decreased equity income at Subic was primarily due to the expiration of the 15-year BOT between Subic and NPC in February 2009, which required us to turn over the plant to the NPC.

Operating Income

As a result of the factors discussed above, AEI’s operating income for the six months ended June 30, 2009 decreased by $63 million to $413 million compared to $476 million for the six months ended June 30, 2008. The following table reflects the contribution of each segment to operating income in the comparative periods:


	For the Six Months Ended
	June 30,
	2008			2009
	(In millions of $)

Power Distribution	$	200		$	184
Power Generation		40			76
Natural Gas Transportation and Services		67			61
Natural Gas Distribution		61			65
Retail Fuel		166			67
Headquarters/Other/Eliminations		(58	)		(40	)

Total operating income	$	476		$	413

Operating income in the Retail Fuel segment decreased $99 million to $67 million for the six months ended June 30, 2009 compared to $166 million for the six months ended June 30, 2008 primarily due to the recognition of a $74 million gain in the first quarter of 2008 representing the gain on the sale of 46% of Gazel when exchanged for a

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17% additional interest in SIE. See Note 3 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009. Operating income in the Power Generation segment increased for the six months ended June 30, 2009, primarily at Trakya and San Felipe for the reasons described above.

Interest Income

Interest income decreased by $6 million to $35 million for the six months ended June 30, 2009 compared to $41 million for the six months ended June 30, 2008. Of the interest income earned during the six months ended June 30, 2009 and 2008, 49% and 52%, 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 was primarily due to the devaluation of Brazilian real relative to the U.S. dollar.

Interest Expense

Interest expense decreased by $34 million to $159 million for the six months ended June 30, 2009 compared to $193 million for the six months ended June 30, 2008. The decrease was primarily due to the decreased interest expense at Elektro and the parent level. Interest expense at Elektro decreased by $24 million to $18 million due primarily to lower interest rates and the devaluation of Brazilian real relative to the U.S. dollar. Interest expense at the parent level decreased by $10 million to $58 million due primarily to the conversion of PIK notes and lower interest rates on variable rate debt.

Foreign Currency Transaction Gain (Loss), Net

Total foreign currency transaction gains were $6 million (less than $1 million after tax and noncontrolling interests) for the six months ended June 30, 2009 compared to foreign currency transaction gains of $23 million for the six months ended June 30, 2008. During the six months ended June 30, 2009, the foreign currency transaction gains were primarily associated with U.S. dollar denominated debt instruments ($152 million as of June 30, 2009) held by Promigas and certain of its subsidiaries as a result of the appreciation of the Colombian peso relative to the U.S. dollar during the first six months of 2009. During the six months ended June 30, 2008, the foreign currency transaction gains were primarily associated with the revaluation of a portion of the lease investments at EPE, accounted for as a lease through December 31, 2008, as a result of the appreciation of the Brazilian real relative to the U.S. dollar and the revaluation of the U.S. dollar denominated debt instruments ($305 million as of June 30, 2008) held by Promigas and certain of its subsidiaries as a result of the appreciation of the Colombian peso relative to the U.S. dollar.

Other Income (Expense)

AEI recognized $50 million of other income for the six months ended June 30, 2009, compared to $2 million of other income for the six months ended June 30, 2008. The income recognized in 2009 was primarily due to a reversal of a provision in the second quarter. Elektro had previously accrued approximately $49 million ($32 million after tax and noncontrolling interests) associated with the calculation of the required social contribution on revenue and the contribution to the government social integration program. In May 2009, a newly enacted Brazilian law revoked a previous law which resulted in a change in the methodology by which such contributions should be calculated. See Note 4 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.

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 subsidiaries in 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 six months ended June 30, 2009 and 2008 was $127 million and $119 million, respectively. The estimated effective income tax rate for the six months ended June 30, 2009 and 2008 was 36.5% and 34.1%, respectively, which was higher than the statutory rate primarily due to losses generated by the Company in its Cayman Island and certain of its Brazilian subsidiaries for which no tax benefit has been provided and which increased the effective tax rate for this period.

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Noncontrolling Interests

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


	For the Six Months Ended
	June 30,
	2008			2009
	(In millions of $)

Promigas	$	124		$	48
Cuiaba		(6	)		(10	)
Trakya		3			11
DCL		—			(4	)
Elektra		4			5
Other		(1	)		3

Total net income — noncontrolling interests	$	124		$	53

Net income — noncontrolling interests decreased by $71 million to $53 million for the six months ended June 30, 2009 compared to $124 million for the six months ended June 30, 2008. The decrease was primarily due to the impact of the noncontrolling interest share of the Promigas gain ($55 million) on its sale of 46% of Gazel to noncontrolling shareholders of SIE during the first quarter of 2008 and the lower consolidated net income for the six months ended June 30, 2009. In addition,we incurred losses during the first six months of 2009 at Cuiaba and DCL, each of which has noncontrolling interests.

Net Income Attributable to AEI

As a result of the factors discussed above, net income attributable to AEI for the six months ended June 30, 2009 was $168 million compared to net income attributable to AEI of $106 million for the six months ended June 30, 2008.

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

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

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

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

Revenues

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


	For the Year Ended
	December 31,
	2007		2008
	(In millions of $)

Colombia	$	563	$	3,926
Brazil		1,406		1,503
Chile		—		1,311
Panama		389		808
Turkey		337		416
Guatemala		168		206
Dominican Republic		139		211
Ecuador		—		126
Argentina		52		122
China		8		104
Other		154		478

Total	$	3,216	$	9,211

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The following table reflects revenues by segment:


	For the Year Ended
	December 31,
	2007			2008
	(In millions of $)

Power Distribution	$	1,746		$	2,217
Power Generation		874			1,175
Natural Gas Transportation and Services		199			202
Natural Gas Distribution		352			584
Retail Fuel		160			5,137
Headquarters/Other/Eliminations		(115	)		(104	)

Total revenues	$	3,216		$	9,211

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

Power Distribution

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

Power Generation

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

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Natural Gas Transportation and Services

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

Natural Gas Distribution

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

Retail Fuel

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

Cost of Sales

The following table reflects cost of sales by segment:


	For the Year Ended
	December 31,
	2007			2008
	(In millions of $)

Power Distribution	$	963		$	1,374
Power Generation		610			984
Natural Gas Transportation and Services		36			13
Natural Gas Distribution		224			386
Retail Fuel		90			4,697
Headquarters/Other/Eliminations		(127	)		(107	)

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

Cost of sales increased by $5,551 million to $7,347 million for the year ended December 31, 2008 compared to $1,796 million for the year ended December 31, 2007. The increase was primarily due to the consolidation of SIE ($4,611 million) during 2008, the acquisitions made during 2007 and 2008 ($299 million), and the increase in cost of sales at Elektro ($159 million), Elektra ($154 million), San Felipe ($102 million), Trakya ($94 million), Promigas and its subsidiaries ($82 million) and PQP ($65 million) as described below, partially offset by the decrease in cost of sales at EPE ($25 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 $411 million to $1,374 million for the year ended December 31, 2008 compared to $963 million for the year ended December 31, 2007. The increase was primarily due to the acquisitions of Delsur ($49 million) and EDEN ($31 million) during the second quarter of 2007 and the increased cost of sales at Elektro ($159 million) and Elektra ($154 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 overall increase in energy prices ($85 million), the appreciation of the Brazilian real ($41 million) and an increase in volumes purchased ($3 million) as a result of higher sales volumes, and additional cost of sales recognition

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($38 million) as a result of recent regulatory determinations made by ANEEL, partially offset by a tax credit of $8 million on cost of sales. The increase in cost of sales due to regulatory determinations was related to a tariff adjustment ($20 million) as a result of the 2007 tariff review performed by ANEEL in August 2008 and the transmission costs ($18 million) to be collected from the generators and passed through to transmission companies as a result of the determination made by ANEEL. The increased cost of sales at Elektra was a result of higher average price of purchased electricity ($146 million) due to increased fuel costs and an increase in volumes purchased ($8 million).

Power Generation

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

Natural Gas Transportation and Services

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

Natural Gas Distribution

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

Retail Fuel

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

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		2008
	(In millions of $)

Power Distribution	$	241	$	323
Power Generation		118		123
Natural Gas Transportation and Services		57		62
Natural Gas Distribution		49		82
Retail Fuel		33		215
Headquarters/Other/Eliminations		132		89

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

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

Power Distribution

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

Power Generation

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

Natural Gas Transportation and Services

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

Natural Gas Distribution

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

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Retail Fuel

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

Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the Year Ended
	December 31,
	2007		2008
	(In millions of $)

Power Distribution	$	139	$	138
Power Generation		42		24
Natural Gas Transportation and Services		20		21
Natural Gas Distribution		8		18
Retail Fuel		3		61
Headquarters/Other		5		6

Total depreciation and amortization expenses	$	217	$	268

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

Other Charges

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

Gain (Loss) on Disposition of Assets

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

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Equity Income from Unconsolidated Affiliates

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


	For the Year Ended
	December 31,
	2007		2008
	(In millions of $)

Power Distribution	$	2	$	68
Power Generation		11		12
Natural Gas Transportation and Services		39		27
Natural Gas Distribution		13		11
Retail Fuel		11		1
Headquarters/Other/Eliminations		—		(2	)

Total equity income from unconsolidated affiliates	$	76	$	117

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

Operating Income

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


	For the Year Ended
	December 31,
	2007			2008
	(In millions of $)

Power Distribution	$	373		$	427
Power Generation		77			15
Natural Gas Transportation and Services		128			128
Natural Gas Distribution		85			104
Retail Fuel		49			218
Headquarters/Other/Eliminations		(135	)		(79	)

Total operating income	$	577		$	813

Interest Income

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

Interest Expense

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

Foreign Currency Transaction Gain (Loss), Net

Total foreign currency transaction losses were $56 million ($19 million after tax and noncontrolling interests) for the year ended December 31, 2008 compared to foreign currency transaction gains of $19 million

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

Loss on Early Retirement of Debt

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

Other Income (Expense), net

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

Provision for Income Taxes

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

Noncontrolling Interests

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

Net Income Attributable to AEI

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

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.

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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. Intercompany revenues between countries have been eliminated in Other.


	For the Year Ended
	December 31,
	2006			2007
	(In millions of $)

Colombia	$	—		$	563
Brazil		390			1,406
Panama		371			389
Turkey		116			337
Guatemala		48			168
Dominican Republic		145			139
Argentina		—			52
China		—			8
Other		(124	)		154

Total	$	946		$	3,216

The following table reflects revenues by segment:


	For the Year Ended
	December 31,
	2006			2007
	(In millions of $)

Power Distribution	$	685		$	1,746
Power Generation		278			874
Natural Gas Transportation and Services		24			199
Natural Gas Distribution		—			352
Retail Fuel		—			160
Headquarters/Other/Eliminations		(41	)		(115	)

Total revenues	$	946		$	3,216

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 for the 2006 period. 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 $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.

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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 local distribution companies. 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.

Cost of Sales

The following table reflects cost of sales by segment:


	For the Year Ended
	December 31,
	2006			2007
	(In millions of $)

Power Distribution	$	410		$	963
Power Generation		193			610
Natural Gas Transportation and Services		4			36
Natural Gas Distribution		—			224
Retail Fuel		—			90
Headquarters/Other/Eliminations		(41	)		(127	)

Total cost of sales	$	566		$	1,796

Cost of sales increased by $1,230 million to $1,796 million for the year ended December 31, 2007 compared to $566 million for the year ended December 31, 2006.

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.

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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 businesses 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.

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,
	2006		2007
	(In millions of $)

Power Distribution	$	91	$	241
Power Generation		37		118
Natural Gas Transportation and Services		6		57
Natural Gas Distribution		—		49
Retail Fuel		—		33
Headquarters/Other/Eliminations		59		132

Total operations, maintenance and general and administrative expenses	$	193	$	630

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.

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Power Distribution

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.

Power Generation

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 businesses 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.

Natural Gas Transportation and Services

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.

Natural Gas Distribution

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.

Retail Fuel

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.

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Depreciation and Amortization

The following table reflects depreciation and amortization expense by segment:


	For the Year Ended
	December 31,
	2006		2007
	(In millions of $)

Power Distribution	$	47	$	139
Power Generation		9		42
Natural Gas Transportation and Services		2		20
Natural Gas Distribution		—		8
Retail Fuel		1		3
Headquarters/Other		—		5

Total depreciation and amortization expenses	$	59	$	217

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. The increase is primarily due to the fact that PEI was consolidated for the whole year of 2007, compared to only four months of 2006.

Other Charges

During 2007, AEI recorded an allowance charge of $50 million against its lease investment receivable balance associated with the EPE PPA. 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 was 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,
	2006			2007
	(In millions of $)

Power Distribution	$	26		$	2
Power Generation		21			11
Natural Gas Transportation and Services		10			39
Natural Gas Distribution		—			13
Retail Fuel		4			11
Headquarters/Other/Eliminations		(24	)		—

Total equity income from unconsolidated affiliates	$	37		$	76

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

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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 segments, equity income increased due to the purchase of additional ownership percentage (42.98%) of Promigas in December 2006.

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,
	2006			2007
	(In millions of $)

Power Distribution	$	151		$	373
Power Generation		60			77
Natural Gas Transportation and Services		21			128
Natural Gas Distribution		—			85
Retail Fuel		3			49
Headquarters/Other/Eliminations		(84	)		(135	)

Total operating income	$	151		$	577

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 $97 million in 2006 to $143 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. Total foreign currency transaction losses in 2006 amounted to $5 million.

Loss on Early Retirement of Debt

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Other Income (Expense), Net

Other expenses of $22 million were recognized in 2007 included a loss of $14 million associated with hedging of reais for Elektro’s dividends. Other income was $7 million in 2006 and included gains from various insurance settlements, partially offset by a litigation reserve at San Felipe.

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 due to 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.

Noncontrolling Interests

The 2007 net income — noncontrolling interests of $65 million increased $45 million as compared to $20 million in net income — noncontrolling interests recognized in the prior year primarily due to the full-year consolidation of PEI and Promigas during 2007, each of which contains certain subsidiary businesses with noncontrolling shareholders for whom net income — noncontrolling interests 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.

Net Income Attributable to AEI

As a result of the factors discussed above, we recorded net income attributable to AEI of $131 million in 2007, compared to a net loss attributable to AEI of $11 million in 2006.

Capital Resources and Liquidity

Overview

We are a holding company that conducts all of our operations through subsidiaries. We finance our activities through a combination of senior debt, subordinated debt and equity at the AEI level and non-recourse and limited recourse debt at the subsidiary level. We have used non-recourse debt at the subsidiary level to fund a significant portion of the capital expenditures and investments required to construct and acquire 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. A default by certain subsidiaries under the agreements governing their debt could under some circumstances trigger a cross default under our senior secured loan facility. See — Parent Company Long-Term Debt.” We 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. In addition, for greenfield construction projects, we may provide funding, credit, obtain financing at the subsidiary level or enter into agreements with additional equity investors in the projects.

At June 30, 2009, we had $1,318 million of recourse debt and $2,231 million of non-recourse debt outstanding. For more information on our long-term debt, see Note 15 to the consolidated financial statements for the year ended December 31, 2008 and Note 14 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.

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We intend to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our subsidiaries and affiliates may develop, construct or acquire. However, depending on market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms. As a result of the recent turmoil in the financial markets, many lenders and investors ceased to provide funding. 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 June 30, 2009, we and certain of our subsidiaries had entered into letters of credit, bank guarantees and performance bonds with balances of $183 million issued and $119 million in unused letter of credit, bank guarantee and performance bond availability, of which $20 million of the total facility balances were fully cash collateralized. Additionally, as of June 30, 2009, lines of credit of $1,295 million were outstanding, with an additional $606 million available.

As of June 30, 2009, we had $524 million of total cash and cash equivalents on a consolidated basis, of which $8 million was at the parent company level, $450 million was at our consolidated operating businesses, and the remaining $66 million was at consolidated holding and service companies. See Note 6 to the unaudited condensed consolidated financial statements as of June 30, 2009.

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, $158 million of which was drawn as of June 30, 2009;

	•	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 and existing projects including greenfield development; and

	•	parent company overhead and development costs.

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

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electricity or natural gas consumption. As a result, the tariff reviews may result in tariff reductions to reset the business’ returns back to the regulated return levels.

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

Capital Expenditures

Capital expenditures were $372 million, $249 million and $76 million in 2008, 2007 and 2006, respectively, of which $145 million, $137 million and $52 million, in 2008, 2007 and 2006, respectively, correspond to capital expenditures at Elektro. Capital expenditures for 2008 and 2007 also include $113 million and $50 million, respectively, associated with Promigas and its consolidated subsidiaries. Capital expenditures were $166 million and $140 million for the six months ended June 30, 2009 and 2008, respectively. For 2009, capital spending is expected to total $593 million, of which $144 million, $143 million and $137 million correspond to capital expenditures at Elektro, development projects and Promigas (including its consolidated subsidiaries), respectively. Planned capital expenditures for 2009 include spending on asset base expansions at certain Power Distribution, Natural Gas Distribution and Natural Gas Transportation projects, additional stations and upgrades in the Retail Fuel segment, new project construction expenditures in the Power Generation segment, and maintenance expenditures related to existing assets across all segments. These capital expenditures are expected to be financed using a combination of cash provided by the businesses’ operations, business level financing and equity contributions from shareholders.

Our Cash Flows for the Six Months Ended June 30, 2009 and June 30, 2008

Cash Flows from Operating Activities

Cash provided by operating activities was $296 million in the first six months of 2009 compared to $172 million in the first six months of 2008 representing an increase of $124 million. The increase in cash flows from operating activities is the combined result of an increase of $129 million in net income after removing non-cash items, partially offset by the increased cash outflow of $5 million related to net changes in operating assets and liabilities. During the first six months of 2009, accounts receivable decreased by $8 million compared to a $107 increase for the same period in 2008; accounts payable decreased by $24 million compared to a $120 increase for the same period in 2008; inventory increased $2 million compared to a $71 increase for the same period in 2008. The changes discussed above were impacted by changes in foreign exchange rates, primarily at Elektro and Promigas and by fluctuations of energy prices for the comparative periods. The $58 million negative impact from other operating activities was primarily due to the decrease of Elektro’s provisions related to social contributions and Trakya’s payment on its Cost Increase Protocol, or CIP. Non-cash adjustments to net income in 2009 increased in the first six months of 2009 compared to 2008 primarily due to Trakya’s CIP, which resulted in decreases in deferred revenue in the first six months of 2008. Additionally, in the first six months of 2008 we recorded a non-cash gain on the disposition of assets of $74 million from the acquisition of additional interests in SIE in exchange for Gazel.

Cash Flows from Investing Activities

Cash used by investing activities for the six months ended June 30, 2009 was $104 million compared to $275 million for the six months ended June 30, 2008. During the first six months of 2009, we received the second payment of $60 million from YPFB related to the sale of its investment in Transredes. During the first six months of 2008, we received proceeds of $38 million from the sale of interests in debt securities of Gas Argentino S.A. Capital expenditures increased by $26 million to $166 million for the first six months of 2009 compared to $140 million for the same period in 2008 due to expansion in our asset base and new project construction during 2009. We paid cash of $22 million for the acquisitions of equity interest in EMDERSA and an additional equity interest in Emgasud in the first six months of 2009, compared to $219 million in the same period of 2008 for the acquisitions of Luoyang, Fenix, Tipitapa and additional interests in BMG and subsidiaries of Promigas. During the first six months of 2009, there were no cash and cash equivalents acquired compared to $75 million in the same period of 2008 from the acquisitions noted above. During the first six months of 2009, we contributed $7 million in Promigas’ unconsolidated investments for project expansion. Additionally, restricted cash decreased by $26 million during the first six months of 2009 due primarily to the repayment of Cálidda’s subordinated loan, which

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released the restriction on cash. Maintenance capital expenditures of $54 million and $39 million were included in capital expenditures for the six months ended June 30, 2009 and 2008, respectively.

Cash Flows from Financing Activities

Cash used in financing activities for the six months ended June 30, 2009 was $412 million compared to $90 million of cash provided by financing activities for the six months ended June 30, 2008. During the first six months of 2009, we made repayments of $337 million under our Revolving Credit Facility; Cálidda repaid its subordinated loan of $47 million; we purchased $10 million of outstanding debt held by EDEN; Promigas refinanced $131 million of its U.S. dollar denominated debt through Colombian peso denominated notes; Elektro issued unsecured commercial paper totaling 120 million Brazilian reais (approximately U.S. $61 million) (see Note 14 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009). In May 2008, we sold 12.5 million of our ordinary shares to Buckland Investment Pte Ltd. and received $200 million in proceeds. Additionally, Elektro and Promigas increased borrowings by $22 million and $113 million, respectively, for financing of capital expenditures, while we used a portion of the stock issuance proceeds from Buckland Investment Pte Ltd. to repay $162 million of our revolving credit facility and Trakya repaid $24 million of its long-term debt.

Our Cash Flows for the Years ended December 31, 2008 and December 31, 2007

Cash Flows from Operating Activities

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

Cash Flows from Investing Activities

Cash used in investing activities decreased by $737 million to $414 million for the year ended December 31, 2008 from $1,151 million for the same period in 2007. Capital expenditures increased by $123 million in the year ended December 31, 2008 due to expansion in the asset base and new project construction during 2008. Capital expenditures in 2008 include maintenance capital expenditures of $129 million. Cash paid for acquisitions was $253 million in 2008 for the interests in BMG, Luoyang, Fenix, Tipitapa, DCL, Emgasud and Promigas’ additional interests in certain subsidiaries. This is compared to $1,111 million in the same period in 2007 for the acquisitions of Cálidda, EDEN, Delsur, Tongda, Corinto, BMG, JPPC, Chilquinta and POC and the additional interests in San Felipe and PQP. Additionally, in 2008, cash and cash equivalents of $60 million were acquired compared to $21 million in the same period in 2007. Restricted cash decreased by $78 million for the year ended December 31, 2008 compared to a $61 million decrease for the same period in 2007 due primarily to the release of restricted cash at Trakya upon the repayment of its long-term debt in the third quarter of 2008. Activities in 2008 and 2007 also included proceeds of $38 million from the sale of the Metrogas available-for-sale securities and proceeds of $48 million from the sale of BLM, respectively.

Cash Flows from Financing Activities

Cash provided by financing activities for the year ended December 31, 2008 was $173 million compared to $88 million for the year ended December 31, 2007. In May 2008, we sold 12.5 million of our ordinary shares to Buckland Investment Pte Ltd. and received $200 million in proceeds. Additionally, during 2008, Elektro did not execute call options and tender offers on its debentures as it had in 2007; Elektra issued corporate bonds; Delsur

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refinanced its $100 million bridge loan; and Promigas refinanced various credit facilities for the financing of capital expenditures. In addition, we used a portion of the stock issuance proceeds previously mentioned to repay a portion of our revolving credit facility and to make dividend payments to minority interest holders of the operating companies, and Trakya paid off all of its long-term debt.

Our Cash Flows for the Years ended December 31, 2007 and December 31, 2006

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 PPA 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 above. 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.

Contractual Obligations

A summary of contractual obligations, commitments and other liabilities as of December 31, 2008 is presented in the table below:


			Less Than 1						After 5
	Total		Year		1-3 Years		3-5 Years		Years
	(In millions of $)

Debt obligations⁽¹⁾	$	3,962	$	547	$	1,078	$	903	$	1,434
Interest payments on long-term debt⁽²⁾		1,598		388		439		283		488
Pension obligations		199		12		27		34		126
Operating lease obligations⁽³⁾		91		16		24		20		31
Capital lease obligations⁽⁴⁾		71		12		29		22		8
Power commitments⁽⁵⁾		11,901		790		1,741		1,634		7,736
Fuel commitments⁽⁶⁾		4,700		474		889		834		2,503
Transportation commitments⁽⁷⁾		499		55		115		85		244
Equipment commitments⁽⁸⁾		156		22		14		37		83
FIN 48 obligations, including interest and Penalties		117		11		5		—		101
Other commitments⁽⁹⁾		11		7		3		1		—

Total	$	23,305	$	2,334	$	4,364	$	3,853	$	12,754


(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.

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(2)		Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2008 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, 2008.
(3)		Operating lease obligations are the future obligations primarily related to land, office, office equipment and vehicles in which several our businesses are the lessees.
(4)		Capital lease obligations are the future obligations primarily related to certain pipelines and equipment in which Promigas and Elektro are the lessees. The leases are all nonrecourse. As of December 31, 2008 and 2007, the net assets held under capital leases were $42 million and $26 million, respectively, and imputed interest for these obligations were both $14 million.
(5)		Represents take-or-pay and other commitments to purchase power of various quantities from third parties.
(6)		Represents take-or-pay and other commitments to purchase fuel of various quantities from third parties.
(7)		Represents a commitment to purchase gas transportation services from an unconsolidated affiliate and third parties.
(8)		Represents commitments of various duration for parts and maintenance services provided by third parties, which are expensed during the year of service.
(9)		Represents various other purchase commitments with third parties.

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 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 1.75%. The revolving credit facility when drawn incurs interest at LIBOR plus 3% or the rate most recently established by the Administrative Agent as its base rate for dollars loaned in the United States plus 1.75%; the undrawn portion of the revolving credit facility incurs a commitment fee of 0.50% per annum. The synthetic revolving credit facility when drawn incurs interest at LIBOR plus 3% or the rate most recently established by the Administrative Agent as its base rate for dollars loaned in the United States plus 1.75%; the undrawn portion of the synthetic revolving credit facility incurs a commitment fee of 3.1% per annum. The funding of the term loan and access to the revolving credit facility and the synthetic revolving credit facility took place on March 30, 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 June 30, 2009, $53 million was drawn under the revolving credit facility and $105 million was drawn under the synthetic revolving credit facility.

Note Purchase Agreement (PIK Notes)

We are the issuer of PIK notes under a note purchase agreement dated May 24, 2007, as amended. The proceeds from the issuance of the PIK notes were used by us to repay $279 million of the outstanding PIK notes, including capitalized interest, that were issued on September 6, 2006. As of December 31, 2008, the aggregate principal and interest amount of the PIK notes was $352 million. Since that time, as discussed below, $118 million was converted to equity in March 2009. The PIK 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 PIK note holder to declare its PIK note immediately due and payable, include: (a) a failure to timely repay PIK 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 PIK note holders agree not to accelerate the payment of the PIK note obligations or exercise other remedies available to them with respect to the PIK notes until satisfaction of all obligations under our existing senior loan facilities.

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We may, upon notice to the PIK note holders, redeem the PIK notes prior to maturity by paying the then outstanding principal amount of the PIK note, plus a redemption premium, together with any accrued but unpaid and uncapitalized interest. The redemption price is as follows: May 24, 2010 — 106% and May 24, 2011 and thereafter — 108%.

On March 11, 2009, we amended the note purchase agreement in order to issue an option to all of our PIK note holders to exchange their PIK notes for our ordinary shares. Pursuant to an option agreement, dated February 25, 2009 and effective March 11, 2009, the option period is for up to one year ending on March 10, 2010. The initial exchange rate is 63 ordinary shares per $1,000 for each principal amount of PIK notes exchanged. This rate adjusts downward relative to the increase of interest on the notes. Additionally, the amendment allows us to purchase the PIK notes in the open market, subject to certain conditions. In March, August and October 2009, various Ashmore Funds exercised their option to convert their PIK notes and related interest receivable in the amount of $118 million for 7,412,142 ordinary shares, $57 million for 3,438,069 ordinary shares and $21 million for 1,233,864 ordinary shares, respectively.

Subsidiaries Financing Activities

In July 2009, Elektro issued 300 million Brazilian reais (approximately $152 million) in debentures. The proceeds of the debentures were used to refinance its existing debentures.

In July 2009, Gases de Occidente issued debentures in an aggregate principal amount of COP150 billion (approximately $77 million).

In August 2009, Promigas issued debentures in an aggregate principal amount of COP400 billion (approximately $200 million).

Between March and August of 2009, Terpel refinanced its U.S. dollar denominated debt of $250 million through a combination of cash and local currency loans. The refinancing included (i) loans of COP400 billion (approximately $200 million), with tenors ranging between three and five years and a weighted average interest of rate of 10.43%, (ii) loans of CLP10 billion (approximately $18 million), with a 5-year tenor and an interest rate of 4.04% and (iii) $32 million from internally generated cash.

In September 2009, Luz del Sur issued local currency bonds authorized under its existing bond program to refinance a maturing bond issue. The amount issued was 73 million Peruvian nuevos soles (approximately $25 million). The bonds mature in five years. The interest rate was 6.47%. The issuance was rated locally pAAA by PCR — Pacific Credit Rating and AAA by Class & Asociados ratings.

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Subsidiaries’ Long-Term Debt Schedule

The following table summarizes our consolidated subsidiaries’ credit facilities as of June 30, 2009:

Currency of

Balance as of

Maturity

Summary of Distribution

Business

Borrowing

June 30, 2009

Profile

Collateral

Restrictions

(In millions of $)

Cálidda

U.S.$

2009-2015

Security includes the gas distribution concession and income trust

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

Cuiabá — EPE⁽¹⁾

U.S.$

2015-2016

Shareholder loan with Shell (no security)

N/A

Cuiabá — GOB⁽¹⁾

U.S.$

2015-2016

Shareholder loan with Shell (no security)

N/A

Cuiabá — GOM⁽¹⁾

U.S.$

2015-2016

Shareholder loan with Shell (no security)

N/A

DCL⁽²⁾

Pakistani
rupees

2009-2019

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 (³1.5) and the Leverage Ratio (Debt to Equity £75:25, Current Ratio ³0.7 5:1) and Applicable Law

Delsur

U.S.$

2015

Security includes subsidiary guarantees and pledges of shares

No default/must meet distribution ratios/local laws

EDEN⁽³⁾

U.S.$

2013

Unsecured

No default/limited to% of excess cash

Elektra

U.S.$

119

2009-2021

Unsecured

None

Elektro

507

2010-2020

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

Polish zloty

2009-2018

Security includes mortgage on assets, assignment of contracts, pledge of shares, MRA, final correction reserve account, insurance assignments, etc.

No default/must meet distribution ratios/local laws

Luoyang

Chinese
Renminbi

116

2009-2016

Security includes assignment of rights to collection of revenues

None

PQP

U.S.$

2015

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

No default/must meet distribution ratios/local laws

Promigas⁽⁴⁾

Colombian
pesos

835

2009-2012

Unsecured

None

Promigas⁽⁵⁾

U.S.$

152

2012

Security includes certain subsidiaries of Promigas

Dividends depending on the leverage ratio ³2.5 X 50% of the Net Income <2.5 X 100% of the Net Income

Others

U.S.$ and
Chinese
Renminbi

2009-2014

Total

2,231

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(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.
(2)		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 seeking repayment by DCL of $46 million. See Note 21 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.
(3)		EDEN is in 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 14 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009.
(4)		Some of the credit facilities included in this entry may have shorter maturity profiles.
(5)		Some of the credit facilities included in this entry may have shorter maturity profiles, unsecured collateral and no distribution restrictions.

Trend Information

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

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

Macroeconomic Developments in Emerging Markets. We generate nearly all of our revenue from the production and delivery of energy in emerging markets. Therefore, our operating results and financial condition are directly impacted by macroeconomic and fiscal developments, including fluctuations in currency exchange rates, in those markets. During the last few years leading up to the world-wide financial crisis, emerging markets had generally experienced significant macroeconomic and fiscal improvements. We expect our key markets will again experience macroeconomic improvements, evidenced by modest GDP growth, and higher energy demand beginning in 2010.

Foreign Currency Changes. In 2008 and through the first quarter of 2009, the local currencies in many emerging markets in which we operate depreciated or remained flat against the U.S. dollar, resulting in lower earnings and cash flows (measured in U.S. dollars) from some of our subsidiaries, particularly Elektro, which is located in Brazil and is our largest business. Between January 1, 2008 and December 31, 2008, the Brazilian real depreciated by 31.6% against the U.S. dollar, according to the European Central Bank. During the second quarter of 2009, the local currencies in emerging markets strengthened significantly. Based on information from the European Central Bank, the Brazilian real appreciated against the U.S. dollar by 0.8% in the first quarter of 2009 and 15.9% in the second quarter of 2009.

Acquisitions and Future Greenfield Development. We have experienced growth through acquisitions in recent years. This growth has resulted in material year-over-year changes in our financial condition and changes from equity method accounting to consolidation for certain subsidiaries, which affect the yearly comparison of our financials. We intend to continue growing our business through organic growth and additional acquisitions as well as through greenfield development.

Regulatory Developments in Emerging Markets. In many of our markets, the regulatory frameworks have been and continue to be restructured to create conditions that will foster investment and growth in energy supply to meet expected future energy requirements. The development and timing of this process varies across our markets. In some markets, such as Brazil and Colombia, major regulatory changes were implemented in the 1990s or early 2000s, and, in those countries, the regulatory framework is now relatively settled. In other markets, such as Turkey and China, the regulatory process is less evolved, with major changes continuing to take place, and it is as yet unclear what the ultimate regulatory structure will be. However, in most of these markets, the common trend has been to establish conditions that foster and rely on the participation of the private sector in providing the needed infrastructure to support the current growth pattern of energy consumption. We believe that this trend will continue in most of the markets that we serve.

Commodity Prices. There have been substantial changes in commodities prices in the last few years. Most of our revenue depends directly or indirectly on fuel prices in the local markets we serve. In most cases, we are able to pass on the higher or lower fuel costs to our customers, which increases or decreases our revenue and costs of sales, but does not necessarily affect our net income.

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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 June 30, 2009, our floating rate debt at the AEI level consisted primarily of a $914 million term loan facility, $53 million of drawn revolving credit facility and a $105 million synthetic credit facility. Although all three facilities are based on floating rates, we have mitigated our interest rate exposure by entering into interest rate swaps. We are also exposed to interest rate fluctuations at some of our subsidiaries, the primary ones being Elektro 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 may hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Using sensitivity analysis and a hypothetical 1% increase in interest rates across all the consolidated debt facilities, without taking into consideration offsetting tariff adjustments or tax shield, the increase in annual interest expense on all of our variable-rate debt would reduce net income by $19 million.

Foreign Exchange Rate Risk

A significant portion of our operating income is exposed to foreign exchange fluctuations. We are primarily exposed to fluctuation in the exchange rate between the U.S. dollar and the Brazilian real and the Colombian peso. Our exposure to currency exchange rate fluctuations results from the translation exposure associated with the preparation of our consolidated financial statements, and from transaction exposure associated with generating revenues and incurring expenses in different currencies. Currency fluctuations may also affect the earnings of subsidiaries where we are unable to match external indebtedness with the functional currency of the business, and consequently may affect our consolidated earnings. Fluctuations in exchange rates and currency devaluations affect our cash flow as cash distributions received from those of our subsidiaries operating in local currencies might be different from forecasted distributions due to the effect of exchange rate movements. Further, the devaluation of local currency revenues against the U.S. dollar may impair the value of the investment in U.S. dollars. While our consolidated financial statements are reported in U.S. dollars, the financial statements of some of our subsidiaries are prepared using the local currency as the functional currency and translated into U.S. dollars by applying an appropriate exchange rate. Accordingly, changes in exchange rates relative to the U.S. dollar could have a material adverse effect on our earnings, assets and cash flows. Most countries in which we operate use local currencies, many of which have fluctuated significantly against the U.S. dollar in the past.

Based on historical results, a 10% devaluation of the Brazilian real and the Colombian peso for the six months ended June 30, 2009 would result in an estimated net loss on the translation of local currency earnings of approximately $9 million and $3 million, respectively, to our unaudited condensed consolidated statement of operations for the six months ended June 30, 2009. We estimate that the unaudited condensed consolidated balance sheet as of June 30, 2009 would be negatively impacted by approximately $76 million and $41 million, respectively, in currency translation through the cumulative translation adjustment in accumulated other comprehensive income as a result of a 10% devaluation of the Brazilian real and the Colombian peso as of June 30, 2009.

To manage the impact of currency fluctuation on cash flow from dividends of certain of our subsidiaries, we hedge part of our future dividends (especially those denominated in Brazilian 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 redesignate them after dividends are declared.

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The notional and fair market values of positions at June 30, 2009, were as follows:


	As of June 30, 2009
	Notional Amount		Fair Value
Foreign Currency Forward Contracts
Designated as Net Investment Hedge	(In millions of U.S. Dollars)

Sell Brazilian real, buy U.S. dollar	$	82	$	(6	)


	As of June 30, 2009
	Notional Amount		Fair Value
Foreign Currency Forward Contracts Not
Designated as Hedge	(In millions of U.S. Dollars)

Sell Colombian peso, buy U.S. dollar	$	22	$	(1	)

All of the foreign currency derivative contracts mature in 2009.

Commodity Price Risk

Although most of the businesses operate under long-term contracts or retail sales concessions, a small minority of current and expected future revenues are derived from businesses without significant long-term sales or supply contracts. These businesses subject the results of operations to the volatility of electricity and fuel prices in competitive markets. To mitigate these risks, we may use a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy may involve the use of commodity forward contracts, futures, swaps or options. We may also enter into long-term supply contracts containing price escalators for the supply of fuel and electricity. In all other cases, our contracts allow us to either pass through to our customers our full commodity costs or to escalate our prices to track applicable commodity price indices.

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 June 30, 2009, $183 million in letters of credit, bank guarantees, and performance bonds were issued, of which $20 million was cash collateralized. In addition, we had $119 million in unused letter of credit, bank guarantee and performance bond availability at our disposal.

See Note 21 to the unaudited condensed consolidated financial statements for the six months ended June 30, 2009 included elsewhere in this prospectus for further information on letters of credit, litigation and other commitments and contingencies.

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BUSINESS

We own and operate essential energy infrastructure assets in emerging markets. We operate in 19 countries in Latin America, Central and Eastern Europe and Asia in Power Distribution, Power Generation, Natural Gas Transportation and Services, Natural Gas Distribution and Retail Fuel. We operate or have joint control of more than 50 businesses and have investments in more than ten others. As of June 30, 2009, our businesses included approximately:


	•	4.9 million electric power customers;

	•	2.4 million natural gas customers;

	•	119,985 miles of power distribution and transmission lines;

	•	2,182 MW of electric power generation capacity;

	•	4,920 miles of natural gas and gas liquids transportation pipelines;

	•	20,892 miles of natural gas distribution pipeline networks; and

	•	1,826 owned and affiliated gasoline and CNG service stations.

Because our businesses are generally contracted to a sole or limited number of customers or are regulated franchises, we generally do not conduct significant marketing efforts.

Our Competitive Strengths

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

Exclusive focus in emerging markets

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

Well positioned across multiple countries, regions and segments of the energy infrastructure industry

We operate in multiple countries, regions and segments of the energy infrastructure industry and have an established and locally branded presence in our existing markets that we believe positions us to benefit from the above-average growth of our markets, while at the same time, diversifying our risks. We also believe that our ability to identify and consider investments in multiple countries and segments continuously presents us with a robust set of investment opportunities irrespective of challenges that may occur in any one country or segment.

Stable and flexible financial profile to support growth

We generate the vast majority of our earnings from our regulated and contracted businesses. Most of these businesses benefit from mid- to long-term indexation to the U.S. dollar through foreign exchange and inflation adjustments and historically have generated stable cash flow. Our financial stability is further enhanced by geographic and segment diversification of our businesses. Well over half of our earnings are derived from countries

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with investment grade ratings. This stable operating profile is also enhanced by our moderate debt level. In addition, while certain of our businesses are subject to a limited degree of seasonality, our overall business is not materially impacted by fluctuations due to seasonal changes. The combination of our stable cash flow and moderate debt level provides us with rapid and efficient access to capital when we identify compelling growth opportunities.

Demonstrated capability to grow in a disciplined manner

We have successfully demonstrated our ability to grow our company in a disciplined manner as evidenced, for example, by the increase in our diluted earnings per share from $0.42 in 2007 to $0.73 in 2008. For the first six months of 2009, our diluted earnings per share were $0.72. We have improved the operational and financial performance of our existing businesses, delivered organic growth from existing businesses, including the on-going build-out of our natural gas distribution business in China, Colombia and Peru, demonstrated an ability to integrate multiple acquisitions of new businesses and captured valuable brownfield and greenfield development opportunities.

Operational excellence

We are committed to the reliable, responsible, efficient and safe operations of our businesses with a disciplined focus on high operating, health, safety and environmental standards. We have a recognized record for operational excellence and many of our businesses are leaders in their markets, surpassing both local and U.S. standards and their contractual requirements. We had company-wide power distribution line losses of 7.9%, power plant reliability of 97.33%, natural gas pipeline reliability of 100.00% and natural gas processing reliability of 99.72% in 2008. Additionally, our LTIR for all our businesses was 0.30 in 2007 and 0.35 in 2008, well below the U.S. industry average of over 1.1 according to the U.S. Bureau of Labor Statistics. Our commitment to operational excellence is critical to achieving compliance with regulations and contracts and to maintaining credibility and generating trust with our key stakeholders, including governments, regulators, off-takers, employees and local communities. Our focus on operational excellence enhances our financial performance and is essential to the execution and sustainability of our strategy.

Experienced management team with strong local presence

Our management team, including the executives in each of the markets in which we operate, has extensive experience operating, developing and acquiring businesses in the energy industry, with an average of approximately 19 years of experience. We believe that this overall level of experience contributes to our ability to effectively manage existing businesses, identify and evaluate high quality growth opportunities and integrate new businesses that are acquired or developed. The management teams of our businesses consist primarily of local executives who have significant experience working in the local energy industry and with government regulators. We believe that the market specific experience of our local management provides us with visibility into the local regulatory, political and business environment that gives us a greater ability to manage risk and identify new opportunities.

Our Strategy

Our strategy is to own and operate essential energy infrastructure assets diversified across our existing lines of business in key emerging markets. We generally focus on businesses that are regulated and/or contracted that produce stable cash flows with strong local branding and management. We seek to grow our company by investing capital at attractive rates of return into organic expansion of existing businesses, acquisitions of new businesses or incremental interests in existing businesses and brownfield and greenfield development of new assets. We prefer investments that provide operational control or the ability to exert significant influence, or strategic non-control positions that offer the opportunity to gain control or significant influence over the investment in the future. We target opportunities that will reinforce our existing business lines or result in synergies with existing operations and seek to consolidate our significant presence in certain countries, build upon our early stage presence in other countries and enter key new countries. From January 2007 through June 30, 2009, we have acquired new or additional interests in 19 businesses. We are also currently pursuing additional greenfield development opportunities. We have deployed capital in excess of $1.5 billion, including cash and, in certain cases, our ordinary shares, in connection with these opportunities.

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In executing our strategy, we seek to:


	•	maximize the financial performance of our businesses;

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

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

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

	•	leverage our strong management teams and their relationships and market knowledge to effectively manage our businesses and pursue growth opportunities; and

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

Our Businesses

We own and operate essential energy infrastructure assets in emerging markets. We operate in 19 countries in Latin America, Central and Eastern Europe and Asia. The tables below list our businesses and describe the five reporting 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. For additional information regarding the jurisdictions in which our businesses operate, see “Economic and Regulatory Aspects of the Countries Where We Do Business.”

Business Segments

Our Power Distribution businesses distribute and sell electricity primarily to residential, industrial and commercial customers. This segment contributed 51% of our Adjusted EBITDA (excluding Headquarters and Other) in 2008. Most of the businesses in this segment operate in a designated service area defined in a concession agreement. All of the concession agreements and/or associated regulations include tariffs that are periodically reviewed by regulators and are designed to provide for a pass-through to customers of the main non-controllable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return. These seven businesses operate and maintain an electric distribution network, and bill customers directly via consumption and/or demand charges.


Power Distribution⁽¹⁾
				AEI
				Ownership				Approximate
				Interest				Number of				GWh		Approximate
		Start of		(Direct and			Operating	Customers		Network		Sold		Number of
Business	Country	Operations⁽²⁾		Indirect)			Control⁽³⁾	(Thousands)		in Miles		(2008)⁽⁴⁾		Employees

Elektro	Brazil		1998		99.68	%	Yes		2,095		66,163		10,844		2,806
Elektra	Panama		1998		51.00	%	Yes		342		5,523		2,250		547
EDEN⁽⁵⁾	Argentina		1997		90.00	%	Yes		325		10,910		2,225		740
Delsur	El Salvador		1996		86.41	%	Yes		311		5,296		1,162		273
Chilquinta	Chile		1981		50.00	%	Joint with Sempra		481		5,118		2,303		618
Luz del Sur⁽⁶⁾	Peru		1994		37.97	%	Joint with Sempra		822		11,482		5,333		695
EMDERSA⁽⁷⁾	Argentina		1993		19.91	%	No		502		15,493		2,673		394

									4,878		119,985		24,117		6,073

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(1)		Information provided in this table is as of June 30, 2009, unless otherwise indicated.
(2)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.
(3)		“Operating Control” means that AEI has either a controlling interest in the business or operates the business through an operating agreement.
(4)		Represents GWh sold to end customers. Does not include sales for distribution in third-party transmission. The total energy sales for 2008 does not include GWh sold by EMDERSA because EMDERSA was not owned by AEI in 2008.
(5)		Subject to local anti-trust approval.
(6)		On September 8, 2009, we signed agreements with certain shareholders of Luz del Sur pursuant to which we agreed to acquire an additional interest of Luz del Sur in exchange for AEI Shares. Closing of this transaction is subject to certain conditions, including the listing of our shares on an approved exchange, including the NYSE. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments in 2009.”


(7)		EMDERSA is the holding company of the power distribution companies EDESAL, EDELAR and EDESA. On August 27, 2009, we acquired an additional 4.5%; on September 24, 2009, we acquired an additional 25.6%; and on October 13, 2009, we acquired an additional 27.09% of EMDERSA. As a result of these transactions, we own 77.11% of EMDERSA as of the date of this prospectus.

Our Power Generation businesses generate and sell wholesale capacity and energy primarily to power distribution businesses and other large off-takers. This segment contributed 6% of our Adjusted EBITDA (excluding Headquarters and Other) in 2008. Most of the businesses in this segment sell substantially all of their generating capacity and energy under long-term PPAs. Our PPAs generally are structured to minimize both our exposure to fluctuations in commodity fuel prices and are dollar denominated. Our 12 businesses in this segment are listed in the table below. During the first quarter of 2009, the BOT agreement for Subic expired on schedule and the plant was turned over to NPC.


Power Generation⁽¹⁾
					AEI
					Ownership				Installed		Energy
					Interest				Generating		Sales			Approximate
		Start of			(Direct and			Operating	Capacity		2008		Primary	Number of
Business	Country	Operations⁽²⁾			Indirect)			Control⁽³⁾	(MW)		(GWh)		Fuel Type	Employees

Trakya⁽⁴⁾	Turkey		1999			59.00	%	Yes		478		3,342	Natural Gas		86
Cuiabá-EPE	Brazil		1999			50.00	%	Joint with Shell		480		161	Natural Gas		57
Luoyang	China		2006			50.00	%	Yes		270		750	Coal		195
PQP	Guatemala		1993			100.00	%	Yes		234		1,377	Bunker Fuel		52
San Felipe	Dominican Republic		1994			100.00	%	Yes		180		1,029	Bunker Fuel		82
ENS	Poland		2000			100.00	%	Yes		116		754	Natural Gas		47
Corinto	Nicaragua		1999			57.67	%	Yes		70		517	Bunker Fuel		78
Tipitapa	Nicaragua		1999			57.67	%	Yes		51		393	Bunker Fuel		50
JPPC	Jamaica		1998			84.42	%	Yes		60		455	Bunker Fuel		55
DCL	Pakistan		2008			60.22	%	Yes		94		229	Natural Gas		87
Emgasud	Argentina		1991	⁽⁵⁾		37.00	%	No		109		139	Natural Gas		19
Amayo	Nicaragua		2009			12.72	%	No		40		—	Wind		20

										2,182		9,147			828


(1)		Information provided in this table is as of June 30, 2009, unless otherwise indicated.
(2)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.
(3)		“Operating Control” means that AEI has either a controlling interest in the business or operates the business through an operating agreement.
(4)		On August 27, 2009, we acquired an additional 31.00% of Trakya.
(5)		Power generation operations began in 2008.

Our Natural Gas Transportation and Services businesses sell natural gas transportation capacity and related services to oil and gas producers, natural gas distribution companies and other large off-takers. This segment contributed 13% of our Adjusted EBITDA (excluding Headquarters and Other) in 2008. Most of the businesses in this segment operate either through regulated concessions under a cost of service regulatory model or long-term contracts that provide for recovery of reasonable operating and administrative costs, incentives to continue cost

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reductions and make needed capital investments and a regulated rate of return. Our 14 businesses in this segment are listed below.


Natural Gas Transportation and Services⁽¹⁾
					AEI
					Ownership
					Interest							2008 Average
		Start of			(Direct and			Operating	Network in			Throughput
Business	Country	Operations⁽²⁾			Indirect)			Control⁽³⁾	Miles			(mmcfd)⁽⁴⁾			Employees

Promigas						52.13	%
Promigas Pipeline	Colombia		1974			52.13	%	Yes⁽⁵⁾		1,271			294			321
Transmetano	Colombia		1993			50.34	%	Yes⁽⁵⁾		93			35			36
GBS	Colombia		1999			49.37	%	Yes⁽⁵⁾		196			12			8
Centragas	Colombia		1996			13.03	%	Yes⁽⁵⁾		458			159			22
PSI	Colombia		2003			50.46	%	Yes⁽⁵⁾		N/A	⁽⁶⁾		268			13
Transoccidente	Colombia		1998			35.96	%	Yes⁽⁵⁾		7			36			3
Transoriente	Colombia		1994			13.73	%	No		98			13			16
Cuiabá
GOB	Bolivia		2002			50.00	%	Joint with Shell		225			2			14
GOM	Brazil		2002			50.00	%	Joint with Shell		175			1			1
TBS	Bolivia		1999			50.00	%	Joint with Shell		N/A	⁽⁷⁾		1	⁽⁷⁾		0
Accroven	Venezuela		2001			49.25	%	Joint with Williams		N/A	⁽⁸⁾		759			129
Bolivia-to-Brazil Pipeline
GTB	Bolivia		1999			17.65	%	No		346			1,077			71
TBG	Brazil		1999			4.21	%	No		1,611			1,077			261
Emgasud	Argentina		1992	⁽⁹⁾		37.00	%	No		440			12			13

										4,920			3,747			908


(1)		Information provided in this table is as of June 30, 2009, unless otherwise indicated.
(2)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.
(3)		“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.
(4)		Includes both gas and liquids.
(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)		Natural gas transportation operations began in 2007.

Our Natural Gas Distribution businesses distribute and sell natural gas primarily to residential, industrial and commercial customers. This segment contributed 11% of our Adjusted EBITDA (excluding Headquarters and Other) in 2008. Most of the businesses in this segment operate in a designated service area defined in a concession agreement. All of the concession agreements and/or associated regulations include tariffs that are periodically reviewed by regulators and are designed to provide for a pass-through to customers of the main non-controllable cost items (mainly natural gas purchases), recovery of reasonable operating and administrative costs, incentives to continue to reduce costs and make needed capital investments and a regulated rate of return. Most of these concession agreements are structured to minimize our exposure to fluctuations in commodity prices. Our seven businesses in this segment are listed in the table below.


Natural Gas Distribution⁽¹⁾
			AEI
			Ownership								Approximate		2008
			Interest								Number of		Average
		Start of	(Direct and			Operating			Network in		Customers		Throughput
Business	Country	Operations⁽²⁾	Indirect)			Control⁽³⁾			Miles		(Thousands)		(mmcfd)		Employees

Promigas				52.13	%
Surtigas	Colombia	1968		52.08	%		Yes	⁽⁴⁾		4,951		460		31		363
Gases de Occidente	Colombia	1992		46.97	%		Yes	⁽⁴⁾		4,155		640		48		380
Gases del Caribe⁽⁵⁾	Colombia	1966		16.16	%		No			8,670		949		107		697	⁽⁵⁾
Cálidda	Peru	2004		80.85	%		Yes			466		14		157		186
BMG⁽⁶⁾	China	1988		70.00	%		Yes			870		135		12		756
Tongda⁽⁷⁾	China	1998		100.00	%		Yes			1,299		151		6		632
Emgasud	Argentina	1992		37.00	%		No			482		25		8		28

										20,892		2,375		369		3,042

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(1)		Information provided in this table is as of June 30, 2009, unless otherwise indicated.
(2)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.
(3)		“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.
(4)		AEI has operating control through its operating control of Promigas.
(5)		Includes its consolidated subsidiaries, Gases de La Guajira, Gases del Quinido, Gases del Risaralda and Gas Natural del Centro
(6)		Includes BMG and its businesses. See “— Natural Gas Distribution — Beijing Macrolink Gas Co., Ltd. (BMG)” for a list of the franchises.
(7)		Includes Tongda and its businesses. See “— Natural Gas Distribution — Tongda Energy Private Limited (Tongda)” for a list of the franchises.

Our Retail Fuel businesses distribute and sell liquid fuels and CNG primarily to wholesale and retail customers. This segment contributed 19% of our Adjusted EBITDA (excluding Headquarters and Other) in 2008. In addition to owning, licensing and operating retail outlets, these businesses own fleets of bulk-fuel distribution vehicles. The businesses in this segment operate in a combination of regulated and unregulated markets. Retail fuel is a non-core business for us. Our two businesses in this segment are listed in the table below.

Retail Fuel⁽¹⁾

AEI

Ownership

Interest

Approximate

Start of

(Direct and

Operating

Volume Sold

Number of

Business

Country

Operations⁽²⁾

Indirect)

Control⁽³⁾

Product Sold

(2008)

Employees

SIE — Gazel

Colombia, Chile, Mexico, Peru

1986

24.96

Yes

Compressed Natural Gas

12,119 mmscf

665

SIE — Terpel

Colombia, Chile, Ecuador, Panama

1968

24.96

Yes

Gasoline, Diesel, Jet Fuel, Lubricants

1,660 million gallons

3,210

3,875


(1)		Information provided in this table is as of June 30, 2009, unless otherwise indicated.
(2)		“Start of Operations” refers to the beginning of commercial operations as a stand-alone entity, not when we acquired an interest in the business.
(3)		“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.

Power Distribution

Segment Overview

Our businesses in this segment are summarized in the table shown below. Information is as of June 30, 2009, unless otherwise indicated.


	Concession/License
	and Contract
	Scheduled	Renewal	Target	Next Tariff
Business	Termination Date	Option	Regulated Return⁽¹⁾	Review

Elektro	2028	30 years	15.08%	2011 (every 4 years)
Elektra	2013	15 years (subject to winning a new bid)	10.73%	2010 (every 4 years)
EDEN	2012	10 years (subject to winning a new bid)	N/A	Undefined
Delsur	Indefinite; terminates only if Delsur breaches license	Indefinite	10.00%	2012 (every 5 years)
Chilquinta	Indefinite; terminates only if Chilquinta breaches concession	Indefinite	10.00%	2012 (every 4 years)
Luz del Sur	Indefinite; terminates only if LDS breaches concession	Indefinite	12.00%	2009 (every 4 years)
EMDERSA	2010-2018 (varies by franchise)	10-15 years (subject to winning new bid)	N/A	N/A


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

For the year ended December 31, 2008, the Power Distribution segment accounted for 24% of our net revenues, 53% of our operating income and 56% of our Adjusted EBITDA. For the six months ended June 30, 2009,

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the Power Distribution segment accounted for 25% of our net revenues, 45% of our operating income and 46% of our Adjusted EBITDA.

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 with negligible liquidity. Elektro is regulated by the Brazilian Securities and Exchange Commission (Comissão de Valores Mobiliários) and, as a regulated power distribution concessionaire, by ANEEL.

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


							As of and
							for the
							Six Months
	As of and for the Year						Ended
	Ended December 31,						June 30,
	2006		2007		2008		2009
	(In millions of $, except GWh, customers and miles)

Customers (thousands)		1,954		2,005		2,067		2,095
Energy sales (GWh)⁽¹⁾		9,561		9,971		10,844		5,342
Network length (miles)		62,678		64,478		65,749		66,163
Operating income	$	320	$	323	$	298	$	113
Depreciation and amortization	$	60	$	115	$	110	$	46
Net debt⁽²⁾	$	134	$	229	$	241	$	318


(1)		Does not include sales for distribution in third-party transmission.
(2)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	415		$	414		$	370		$	507
Less
Cash and cash equivalents		(237	)		(130	)		(93	)		(131	)
Current restricted cash		(23	)		(25	)		(7	)		(23	)
Non-current restricted cash		(21	)		(30	)		(29	)		(35	)

Net debt	$	134		$	229		$	241		$	318

Concession and Contractual Agreements; Tariffs

Elektro holds a 30-year renewable concession from ANEEL covering five municipalities in the state of Mato Grasso do Sul and 223 municipalities in the state of São Paulo, the largest state in terms of GDP in Brazil, which accounted for 30.3% of national electricity consumption in 2008. Elektro’s concession area encompasses approximately 46,300 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 for Brazilian power distribution companies are reviewed by ANEEL periodically. Elektro has tariff reviews every four years, and its last review was in August 2007. Following this review which was finalized in 2009, Elektro’s tariffs were reduced by 20.52%. 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.

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ANEEL uses a model distribution company as its basis to calculate reasonable reimbursable operational and administrative 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 2009 and increased the average tariff by 4.98%. 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 mechanism has also historically allowed distribution companies to benefit from higher energy sales or improved sales mix in comparison with the parameters utilized in the preceding tariff review, during the four year cycle until the following tariff review. Nevertheless, losses could also be incurred if sales or mix were less favorable than forecasted. However, ANEEL has indicated that the pass through of non-controllable costs should be neutral, meaning that it should not cause any gains or losses to the distribution companies. In September 2008, ANEEL issued a technical note proposing changes to adjust this methodology. This proposal is currently under analysis by the Ministry of Mines and Energy.

Customer Base

As of June 30, 2009, Elektro served approximately two million customers. Since 2006, Elektro has experienced a 2.9% average annual growth rate of its customer base. Additionally, electricity consumption in Elektro’s concession area has grown 4.3% per year during the same period. 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 11.2% of total 2008 GWh sales and 7.7% of total 2008 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,						As of June 30,		2008/2006
Customer Type	2006		2007		2008		2009		(%)

Residential		1,674,743		1,712,012		1,763,950		1,789,550		2.6
Commercial		131,522		133,693		139,733		141,256		3.1
Industrial		21,475		21,833		22,112		21,924		1.5
Government		19,432		20,041		21,228		21,545		4.5
Rural		107,035		117,314		120,128		121,027		6.0

Total		1,954,207		2,004,893		2,067,151		2,095,302		2.8

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Sales by Types of Customer


													For the Six Months				Average Annual
	For the Year Ended December 31,												Ended June 30, 2009				Growth 2008/2006
Customer Type	2006				2007				2008								%
	(In millions of $, except GWh)

				GWh				GWh				GWh				GWh				GWh
Residential	$	618		3,060	$	704		3,184	$	739		3,347	$	332		1,776		9.4		4.6
Commercial		256		1,379		296		1,490		305		1,580		141		834		9.2		7.0
Industrial		445		3,348		469		3,464		594		4,052		237		1,797		16.1		10.2
Government		138		1,004		150		1,024		152		1,058		70		547		5.0		2.7
Rural		80		770		90		809		87		807		37		389		4.5		2.4
Other revenues/taxes⁽²⁾		(507	)	306		(514	)	123		(488	)	31		(257	)	197		(1.9	)	(67.3	)

Total net revenues — Elektro		1,031		9,868		1,194		10,094		1,389		10,876		560		5,538		16.1		5.0
EKCE⁽¹⁾		49		1,338		45		986		18		318		6		117		(33.3	)	(47.1	)

Total net revenues — consolidated	$	1,080		11,206	$	1,239		11,080	$	1,407		11,194		566		5,656		14.2		0.0


(1)		EKCE — Elektro Comercializadore de Energia Ltda. is Elektro’s marketing company. EKCE’s results are consolidated into Elektro’s U.S. GAAP financial results.
(2)		Includes revenues in other categories net of social integration, social security and value-added taxes.

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 2003 regulatory changes. These contracts are denominated in Brazilian reais and adjusted for inflation, except for those with Itaipu, which are U.S. dollar denominated and accounted for about 25% of Elektro’s power supply in 2008. 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 PPAs 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. Energy purchases of up to 3% in excess of a distribution company’s total demand are allowed to be fully passed through to customers. If the distribution company foresees that it may be short of energy in the following years, it may buy additional energy up to 1% of its total demand of the previous year in annual auctions (except 2009, when the limit 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.

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Operations

Elektro has extensive experience in power distribution operations management, including the management of a state-of-the-art call center and an operations dispatch and call 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 and a state-of-the-art communications infrastructure. Among other technological innovations, Elektro pioneered in Brazil the use of personal digital assistants for the optimal dispatch of field crews. In addition, Elektro has certifications under ISO 9001, ISO 14001 (for four substations) and OSHAS 18001 (for the head office and regional offices).

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.

As of June 30, 2009, Elektro has 119 substations, 3,006 MVA of installed transformation capacity with over 65,318 miles of distribution lines and 845 miles of transmission lines. Elektro has six regional offices and technical teams in 105 strategic locations for services, including the restoration of electricity service, maintenance of the distribution network and other commercial services. Peak load as of December 31, 2008 was 2,283 MW.

Elektro has historically maintained outages at relatively low levels compared to Brazilian electricity companies with similar concessions as shown in the table below:


	For the Year Ended
	December 31,
	2006		2007		2008

FEC (number per customer per year)		6.7		6.4		6.0
DEC (hours per customer per year)		10.2		9.4		8.5
Losses (%)		6.9		6.9		6.7

Elektro has implemented various efficiency measures since the privatization in 1998. 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, 80.3 GWh in 2007 and 92.6 GWh in 2008. Compared to other large private power distributors in Brazil, Elektro ranked best compared to the model company with respect to energy losses in 2008.

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 approximately 45,000 new customers since November 2004 (over 9,400 in 2007 plus an additional 3,267 in that year through rural universalization and approximately 7,600 new rural customers in 2008) and currently plans to connect approximately 7,300 new rural customers in 2009. Elektro has invested $106 million in this program from November 2004 until June 30, 2009. Third party financing covers approximately 75% of these capital expenditures (of which 21% is provided by the Brazilian Energy Development Account (Conta de Desenvolvimento Energético) and 54% is funded from the Global Reserve Fund (Reserva Global de Reversão)), 10% is provided by Brazilian government funding and 15% from Elektro’s own cash.

Elektro has 2,806 employees all of which are unionized. The collective bargaining agreement expired in May 2009 and a new agreement is under discussion with the union. Relations with the union have been constructive and there have been no work stoppages to this date.

Financing

As of June 30, 2009, Elektro had R$543 million in debentures maturing in 2011 and R$451 million in notes maturing between 2009 and 2020. In July 2009, Elektro closed a R$300 million (approximately $152 million) debenture offering, the proceeds of which are being used to refinance maturing debt.

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

In May 2009, Standard & Poor’s upgraded Elektro’s local rating to brAA+, one of the highest Standard & Poor’s ratings in the electricity distribution sector in Brazil. Standard & Poor’s also upgraded the local rating to brAA+ for Elektro’s non-convertible debentures.

Elektra Noreste, S.A. (Elektra)

Overview

Our subsidiary Elektra was the second largest electricity distribution company in Panama in terms of electricity volume distributed and area served as of December 31, 2008. 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, a wholly owned subsidiary of AEI, with a substantial majority of the remainder retained by the Panamanian government.

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


							As of and
							for the
							Six Months
	As of and For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009
	(In millions of $,
	except GWh, customers and miles)

Customers (thousands)		312		328		340		342
Energy sales (GWh)⁽¹⁾		2,029		2,179		2,250		1,147
Network length (miles)		4,917		5,154		5,393		5,523
Operating income	$	33	$	34	$	36	$	18
Depreciation and amortization	$	12	$	13	$	13	$	7
Net debt⁽²⁾	$	67	$	91	$	119	$	101


(1)		Does not include sales for distribution in third-party transmission.
(2)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	99		$	99		$	144		$	119
Less
Cash and cash equivalents		(32	)		(8	)		(25	)		(18	)
Current restricted cash		—			—			—			—
Non-current restricted cash		—			—			—			—

Net debt	$	67		$	91		$	119		$	101

Concession and Contractual Agreements; Tariffs

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 June 30, 2009, 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 53% of the country’s container port activities are located; and the eastern portion of the province of Panama where the international airport, the main water company and the main cement company are located. As of December 31, 2008, Elektra had a market share of approximately 44% of the customers and approximately 42% of total energy sales in Panama.

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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, 2008, Elektra purchased approximately 81% of its total energy requirements through PPAs. 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 2009, Elektra has contracted 92% of its energy requirements and for 2010 to 2012 has already fully contracted 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 investments, operating, maintenance, administrative and service expenses, a standard level of loss and depreciation and a reasonable return on invested capital.

Customer Base

As of June 30, 2009, Elektra served approximately 342,000 customers. The average annual growth in customers from 2006 through 2008 was 4.4%. As of June 30, 2009, no single customer represented more than 10.0% of Elektra’s sales. As of December 31, 2008, Elektra had energy sales of 2,250 GWh to 340,000 customers with volumes allocated as follows: 41% commercial, 33% residential, 14% governmental and 12% industrial.

Operations

As of December 31, 2008, Elektra had a peak demand of 395 MW and achieved a load factor of 72%. As of June 30, 2009, Elektra’s electricity distribution network comprised approximately 5,523 miles of distribution and transmission lines, 12 key substations and 1,208 MVA of transforming capacity. 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 a workforce of 1,368 people, of which 821 are contractors. Out of the 547 direct employees, 206, or 38%, were unionized. The collective bargaining agreement was re-negotiated in 2008 and expires in February 2012. Relations with the union have historically been constructive and there have been no work stoppages.

The following table summarizes Elektra’s actual urban outages for the periods indicated. 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,
	2006		2007		2008

SAIFI (number per customer per year)		3.0		2.7		2.8
SAIDI (hours per customer per year)		3.4		3.0		3.1
Losses (%)		10.4		9.6		9.2

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 June 30, 2009, Elektra’s outstanding third-party indebtedness totaled $119 million, consisting of $99 million of unsecured senior notes issued in June 2006 and $20 million in corporate bonds issued in October 2008. These corporate bonds are part of a $40 million offering, the second $20 million tranche of which is currently

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on hold due to market conditions. Elektra has a revolving credit facility of $100 million, none of which was drawn as of June 30, 2009.

Management and Governance

We appoint three of the five board members of Elektra. The Panamanian government has the ability to select two out of the five members of Elektra’s board of directors.

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 through 10,897 miles of distribution lines. 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 2008, we recognized from EDEN operating income of $14 million and depreciation and amortization of $3 million. As of June 30, 2009, we recognized from EDEN operating income of $14 million and depreciation and amortization of $2 million. As of June 30, 2009, EDEN had net debt of $4 million, which is derived from $25 million of total debt, less $21 million of cash and cash equivalents.

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


							For the
							Six Months
	As of and For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Customers (thousands)		307		315		322		325
Energy sales (GWh)⁽¹⁾		1,998		2,127		2,225		1,119
Network length (miles)		10,431		10,497		10,897		10,910


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

Concession and Contractual Agreements; Tariffs

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 approximately 47% on average. EDEN is in a tariff review process which we expect to be completed in 2009.

Customer Base

As of June 30, 2009, EDEN served approximately 325,000 customers. No single customer represented more than 10% of EDEN’s sales. The customer base has grown at an average rate of 4.5% from 2005 to 2008. As of December 31, 2008, EDEN had energy sales of 2,225 GWh and volumes were allocated as follows: 26% residential, 12% commercial, 32% industrial, 24% cooperatives and 6% government.

Operations

As of June 30, 2009, EDEN had a workforce of 740 employees, of which 622 were unionized. Relations with the unions have been constructive. EDEN has earned certifications under ISO 9001.

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


	For the Year Ended
	December 31,
	2006		2007		2008

SAIFI (number per customer per year)		8.7		8.2		8.8
SAIDI (hours per customer per year)		15.5		13.8		15.0
Losses (%)		9.2		10.0		10.1

Financing

As of June 30, 2009, EDEN had $35 million in debt in the form of a dollar-denominated syndicated credit agreement, of which AEI owned $10 million. Subsequent to June 30, 2009, AEI purchased an additional approximately $21 million in principal amount of EDEN’s debt. 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 outstanding debt. The designated administrative agent, upon receipt of instructions from the lenders of this debt (other than AEI), 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, but is exploring refinancing alternatives. 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 1,655 square miles, which includes approximately 2.5 million people and constitutes approximately 25% of total energy sales in El Salvador as of December 31, 2008. Delsur was privatized in 1998. In May 2007, AEI acquired 86.4% of Delsur’s common stock. 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 2008, we recognized from Delsur operating income of $12 million and depreciation and amortization of $11 million. As of June 30, 2009, we recognized from Delsur operating income of $6 million and depreciation and amortization of $6 million. As of June 30, 2009, Delsur had net debt of $63 million, which is derived from $69 million of total debt, less cash and cash equivalents of $3 million and restricted cash of $3 million.

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


							As of and
							for the
							Six Months
	As of and for the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Customers (thousands)		291		299		308		311
Energy sales (GWh)⁽¹⁾		1,098		1,113		1,162		574
Network length (miles)		4,749		5,137		5,159		5,296


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

Concession and Contractual Agreements; Tariffs

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.

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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 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, distribution and customer charges were reduced by a combined average of 21.6% compared to the previous tariff. 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 June 30, 2009, no single customer represented more than 10.0% of Delsur’s sales. As of December 31, 2008, Delsur served approximately 308,000 customers and had energy sales of 1,162 GWh with volumes allocated as follows: 35% residential, 7% commercial, 56% industrial and 2% other. The average annual growth of the number of customers from 2006 to 2008 was 2.9%.

Operations

As of December 31, 2008, Delsur had a peak demand of 226 MW and achieved a load factor of approximately 68%. As of June 30, 2009, Delsur’s electricity distribution network comprised 5,296 miles of distribution lines, 26 key substations and 277 MVA of transforming capacity. As of June 30, 2009, Delsur had 273 employees of which 171 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.


	For the Year Ended
	December 31,
	2006		2007		2008

SAIFI (number per customer per year)		10.8		17.1		15.3
SAIDI (hours per customer per year)		31.4		41.5		37.5
Losses (%)		8.9		8.9		8.8

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

In August 2008, Delsur entered into a $75 million seven-year senior term loan, of which $69 million is outstanding as of June 30, 2009. Delsur entered into an interest rate cap in November 2008, for a notional amount of $37 million to partially mitigate interest rate exposure.

Chilquinta Energía 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 2008 energy sales. Chilquinta owns a controlling interest in four power distribution companies in Chile: Litoral (75.61%), LuzParral (56.59%), LuzLinares (85.00%), and Energía Casablanca (69.75%). In 2008 and for the six months ended June 30, 2009, we recognized $32 million and $13 million, respectively, in equity income from our interest in Chilquinta.

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


							As of and
							for the
							Six Months
	As of and for the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Customers (thousands)⁽¹⁾		454		465		475		481
Energy sales (GWh)⁽²⁾		2,121		2,281		2,303		1,200
Network length (miles)⁽¹⁾		4,949		5,019		5,088		5,118


(1)		Does not include subsidiaries of Chilquinta.
(2)		Does not include sales for distribution in third-party transmission.

Concession and Contractual Agreements; Tariffs

Chilquinta is the main power distributor for Chile’s Region V, and its concession area comprises approximately 1,960 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. 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 new regulations, referred to as 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 will be determined through competitive tenders by distributors.

Customer Base

As of June 30, 2009, Chilquinta served approximately 481,000 customers. As of December 31, 2008, Chilquinta had energy sales of 2,303 GWh to approximately 475,000 customers with volumes distributed as follows: 30% residential, 26% industrial, 18% commercial, 7% governmental, 8% rural and 11% other.

Operations

As of June 30, 2009, Chilquinta employed 618 people, 261 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.

Our affiliate, 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,
	2006		2007		2008

SAIFI (number per customer per year)		2.7		1.5		1.5
SAIDI (hours per customer per year)		7.3		4.1		3.8
Losses (%)		9.4		9.3		8.4

Financing

As of June 30, 2009, Chilquinta’s outstanding third party indebtedness totalled $224 million.

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Management and Governance

Chilquinta’s affairs and the relationship among its shareholders are regulated by its bylaws and a shareholders agreement. The only other shareholder of Chilquinta, holding the remaining 50%, is an affiliate of Sempra Energy International, or Sempra. The board of directors consists of six members, half of which are appointed by us and the other half by Sempra. All decisions of the board effectively require an affirmative majority vote.

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

Overview

On December 14, 2007, we acquired a 50.00% interest in Peruvian Opportunity Company S.A.C., 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. As of September 8, 2009, we signed agreements with certain shareholders of Luz del Sur pursuant to which we will acquire an additional l3.65% in Luz del Sur. Closing of this transaction is subject to certain conditions, including the listing of our shares on an approved exchange, including the NYSE. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments in 2009.” Luz del Sur is the largest power distribution company in Peru as measured by 2008 energy sales and is listed on the Lima Stock Exchange under the symbol “LUSURC1.” In 2008 and for the six months ended June 30, 2009, we recognized $32 million and $18 million, respectively, in equity income from our interest in Luz del Sur.

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


							As of and
							for the
							Six Months
	As of and for the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Customers (thousands)⁽¹⁾		760		782		808		822
Energy sales (GWh)⁽¹⁾⁽²⁾		4,642		4,994		5,333		2,739
Network length (miles)⁽¹⁾		11,004		11,169		11,367		11,482


(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; Tariffs

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 4 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. The results of such review are uncertain at this time. 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 June 30, 2009, Luz del Sur served approximately 822,000 customers. As of December 31, 2008, Luz del Sur served approximately 808,000 customers and had energy sales of 5,333 GWh, broken down as follows: 40%

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residential, 23% industrial, 17% commercial and 20% other. This represented approximately 20% of market share in Peru by sales volume.

Operations

As of June 30, 2009, Luz del Sur employed approximately 695 people, 280 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.

Our affiliate, 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,
	2006		2007		2008

FEC (equivalent frequency of interruption per year)		3.1		2.2		2.2
DEC (equivalent duration of interruption per year)		6.9		6.3		6.1
Losses		7.8		7.6		7.5

Financing

As of June 30, 2009, Luz del Sur’s outstanding third party indebtedness totalled $228 million. In September 2009, Luz del Sur issued local currency bonds authorized under its existing bond program to refinance a maturing bond issue. The amount issued was 73 million Peruvian nuevos soles (approximately $25 million). The bonds mature in five years. The interest rate was 6.47%. The issuance was rated locally pAAA by PCR and AAA by Class & Asociados ratings.

Management and Governance

Luz del Sur is controlled by POC. We and an affiliate of Sempra each own a 50% interest. Luz del Sur’s affairs and the relationship among its shareholders is regulated by its bylaws and a shareholders agreement. The board of directors of Luz del Sur consists of four members, all of which are appointed by POC and half of which are nominated by us and the other half by Sempra. All decisions of the board effectively require an affirmative majority vote.

Empresa Distribuidora Eléctrica Regional S.A. (EMDERSA)

Overview

In May 2009, we acquired a 19.91% interest of EMDERSA. In August 2009, we acquired an additional 4.5% interest; on September 24, 2009, we acquired an additional 25.61% interest; and on October 13, 2009, we acquired an additional 27.09% of EMDERSA. As a result, we now own an aggregate of 77.11%. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments in 2009.” EMDERSA is a holding company which, through its subsidiaries EDESAL, EDELAR and EDESA distributes electricity in Argentina on an exclusive basis to the Provinces of San Luis, La Rioja and Salta, respectively. It owns 99.99% of EDESAL, 99.99% of EDELAR and 90% of the capital stock of EDESA. EMDERSA supplies a region of approximately 124,000 square miles and a population of approximately 2 million people. EMDERSA is listed on the Buenos Aires Stock Exchange under the symbol “EMDEHR.”

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


							As of and
							for the
							Six Months
	As of and for the Year Ended						Ended
	December 31						June 30,
	2006		2007		2008		2009

Customers (thousands)		462		479		495		502
Energy sales (GWh)⁽¹⁾		2,387		2,597		2,673		1,352
Network length (miles)		15,161		15,333		15,493		15,493

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

Concession and Contractual Agreements; Tariffs

EDESAL, EDELAR and EDESA each hold an exclusive concession for electricity distribution in the Provinces of San Luis, La Rioja and Salta, respectively. The EDESAL, EDELAR and EDESA concessions were entered into in 1993, 1995 and 1996 for periods of 95 years, 95 years and 50 years, respectively, and are divided into several administrative periods, the first of which lasts 15 years in the case of EDESAL and EDELAR (each with subsequent eight periods which last 10 years each) and 20 years in the case of EDESA (with subsequent two periods of 15 years each). With the exception of EDESAL, the concession agreements establish an auctioning mechanism for the sale of a controlling stake in the distribution companies at the end of each administrative period; provided, however, that EMDERSA can retain the controlling stake, without having to make any payment, if it submits to the provincial government a valuation for the controlling stake that is equal to or higher than the highest offer submitted in the auction process. At the end of the concession term, the assets are transferred to the respective provincial government for a payment that is received from a new entity that bids for the concession. In the case of EDESAL, at the end of each administrative period, the government of the Province of San Luis reserves the right to suspend the concession or modify the area in which it applies. At the end of the concession term, the assets are transferred to the respective provincial government for a payment that is received from a new entity that bids for the concession.

EDESAL’s, EDELAR’s and EDESA’s tariffs are regulated by the regulators in the provinces in their respective concession areas. The tariffs were originally approved for a period of five years with adjustments every six months based on variations in the Argentine wholesale power market, or MEM, and the U.S. consumer price index, or U.S. CPI. In January 2002, as a result of the Public Emergency Law, tariffs were converted from their original U.S. dollar values to Argentine pesos at a rate of AR$1.00 per U.S.$1.00 and the adjustment for inflation was cancelled. Since the first tariff review, subsequent reviews have not followed regulation nor have been well-defined with respect to requiring distribution companies to obtain tariffs and associated increases on an interim basis.

Customer Base

As of December 31, 2008, EMDERSA served 494,851 customers with sales of 2,673.2 GWh with volumes allocated as follows: 42% residential, 12% commercial, 39% industrial, and 7% government.

Operations

As of December 31, 2008, EMDERSA had a workforce of 394 employees. EMDERSA has earned certifications under ISO 9001.

Financing

As of June 30, 2009, EMDERSA had $77 million in third party debt.

Management and Governance

EMDERSA’s affairs and the relationship among its shareholders are regulated by its bylaws. On September 24, 2009, we became the controlling shareholder of EMDERSA, owning 50.02% of its capital stock. We have the right to nominate at least five of the seven members of the board of directors of EMDERSA. All decisions of the board require an affirmative majority vote, with certain material decisions (including, without limitation, the merger, consolidation or liquidation of the company, the appointment of directors, and any capital increase or reduction of the capital of EMDERSA) requiring the affirmative vote of shareholders representing the majority of the aggregate voting interest present at any shareholders meeting.

Power Generation

Segment Overview

Our 12 businesses in this segment are listed in the table below. During the first quarter of 2009, the build-operate-transfer, or BOT, agreement for Subic expired on schedule and the plant was turned over to NPC. Information is as of June 30, 2009, unless otherwise indicated.

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Power Generation

Percent Generating

Capacity Under

Contracts and

AEI

Scheduled

Ownership

Installed

Termination Date

Interest

Generating

Under Principal

Approximate

(Direct and

Operating

Capacity

Primary

Power Purchase

Number of

Business

Country

Indirect)

Control⁽¹⁾

(MW)

Fuel Type

Agreements

Employees

Trakya⁽²⁾

Turkey

59.00%

Yes

478

Natural Gas

100% until June 2019

Cuiabá — EPE

Brazil

50.00%

Joint with
Shell

480

Natural Gas

100% until May 2019

Luoyang

China

50.00%

Yes

270

Coal

PPA renewed
annually.

195

PQP

Guatemala

100.00%

Yes

234

Bunker Fuel

47% until February
2013

San Felipe

Dominican
Republic

100.00%

Yes

180

Diesel Oil/ Bunker
Fuel

100% until January
2015

ENS

Poland

100.00%

Yes

116

Natural Gas

79% until December
2010

Corinto

Nicaragua

57.67%

Yes

Bunker Fuel

71% until September
2014

Tipitapa

Nicaragua

57.67%

Yes

Bunker Fuel

100% until 2014

JPPC

Jamaica

84.42%

Yes

Bunker Fuel

100% until 2018

DCL

Pakistan

60.22%

Yes

Natural Gas

N/A

Emgasud

Argentina

37.00%

109

Natural Gas/ Fuel
Oil

100% until 2011 and
2012

Amayo

Nicaragua

12.72%

Wind

100% until 2024

2,182

828


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


(2)		On August 27, 2009, we acquired an additional 31.00% interest in Trakya.

For the year ended December 31, 2008, the Power Generation segment accounted for 13% of our net revenues, 2% of our operating income and 8% of our Adjusted EBITDA. For the six months ended June 30, 2009, the Power Generation segment accounted for 14% of our net revenues, 18% of our operating income and 18% of our Adjusted EBITDA.

Power Generation Growth

We are actively involved in several development projects in this segment. By their nature, these are long-term projects involving siting, permitting, sourcing, marketing, constructing, financing and ultimately operating activities. Our greenfield development activities in power generation are focused in the markets where we currently operate, including opportunities that are advancing in Guatemala and Peru, namely Jaguar and Fenix. In May 2008, Jaguar 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. Jaguar executed the PPAs 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. Subject to obtaining financing and completion of other project milestones, we anticipate commencing construction in the second half of 2009 and commercial operations in the second half of 2012. In June 2008, we completed the purchase of an 85.00% interest in Fenix, 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 obtaining financing, securing a gas supply agreement and completion of other project milestones, we anticipate commencing construction in the second half of 2010 and commercial operations in the first half of 2013.

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

Overview

We own a 90% interest in Trakya, a Turkish combined cycle combustion turbine generator with a nominal capacity of 478 MW. 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 alternative fuel (gasoil), 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 gasoil. The power plant commenced commercial operations in June 1999.

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


										As of and
										for the
										Six Months
	As of and for the Year Ended									Ended
	December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $,
	except MW, % and Btu/kWh)

Capacity (MW)		478			478			478			478
Capacity factor (%)		99.2			98.5			96.5			96.8
Heat rate (Btu/kWh)		7,432			7,415			7,442			7,454
Operating income	$	85		$	46		$	24		$	31
Depreciation and amortization	$	19		$	19		$	16		$	8
Net debt⁽¹⁾	$	(82	)	$	(62	)	$	(59	)	$	(55	)


(1)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


	As of December 31,									As of June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	94		$	47		$	—		$	—
Less
Cash and cash equivalents		(60	)		(8	)		(59	)		(55	)
Current restricted cash		(13	)		(13	)		—			—
Non-current restricted cash		(103	)		(88	)		—			—

Net debt	$	(82	)	$	(62	)	$	(59	)	$	(55	)

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 ended September 2008, and therefore payments under it decrease over time, however, revenue recognition is levelized over the full contract period. 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 company, 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

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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.

As a result of changes to Turkish law which were made in 2002, the Turkish Energy Market Regulatory Authority required generation companies in Turkey, including Trakya, to obtain an electricity generation license. Trakya filed a license application in 2002, but challenged the validity of the change in law in Turkish court on the basis that it did not protect Trakya’s vested rights under the government authorization it was granted prior to this change in law. If this legal challenge is not successful, it is possible that any license granted by the Turkish Energy Market Regulatory Authority may contain terms which differ from those existing under Trakya’s current authorization agreements.

Since November 2002, Trakya and the other Turkish BOT projects have been under pressure from MENR to renegotiate their current contracts. The primary aim of MENR is to reduce what it views as excess returns paid to the projects by TETAŞ under the existing PPAs. AEI and the other shareholders of Trakya developed a proposal and presented it to MENR in April 2006. MENR has not formally responded to the proposal.

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. As a result of the recent liberalization of the gas market in Turkey, Trakya would be able to purchase gas from other sellers, subject to availability, if BOTAŞ does not make gas available after 2014. The payment 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 (including gasoil), subject to target efficiencies. Trakya’s ability to operate using 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 as shown in the table below.


							For the
							Six Months
	For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Availability (%)		97.6		97.7		88.3		96.5
Reliability (%)		99.9		99.7		99.0		99.9
Energy sales (GWh)		3,703		3,753		3,342		1,889

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 2008.

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.

Financing

As of June 30, 2009, Trakya had no third party debt.

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.

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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).” EPE generally has not operated since August 2007 due to lack of gas supply.

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.

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


										As of and
										for the
										Six Months
	As of and for the Year Ended									Ended
	December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $,
	except MW, % and Btu/kWh)

Capacity (MW)		480			480			480			480
Capacity factor (%)		25.1			28.8			3.8			—
Heat rate (Btu/kWh)		7,544			7,624			7,576			N/A
Operating income (loss)	$	(1	)	$	(85	)	$	(90	)	$	(32	)
Depreciation and amortization	$	1		$	1		$	1		$	3
Net debt⁽¹⁾⁽²⁾	$	12		$	3		$	24		$	22


(1)		Attributable to notes owed to shareholder affiliates.
(2)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	44		$	42		$	42		$	43
Less
Cash and cash equivalents		(32	)		(39	)		(13	)		(15	)
Current restricted cash		—			—			—			—
Non-current restricted cash		—			—			—			(6	)

Net debt	$	12		$	3		$	24		$	22

Concession and Contractual Agreements

In January 1998, EPE was granted a generation license by ANEEL to sell electricity to third parties. EPE has contracted to sell all of its capacity and associated energy to Furnas, one of Brazil’s federally-controlled electricity generation companies, under a PPA with a 21 year term ending in 2019. The obligations of Furnas under the PPA are guaranteed by Eletrobrás, Furnas’ parent.

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. CPI. 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

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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 lower 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. In 2008, TBS invoiced EPE $57 million under this agreement.

Further to the nationalization of the hydrocarbons sector by the Bolivian government, TBS entered into 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 (but resume sporadically). 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. Both we and EPE continue to pursue alternative sources of natural gas.

Due to lack of gas supply from Bolivia, the plant operated on a minimal basis beginning in the third quarter of 2007. As a result, Furnas refused to make capacity payments under the PPA and on October 1, 2007 issued a notification of intent to terminate the PPA. EPE strongly disagreed with Furnas’ allegation and the parties initiated an arbitration process in accordance with the terms of the PPA. EPE cited the fact that Furnas had no contractual basis to terminate and that the PPA does not authorize termination or non-compliance due to the lack of or non-availability of gas. Furthermore, EPE argued that the lack of gas supply was caused by acts of governmental authorities in Bolivia, which constitute a force majeure event pursuant to the PPA. On December 30, 2008, EPE amended its initial pleadings and requested the termination of the PPA based on the Furnas default to make capacity payments and, consequently, for the tribunal to apply the indemnity provision in the PPA pursuant to which Furnas is obligated to buy the plant. We expect a decision in this arbitration during 2009.

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 2008, pursuant to this ministerial order, the EPE power plant ran on diesel and collected approximately $6 million in revenue. The term of this agreement has now expired.

EPE has reduced take-or-pay payments under its GSA with TBS. As noted above, 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).”

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Operations

EPE is certified under ISO 9001, ISO 14001 and OHSAS 18001. EPE generally has not operated since August 2007 due to lack of gas supply.


							For the
							Six Months
	For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Availability (%)		95.6		91.7		100.0		100.0
Reliability (%)		99.0		99.8		100.0		100.0
Energy sales (GWh)		1,054.9		1,014.7		161.2		—

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 $110 million from affiliates of AEI as of June 30, 2009. Pursuant to credit restructuring agreements, EPE can use excess cash balances above stipulated minimum cash requirements to reduce indebtedness to affiliates.

Management and Governance

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 have appointed the current chief executive officer and Shell has appointed the current chief financial officer of all of the Cuiabá Integrated Project businesses. Pursuant to the terms of the agreements with Shell, these appointment rights have alternated. However, neither we nor Shell have exercised the right to alternate these appointments.

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.

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 its service area in the Luoyang New District, a growing area that is home to the city government, industrial zone and the new town center.

For the year ended December 31, 2008, Luoyang achieved a capacity factor of 35.8%, a heat rate of 9671 Btu/kWh, and we recognized operating losses of $(19) million and depreciation and amortization of $7 million. As of June 30, 2009, Luoyang had operating income of $1 million, depreciation and amortization of $4 million and net debt of $114 million which is derived from total debt of $116 million, less cash and cash equivalents of $2 million.

Concession and Contractual Agreements

Luoyang sells power to the Henan Provincial Power Company. The tariff is set by the Henan Provincial Pricing Bureau with the approval of the National Development and Reform Commission, or NDRC. Luoyang also

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sells steam to the Luoyang Municipal Heating Company through a steam sales contract. Both the power sales agreement and the steam sales contract contain an evergreen provision, pursuant to which they are automatically renewed annually unless terminated by notice. Luoyang also 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 the Henan Provincial Development and Reform Commission.

Luoyang is a priority dispatched plant according to newly adopted energy conservation and efficiency regulations and, as long as it supplies steam and heat in addition to power, it has preferential dispatch of its power generated, in priority to other non-cogeneration power plants in the same grid using gas, coal or oil as their fuel.

Operations

Commercial operations of the plant began in 2006. Historically, Luoyang had been operated and maintained by third-party contractors but as of May 2009, the third party operations were terminated and Luoyang assumed operations of the plant. The following table sets forth availability and reliability information for the periods indicated:


								For the
								Six Months
	For the Year Ended							Ended
	December 31,							June 30,
	2006		2007		2008			2009

Availability (%)⁽¹⁾		N/A		N/A		61.8	%		94.0	%
Reliability (%)⁽¹⁾		N/A		N/A		90.4	%		98.1	%
Energy sales (GWh)		740		907		750			518


(1)		Figures not available. Luoyang was not owned by AEI during 2006 or 2007.

Financing

Luoyang is currently insolvent with negative equity. As of June 30, 2009, Luoyang had $116 million in third party debt and $15 million in trade payables. If, as a result of the current financial difficulties, Luoyang is unable to pay its creditors on a timely basis, such creditors may seek to exercise various remedies including foreclosing on some or all of Luoyang’s assets. Such event would have a corresponding negative impact on our financial performance and results of operations, but we do not believe this would have a material adverse effect on us.

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.

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 12.4% of the country’s firm capacity and 8.1% of the country’s electricity generation in 2008. AEI currently indirectly owns 100% of PQP.

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


							As of and
							for the
							Six Months
	As of and for the Year						Ended
	Ended December 31,						June 30,
	2006		2007		2008		2009

Capacity (MW)		234		234		234		234
Capacity factor (%)		27.6		39.6		31.7		49.5
Heat rate (Btu/kWh)		9,312		9,256		9,228		9,107
Operating income	$	38	$	42	$	23	$	18
Depreciation and amortization	$	2	$	5	$	5	$	5
Net debt⁽¹⁾	$	21	$	80	$	70	$	63


(1)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	57		$	90		$	88		$	80
Less
Cash and cash equivalents		(13	)		(8	)		(14	)		(17	)
Current restricted cash		(8	)		(2	)		(4	)		—
Non-current restricted cash		(15	)		—			—			—

Net debt	$	21		$	80		$	70		$	63

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 2008, sales made to EEGSA under the PPA accounted for approximately 56.7% 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 with an option to extend to 2016. The fuel supply agreement includes detailed fuel specifications that have to be satisfied in order to meet equipment and environmental requirements. From time to time PQP enters into hedging arrangements to reduce exposure to the volatility of fuel prices. PQP executed an amendment to its long-term fuel supply agreement in June 2009, effective as of January 2009. The primary changes include amendments to increase the premium paid per barrel of fuel, the option to extend to 2016 and to provide both parties with a more comprehensive set of remedies in an event of default.

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 reserves. Merchant operations represented 43% of PQP’s 2008 revenues.

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.”

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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						For the Six Months
	December 31,						Ended June 30,
	2006		2007		2008		2009

Availability (%)		93.9		93.6		93.7		96.3
Reliability (%)		98.1		98.9		98.5		99.2
Energy sales (GWh)		1,194.1		1,240.0		1,377.2		768.8

The Guatemalan tax authority, the Superintendency of Tax Administration (Superintendencia de Administración Tributaria), or SAT, has filed two claims against PQP for adjustments to income taxes and other temporary taxes for the periods of January 1, 2001 to December 31, 2002 and from January 1, 2003 to June 30, 2005. Both claims have been vigorously opposed by PQP. In February 2009, SAT withdrew the largest adjustment from the 2001-2002 claim. Both cases are still pending final resolution.

Financing

In October 2007, PQP entered into a non-recourse syndicated financing, which includes a $90 million eight-year floating rate term loan and a $25 million five-year revolving credit facility, of which US$80 million is outstanding as of June 30, 2009. 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 equivalent to 75% of principal outstanding to partially mitigate interest rate exposure.

Generadora San Felipe Limited Partnership (San Felipe)

Overview

Our subsidiary, San Felipe, owns a land-locked barge mounted 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 as of June 30, 2009 and in 2008 provided 8.9% of the energy delivered to the country’s system.

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 as of and for the dates indicated:


										As of and
										for the
										Six Months
	As of and for the Year									Ended
	Ended December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $, except MW, % and Btu/kWh)

Capacity (MW)		180			180			180			180
Capacity factor (%)		57			44			65			46
Heat rate (Btu/kWh)		9,457			9,185			9,496			9,443
Operating income	$	22		$	19		$	11		$	35
Depreciation and amortization	$	2		$	6		$	(9	)	$	(2	)
Net debt⁽¹⁾	$	(13	)	$	(16	)	$	(8	)	$	4


(1)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	—		$	—		$	—		$	—
Less
Cash and cash equivalents		(13	)		(16	)		(2	)		(2	)
Current restricted cash		—			—			(6	)		—
Non-current restricted cash		—			—			—			—

Net debt	$	(13	)	$	(16	)	$	(8	)	$	(2	)

Concession and Contractual Agreements

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

As of June 30, 2009, the CDEEE was in payment arrears of approximately $68 million, on which it is currently paying interest. As a result of payment delays San Felipe has from time to time stopped delivering energy. The CDEEE has requested that San Felipe renegotiate the PPA reducing the present level of energy and capacity charges, but there has been no material progress in the renegotiation.

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

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
							Six Months
	For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Availability (%)		77.9		83.7		82.6		93.6
Reliability (%)		77.9		94.8		91.2		97.4
Energy sales (GWh)		899		693		1,029		362

San Felipe received resolutions from the Dominican Republic environmental ministry which required the plant, among other things, to install particulate filtration systems before the end of September 2009. San Felipe has challenged the validity of the resolutions at the administrative level and the matter is still pending. While San Felipe will have the ability to challenge any adverse decision through the legal system (up to the Dominican Supreme Court), in the event that the resolution is ultimately held to be enforceable and San Felipe is found to be in breach of the resolution, the environmental license which San Felipe currently holds may be suspended.

Financing

On June 3, 2008, San Felipe entered into a $6 million revolving credit facility, all of which was undrawn as of June 30, 2009. As of June 30, 2009, San Felipe had no other third party indebtedness.

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.

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


							As of and
							for the
							Six Months
	As of and for the Year						Ended
	Ended December 31,						June 30,
	2006		2007		2008		2009
	(In millions of $, except MW, % and Btu/kWh)

Capacity (MW)		116		116		116		116
Capacity factor (%)		78.6		78.3		79.3		83.4
Heat rate (Btu/kWh)		8,678.3		8,592.4		8,586.0		8,590.5
Operating income	$	15	$	16	$	30	$	15
Depreciation and amortization	$	6	$	10	$	2	$	1
Net debt⁽¹⁾	$	53	$	57	$	56	$	43


(1)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	85		$	77		$	67		$	55
Less
Cash and cash equivalents		(19	)		(10	)		(8	)		(8	)
Current restricted cash		(13	)		(10	)		(3	)		(4	)
Non-current restricted cash		—			—			—			—

Net debt	$	53		$	57		$	56		$	43

Concession and Contractual Agreements

The Polish government had been working on restructuring the Polish electric energy market since the beginning of 2000 in an effort to introduce a competitive market in compliance with European Union legislation. In 2007, legislation was passed in Poland that allowed for power generators producing under long term contracts to voluntarily terminate their contracts subject to payment of compensation for stranded costs. ENS sent notice of its termination of its long-term power purchase contract in December 2007, with such termination being effective as of April 1, 2008. The compensation system consists of stranded costs compensation which is based upon the capital expenditures incurred before May 1, 2004, which could not be recovered from future sales in the free market and additional fuel gas costs compensation. Both will be paid in quarterly installments of varying amounts. The payments started in August 2008. ENS received $18 million in 2008 and $15 million for the six months ended June 30, 2009 in stranded costs compensation and fuel gas compensation. The maximum remaining compensation, for stranded costs and fuel gas costs, attributable to ENS is 1.03 billion Polish zloty (approximately US$320 million based on the exchange rate as of June 30, 2009). In 2008, ENS entered into a new power delivery agreement with Mercuria Energy Trading Sp. z.o.o. ending in December 2010. Should neither party terminate it, this agreement will be automatically extended for an additional three full calendar years.

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. The remaining 10% is sold to the city of Nowa Sarzyna under a medium-term Thermal Energy Supply Agreement which expires in 2010. 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 Agreements.

Polskie Górnictwo Naftowe i Gazownictwo supplies the plant with natural gas under a 20-year Fuel Supply Agreement which expires in 2019. 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 thermal energy (steam) prices and indirectly into the results of electric energy through the stranded cost compensation system.

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Operations

Since commercial operations commenced, the plant has had no significant technical concerns or outages. ENS is fully compliant with Polish and EU environmental law requirements. The following table sets forth availability and reliability information for the periods indicated:


							For the
							Six Months
	For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Availability (%)		90.8		99.8		98.1		99.9
Reliability (%)		99.9		99.8		99.9		99.9
Energy sales (GWh)		680.5		754.5		754.1		381.8
Thermal energy produced (GJ)		584,979		606,291		610,838		320,612

Financing

As of June 30, 2009, ENS had $55 million outstanding in third party debt.

Empresa Energética Corinto Ltd. (Corinto)

Overview

Corinto owns a 70.5 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 2008, the plant represented approximately 10.3% of the country’s installed capacity and 16.7% 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 and 2008, we recognized from Corinto operating income of $3 million and $4 million, respectively, and depreciation and amortization of $1 million and $3 million, respectively. As of June 30, 2009, we recognized from Corinto operating income of $4 million and depreciation and amortization of $1 million. As of June 30, 2009, Corinto had net debt of $1 million, which is derived from $13 million of total debt, less $5 million for cash and cash equivalents and $7 million of restricted cash.

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


							As of and
							for the
							Six Months
	As of and for the Year						Ended
	Ended December 31,						June 30,
	2006		2007		2008		2009
	(In millions of $, except MW, % and Btu/kWh)

Capacity (MW)		70.5		70.5		70.5		70.5
Capacity factor (%)		89.0		92.7		91.2		94.1
Heat rate (Btu/kWh)		9,152		9,122		9,105		9,097

Pursuant to an agreement with Centrans, we contributed our 50% interest in Corinto and our 100% interest in Tipitapa to Nicaragua Energy Holdings in January 2009. See “History and Development — Recent Developments in 2009” for additional information regarding the transaction.

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. The remaining energy and capacity is sold under medium- and short-term contracts and/or in the local spot market. The plant utilizes bunker fuel pursuant to a long-term fuel supply agreement that expires in 2014 with an option to extend to 2017. In August 2009, Corinto executed an amendment to its long-term fuel supply agreement, effective as of April, 2009. The primary changes include amendments to increase the premium paid per barrel of fuel, the option to extend to 2017 and to provide both parties with a more comprehensive set of remedies in an event of default. From time to time Corinto enters into hedging arrangements to reduce exposure to the volatility of fuel prices.

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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
							Six Months
	For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Availability (%)		90.1		93.3		92.1		94.7
Reliability (%)		97.6		98.3		97.4		99.2
Energy sales (GWh)		536.1		556.1		517.1		247.8

Financing

As of June 30, 2009, Corinto’s outstanding third party indebtedness totalled approximately $9 million.

Management and Governance

Corinto’s affairs and the relationship among the shareholders are regulated by its articles of association and a shareholders agreement. The other stockholder of Corinto is Centrans through its 42.33% interest in Nicaragua Energy Holdings.

The board consist of seven members. We are entitled to appoint four directors and Centrans is entitled to appoint three directors. Some decisions of the board require a simple majority vote of the board members present at a meeting while certain others, including a merger, consolidation, liquidation or sale of substantially all of Corinto’s assets, the incurrence of debt obligations or the issuance of securities of Corinto, require an affirmative vote of all members of the board.

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 January 2009 and we currently own 57.67% of Tipitapa.

For the year ended December 31, 2008, Tipitapa achieved a capacity factor of 92.5%, a heat rate of 9000.5 Btu/kWh, and we recognized operating income of $1 million and depreciation and amortization of less than $1 million. As of June 30, 2009, Tipitapa had operating income of $3 million, depreciation and amortization of less than $1 million and net debt of $(4) million. Tipitapa’s net debt represents its balance of cash and cash equivalents since it had no outstanding third party indebtedness.

Concession and Contractual Agreements

Tipitapa supplies power to Disnorte and Dissur, under long term PPAs, which end in 2014, for 51 MW of capacity and energy. Fuel is supplied under a long-term agreement with Esso Standard Oil S.A. Limited which expires in 2014. From time to time Tipitapa enters into hedging arrangements to reduce exposure to the volatility of the fuel prices.

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Operations

Commercial operations of the plant began in 1999. Tipitapa is currently operated through an operations, maintenance and administrative agreement with our subsidiary, AEI Nicaragua, S.A. The following table sets forth availability and reliability information for the periods indicated:


							For the
							Six Months
	For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Availability (%)		96.0		95.8		96.1		97.0
Reliability (%)		98.4		97.5		98.6		99.1
Energy sales (GWh)		420.2		409.2		393.0		185.2

Financing

As of June 30, 2009, Tipitapa had no outstanding third party indebtedness.

Management and Governance

Tipitapa’s affairs and the relationship among the shareholders are regulated by its articles of association and a shareholders agreement. The other shareholder of Tipitapa is Centrans through its 42.33% interest in Nicaragua Energy Holdings.

The board consists of five members. We are entitled to appoint three directors and Centrans is entitled to appoint two directors. Some decisions of the board require a simple majority vote of the board members present at a meeting while certain others, including a merger, consolidation, liquidation or sale of substantially all of Tipitapa’s assets, the incurrence of debt obligations or the issuance of securities of Tipitapa, require affirmative vote of all members of the board.

Jamaica Private Power Company Ltd. (JPPC)

Overview

In October 2007, we acquired an 84.42% 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-S diesel powered generators that commenced operations in 1998. PPO operates JPPC through an operations and maintenance agreement.

For the year ended December 31, 2008, JPPC achieved a capacity factor of 86.3%, a heat rate of 8201.6 Btu/kWh and had operating income of $5 million and depreciation and amortization of $(1) million. As of June 30, 2009, JPPC had operating income of $4 million, depreciation and amortization of $(1) million and net debt of $2 million which is derived from $18 million of total debt, less cash and cash equivalents of $8 million and restricted cash of $8 million.

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.

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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
							Six Months
	For the Year Ended						Ended
	December 31,						June 30,
	2006		2007		2008		2009

Availability (%)		92.2		90.7		88.9		83.7
Reliability (%)⁽¹⁾		—		—		95.3		98.9
Energy sales (GWh)		460.9		436.3		454.9		224.6


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

Financing

As of June 30, 2009, JPPC had $18 million of third party indebtedness.

Management and Governance

JPPC’s affairs and the relationship among the shareholders are regulated by its articles of association and a shareholders agreement. The other shareholder of JPPC is Inkia Energy.

JPPC does not have a board of directors. Decisions are made directly by the shareholders voting in proportion to their stakes. Certain actions, such as liquidation, bankruptcy and modifications to the organizational documents require the consent of all shareholders.

DHA Cogen Limited (DCL)

Overview

On July 18, 2008, we acquired an approximately 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.

Concession and Contractual Agreements

DCL is party to a water purchase agreement, or WPA, with Cantonment Board Clifton, or CBC, for sale of the plant’s full output of water. The WPA has a 30-year term ending in 2038. The WPA provides for CBC to pay DCL monthly water payments at rates escalating at 5% per year.

DCL was party to a PPA with Karachi Electric Supply Company, or KESC, for the sale of the plant’s full output of power, which KESC terminated on April 23, 2009. DCL has started discussions with KESC with respect to a new PPA.

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.

Operations

The plant entered commercial operations on April 17, 2008. On September 12, 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 an existing defect in the gas turbine that was not disclosed to us at the time we acquired our interest in DCL. Due to the shut down, DCL has not generated revenues and cash inflows to pay vendors which has delayed the repairs. On June 17, 2009, DCL entered into loan agreements to finance repairs to the plant. These repairs have been completed, the plant is operational and we are currently conducting final performance testing.

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Financing

On January 24, 2009, DCL received notice of default from one of its senior lenders. Shortly thereafter, two of DCL’s senior lenders filed claims against DCL and Sacoden, which holds AEI’s interest in DCL, in the courts of Sindh Province, Pakistan seeking repayment by DCL of loans totaling PKR3,704 million (equivalent to approximately $45 million at the exchange rates as of June 30, 2009). The allegations included that DCL had issued shares to AEI following the initial acquisition of DCL in violation of the loan covenants. 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 filed responses to these claims.

As part of the loan agreements to finance repairs to the plant, DCL entered into a Standstill Agreement freezing the lenders’ claims for approximately four months while the plant is being repaired and DCL negotiates a new PPA. If the plant is not timely repaired or DCL is unable to secure a new off-taker for the power from DCL’s plant, DCL will be materially adversely affected and the lenders may exercise their right to take ownership of the plant, in either event with a corresponding negative impact on our financial performance and results of operations.

Management and Governance

We have the right to nominate four of DCL’s seven directors as well as the chief executive officer, who also serves as a director in accordance with Pakistani law. This gives us a majority of five of seven directors on DCL’s board. Pakistan Defence Officers’ Housing Authority, a quasi-governmental entity and DCL’s third-largest shareholder, may appoint one director with a final director appointed by Faisal Bank Limited, one of DCL’s senior lenders and DCL’s second largest shareholder.

Emgasud S.A. (Emgasud)

Overview

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

On November 28, 2008, we acquired 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%. In June 2009, we made a third capital contribution to Emgasud of $15 million which increased our ownership interest in Emgasud to 37%. The acquisition of special noncontrolling rights under Emgasud’s Shareholders’ Agreement remains subject to local anti-trust approvals.

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

Concession and Contractual Agreements

Energía Argentina S.A., or ENARSA, an energy company managed by Argentina, has entered into an agreement with Compañía Administradora del Mercado Mayorista Eléctrico S.A., or CAMMESA, the Argentine power pool administrator, and has ceded effective rights to payments on these contracts to Emgasud. Through its projects, Energía Distribuida I & II, Emgasud has entered into a PPA with ENARSA/CAMMESA for approximately 248 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.

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.

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Operations

Emgasud is currently operating 151 MW at the following locations: 3 MW at Rio Mayo, 2 MW at Gobernador Costa, 20 MW at Pinamar as part of Energía Distribuida I, and 126 MW as part of Energía Distribuida II (42 MW at each of Matheu, Olavarría and Paraná). By the end of 2009, 10 MW are scheduled to come online for Energía Distribuida 1 at Las Armas, and 42 MW are scheduled to come on line for Energía Distribuida II at Concepción. In 2010, 63 MW are scheduled to come on line for Energía Distribuida at Bragado. In total, Emgasud plans to have installed capacity of 266 MW, of which 253 MW are already contracted under PPAs.

Financing

In February 2009, Emgasud issued bonds in an aggregate principal amount of $102 million in Argentina followed by a second issuance of $13 million in April 2009. Proceeds from the bonds were used for various capital expenditures and to repay a $68 million bridge loan entered into in 2008. In August 2009, we purchased a 19% senior unsecured convertible note from Emgasud in an aggregate principal amount of $15 million.

Management and Governance

Emgasud’s affairs and the relationship among its shareholders are regulated by its bylaws and a shareholders agreement. The shareholders of Emgasud are divided into three classes. The board of directors consists of seven members, of which four are appointed by the class A shareholders, two are appointed by us (Class B Shareholders) and one is appointed by the class C shareholders. All decisions of the board require an affirmative majority vote, with certain material decisions (including a merger, consolidation or sale of substantially all of Emgasud’s assets, the incurrence of debt obligations in excess of $1,000,000, the issuance of new equity securities, the approval of the annual operating budget or the appointment of the chief executive officer) requiring the affirmative vote of shareholders representing 80% of the aggregate voting interest present at any shareholders meeting, as the case may be. AEI’s acquisition of special minority rights under Emgasud’s Shareholders’ Agreement are subject to local anti-trust approvals.

Consorcio Eolico Amayo S.A. (Amayo)

Overview

Amayo consists of a 39.9 MW wind power generation facility with 19 2.1 MW Suzlon S88 50HZ wind turbines located approximately 129 kilometers south of Managua, Nicaragua. Commissioning commenced in early 2009 and is ongoing. As part of the transaction that included the merger of AEI’s and Centrans’ interest in their respective power generation assets in Nicaragua, AEI together with Centrans will own a 45% interest in Amayo (currently AEI owns an indirect 12.72% interest in Amayo which will increase to 22.5% subject to the consent of the other shareholder of Amayo).

Concession and Contractual Agreements

Amayo has entered into two 15-year PPAs with Union Fenosa’s local distribution companies, Dissur and Disnorte, for 100% of the energy generated and expire in 2024.

Operations

Amayo has a five-year guarantee and operating and maintenance service agreement with an affiliate of Suzlon which has availability and efficiency guarantees.

Financing

BCIE (Central American Development Bank) provided a $71 million long-term facility to fund a portion of the project construction costs, $60 million of which was outstanding as of June 30, 2009.

Management and Governance

Amayo’s affairs and the relationship among its shareholders are regulated by its articles of incorporation and a shareholders agreement. The shareholders of Amayo are divided into three classes. The board of directors consists of four voting members, of which two are appointed by Arctas Capital Group S.A. and two are appointed by Centrans. All decisions of the board require an affirmative majority vote, except for decisions that have a material

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adverse impact on the economic value of the shares, the ownership percentage or the voting rights of any shareholder (including a merger, consolidation or liquidation of Amayo), which require the affirmative vote of a majority of the shareholders of the class whose rights are affected by such decision.

Jaguar Energy Guatemala LLC (Jaguar)

The Jaguar project consists of the development, construction, operation and maintenance of a 300 MW (approximately 271 MW net capacity) solid fuel-fired power generation facility to be located approximately 24 kilometers from Puerto Quetzal, Guatemala. The project includes two identical 150 MW power blocks and will use circulated fluidized bed, or CFB, boiler technology. Jaguar entered into two 15-year PPAs in 2008 with Union Fenosa’s local distribution companies Distribuidora de Electricidad de Occidente S.A., or DEOCSA, and Distribuidora de Electricidad de Oriente, S.A., or DEORSA, to supply a total of 200 MW of capacity and associated energy. The remaining 75 MW of capacity and associated energy are expected to be sold in the Guatemalan and regional markets on a merchant basis. The project has executed a lump-sum, fixed price, date certain turnkey engineering, procurement and construction contract, or EPC, with China Machine New Energy Corporation, or CMNC. Subject to securing financing and completion of other project milestones, we anticipate commencing construction in the second half of 2009 and commercial operations in the second half of 2012.

Empresa Electrica de Generacion de Chilca S.A. (Fenix)

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

Natural Gas Transportation and Services

Segment Overview

Our 14 businesses in this segment are summarized in the table shown below. Information is as of June 30, 2009.

Natural Gas Transportation and Services

Concession/License

and Contract

Scheduled

% Capacity

Termination

Renewal

Target

Contracted Under

Business

Date

Option

Regulated Return⁽¹⁾

Next Tariff Review

Firm Contract

Promigas

Pipeline⁽²⁾

2026

20 years

12.96%-16.94%

2010 (every 5 years)

92%

Transmetano⁽²⁾

2044

20 years

12.56%-16.56%

2010 (every 5 years)

92%

GBS

2009

N/A

Centragas

2011

N/A

PSI⁽³⁾

N/A

Transoccidente⁽²⁾

N/A

13.04%-17.00%

2010 (every 5 years)

42%

Transoriente⁽²⁾

2045

20 years

13.47%-17.41%

2010 (every 5 years)

30%

Cuiabá

TBS⁽⁴⁾

N/A

GOM

Indefinite

N/A

83%

GOB

2039

N/A

71%

Accroven

N/A

100%

Bolivia-to-Brazil

Pipeline

GTB

2037

N/A

100%

TBG

Indefinite

N/A

100%

Emgasud

N/A

100%


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

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⁽²⁾		Previously approved regulated tariffs have expired. The new methodology for calculation of tariffs is expected to be released in 2009, and the new tariffs are expected to be applied in 2010.
⁽³⁾		PSI provides services related to the drying and compression of natural gas.
⁽⁴⁾		TBS is a natural gas shipper which purchases natural gas in Bolivia and resells it to EPE.

For the year ended December 31, 2008, the Natural Gas Transportation and Services segment accounted for 2% of our net revenues, 16% of operating income and 14% of our Adjusted EBITDA. For the six months ended June 30, 2009, the Natural Gas Transportation and Services segment accounted for 3% of our net revenues, 15% of our operating income and 13% of our Adjusted EBITDA.

Promigas S.A., ESP (Promigas)

Overview of Promigas

Promigas S.A. ESP is a Colombian holding company with investments primarily in the Natural Gas Transportation and Services and Natural Gas Distribution business segments. Promigas is a natural gas transportation and distribution company in Colombia which transported approximately 74% of the natural gas in Colombia in 2008 (directly and through held companies) and with operating assets representing approximately 50% of the total natural gas transportation infrastructure as of December 31, 2008. AEI owns a 52.13% interest in Promigas with the remaining owned by local Colombian investors. Promigas is listed on the Colombian Stock Exchange (Bolsa de Valores de Colombia) under the symbol “PROMIG:CB.” See “— Other Promigas Pipelines”, “— Natural Gas Distribution” and “— Retail Fuel — Promigas” for description of Promigas companies in each of the respective business segments. Our Retail Fuel business was until July 2009 a subsidiary of Promigas at which time it was spun off and is now an indirect subsidiary of AEI.

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 $39 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.

Financing

As of June 30, 2009, Promigas had $987 million of third party debt. Most of Promigas’ financing is denominated in local currency to match its cash flows. In August 2009, Promigas issued debentures in an aggregate principal amount of COP400 billion (approximately $200 million).

In June 2009, Duff & Phelps de Colombia S.A. confirmed Promigas’ upgraded local AAA rating within Colombia.

Management and Governance

Promigas is a publicly traded company in Colombia and follows all applicable Colombian securities regulations. It is managed by a five member Board of Directors. We have the ability to elect three of the five board members as well as members of the Compensation and Audit Committees. The Promigas board receives information and reviews both Promigas and its subsidiaries.

In its subsidiaries, Promigas has the right to elect board members in proportion to its ownership stake. Members of the Promigas executive management team are the Promigas nominated board members in all of the Promigas’ subsidiaries.

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Promigas Transportation Businesses


			Promigas Direct and
			Indirect Ownership %
	Pipeline Length		as of
Company	(Miles)		June 30, 2009

Promigas Pipeline		1,271		100.00	%
Transmetano		93		96.56	%
GBS		196		94.70	%
Centragas		458		25.00	%
Transoccidente		7		68.99	%
Transoriente		98		26.34	%

Promigas Pipeline

The Promigas Pipeline is a 1,271 mile natural gas pipeline which transports natural gas from fields in the region of La Guajira to the Jobo terminal station in the Department of Sucre. The Promigas Pipeline also provides subcontracted pipeline design, construction, operation and maintenance services for government and/or third party owned natural gas transportation customers who own pipelines. In 2008, the Promigas Pipeline recognized revenues of $103 million, operating income of $37 million and depreciation and amortization of $14 million. As of June 30, 2009, the Promigas Pipeline recognized revenues of $51 million, operating income of $18 million and depreciation and amortization of $6 million. As of June 30, 2009, the Promigas Pipeline had net debt of $231 million, which is derived from total debt of $258 million, less $27 million of cash and cash equivalents.

Concession and Contractual Agreements

The Promigas Pipeline operates under a gas transportation concession with the Colombian Ministry of Mines and Energy, or the Colombian MME, which 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, concessions have not been required to operate new pipelines in Colombia.

The transportation tariffs in Colombia are set every five years by the Colombian Regulatory Commission for Energy and Gas (Comisión de Regulación de Energía y Gas), or CREG, based on an approved asset rate base, expected future volumes, expected future capital expenditures, recovery of efficient G&A and O&M expenses, and a regulated return. There are two basic tariffs: a tariff for firm capacity and a tariff for interruptible capacity. 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. The current tariff structure in place minimizes the sensitivity of revenues to volume transported and provides for savings achieved through cost management and efficiency to boost returns (which may be partially lost at the next tariff review).

The tariff for the Promigas Pipeline was last set in 2002 and the current tariff has expired. The new methodology for calculation of tariffs is expected to be released at the end of 2009, and the new tariffs are expected to be applied in 2010. The Promigas Pipeline is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for USD-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the renumeration of G&A and O&M), according to the methodology established by CREG.

Customer Base

As of June 30, 2009, the Promigas Pipeline had 14 customers, the largest of which was Generadora y Comercializadora de Energía S.A., a leading power generation and commercialization company in Colombia which represents approximately 26% of the Promigas Pipeline’s 2008 revenues. Other customers include large industrials such as thermoelectric plants, local distribution companies, cement companies, petrochemical firms and mining operations. Approximately 41% of the Promigas Pipeline’s transported volumes as of December 31, 2008 were for Power Generation, 10% for retail distribution, 6% for Gazel and the remaining 43% for industrial customers.

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Operations

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


							As of and
							for the
							Six Months
	As of and for the Year						Ended
	Ended December 31,						June 30,
	2006		2007		2008		2009

Volume transported (mmcfd)		328		304		294		287
Maximum capacity (mmcfd)		475		475		535		535
Customers		12		12		13		14

The Promigas Pipeline has historically experienced strong operating performance and capacity utilization close to its maximum transportation capacity of 535 mmcfd. 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 321 employees as of June 30, 2009, eight 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 with a capacity of 73 mmcfd. Promigas directly and indirectly owns 96.56% of Transmetano. Transmetano has independent administration and operations from Promigas. In 2008, Transmetano recognized revenues of $16 million, operating income of $9 million, depreciation and amortization of $2 million. As of June 30, 2009, Transmetano recognized revenues of $8 million, operating income of $5 million and depreciation and amortization of $1 million. As of June 30, 2009, Transmetano had net debt of $2 million, which was derived from total debt of $6 million, less $4 million of cash and cash equivalents.

Transmetano operates under a gas transportation concession with the Colombian MME which expires in September 2044. The Colombian government has the option to buy the assets at a to-be-determined fair value price in 2043. Otherwise, the concession contemplates extensions in 20-year increments. Since 1994, a concession has no longer been required to operate new pipelines in Colombia.

Determination of Transmetano’s regulated tariff occurs in the same fashion as was described for the Promigas Pipeline. The tariff for Transmetano was last set in 2001 and the current tariff has expired. The new methodology for calculation of tariffs is expected to be released at the end of 2009, and the new tariffs are expected to be applied in 2010. Transmetano is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for USD-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the renumeration of G&A and O&M) according to the methodology established by the regulator.

Ecopetrol S.A., or Ecopetrol, the Colombian state-controlled petroleum company, is currently Transmetano’s sole customer under a Transportation Contract which expires in 2012. At the end of the term, Ecopetrol has an option to renew the contract for 10 successive one-year terms. Independent of volumes transported, Ecopetrol pays a tariff established by the contract. If the tariff to be approved by CREG differs from the one in Ecopetrol’s contract, Transmetano will assume any discount, as applicable. As of June 30, 2009, Transmetano had 36 employees, none of whom were unionized.

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 directly and indirectly owns 94.70% of GBS. In 2008, GBS recognized revenues of $8 million, operating income of $7 million and depreciation and amortization of less than $1 million. As of June 30, 2009, GBS recognized revenues of $4 million, operating income of $3 million and depreciation and amortization of less than

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$1 million. As of June 30, 2009, GBS had net debt of $(3) million, which was comprised of $3 million of cash and cash equivalents.

GBS operates under a build, operate, maintain and transfer, or 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.

Under the terms of the BOMT agreement, GBS is paid by TGI 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.

As of June 30, 2009, GBS had eight employees, none of whom were unionized.

Promigas — Centragas (Centragas)

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

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

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

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.

As of June 30, 2009, Centragas had 22 employees, none of whom were unionized.

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 directly and indirectly owns 96.79% of PSI. In 2008, PSI recognized revenues of $5 million, operating income of $2 million and depreciation and amortization of $1 million. As of June 30, 2009, PSI recognized revenues of $4 million, operating income of $2 million and depreciation and amortization of less than $1 million. As of June 30, 2009, PSI had net debt of $(2) million, which was comprised of $2 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 with Chevron Texaco expires on December 31, 2011. The compression contract expired on December 31, 2008 and was renegotiated to include the compression in series service, which has the objective of maximizing the recovery of the local reserves of its customer. This contract expires on December 31, 2013. In addition, PSI has also renewed a backup compression contract with Chevron Texaco which expires December 31, 2013.

As of December 31, 2008, PSI dehydrated an average of 268 mmcfd of natural gas and compressed natural gas. As of June 30, 2009, PSI had 13 employees, none of whom were unionized.

Promigas — Transoccidente S.A. ESP (Transoccidente)

Transoccidente operates a seven mile pipeline in the Cauca Valley in Colombia with capacity of 69 mmcfd. Promigas currently directly and indirectly owns 68.99% of Transoccidente. In 2008, Transoccidente recognized revenues of $2 million, operating income of $1 million and depreciation and amortization of less than $1 million. As of June 30, 2009, Transoccidente recognized revenues of $1 million and operating income and depreciation and amortization of less than $1 million, respectively. As of June 30, 2009, Transoccidente had net debt of less than $(1) million, which was comprised entirely of less than $1 million of cash and cash equivalents.

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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.

Determination of Transoccidente’s regulated tariff occurs in the same fashion as was described for the Promigas Pipeline. The tariff for Transoccidente was last set in 2004 and the current tariff will expire in 2009. The new methodology for calculation of tariffs is expected to be released at the end of 2009, and the new tariffs are expected to be applied in 2010. Transoccidente is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for USD-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the renumeration of G&A and O&M) according to the methodology established by the regulator.

Transoccidente’s customers are Gases de Occidente, an LDC owned 70.1% 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.

As of June 30, 2009, Transoccidente had three employees, none of whom were unionized.

Promigas — Transoriente S.A. ESP (Transoriente)

Transoriente operates a 98 mile pipeline in Bucaramanga, Colombia with a capacity of 50 mmcfd. Promigas currently directly and indirectly owns 26.34% 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.

Determination of Transoriente’s regulated tariff occurs in the same fashion as was described for the Promigas Pipeline. The tariff for Transoriente was last set in 2001 and the current tariff has expired. The new methodology for calculation of tariffs is expected to be released at the end of 2009, and the new tariffs are expected to be applied in 2010. Transoriente is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for USD-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the renumeration of G&A and O&M) according to the methodology established by 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 June 30, 2009, Transoriente had 16 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 2008, GOM and GOB recognized revenues from TBS of $22 million and $20 million, respectively. No gas has been transported since EPE has not operated since August 2007.

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 2008, TBS recognized revenues of $57 million from

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sales to EPE, which was eliminated in consolidation. 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.

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 was a 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).”

Operations

Both GOB and GOM sub-contract the operations and maintenance of their pipelines to third parties. 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 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 as of and for the periods indicated:


							As of and
							for the
							Six Months
	As of and for the Year Ended December 31,						Ended June 30,
	2006		2007		2008		2009
	(In millions of $, except mmcfd and %)

GOM
Average throughput (mmcfd)		20.6		20.1		1.44		0.16
Maximum capacity (mmcfd)		120		120		120		120
Operating income	$	14	$	15	$	17	$	1
Depreciation and amortization	$	4	$	3	$	3	$	1
Net debt⁽¹⁾⁽²⁾	$	25	$	15	$	7	$	8
GOB
Average throughput (mmcfd)		21.73		21.05		2.28		0.89
Maximum capacity (mmcfd)		141		141		141		141
Operating income	$	11	$	13	$	14	$	6
Depreciation and amortization	$	3	$	2	$	2	$	1
Net debt⁽¹⁾⁽²⁾	$	36	$	32	$	28	$	29


(1)		Attributable to notes owed to shareholder affiliates.
(2)		See “Non-GAAP Financial Measures” and “Selected Consolidated Financial Data.”

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	26		$	23		$	23		$	23
Less
Cash and cash equivalents		(1	)		(8	)		(16	)		(15	)
Current restricted cash		—			—			—			—
Non-current restricted cash		—			—			—			—

Net debt	$	25		$	15		$	7		$	8

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


										As of
	As of December 31,									June 30,
	2006			2007			2008			2009
	(In millions of $)

Total debt	$	37		$	33		$	31		$	31
Less
Cash and cash equivalents		(1	)		(1	)		(3	)		(2	)
Current restricted cash		—			—			—			—
Non-current restricted cash		—			—			—			—

Net debt	$	36		$	32		$	28		$	29

Financing

The Cuiabá Integrated Project does not have any third-party financing. However, GOM and GOB have aggregate debt outstanding of $55 million and $36 million, respectively, from affiliates of AEI as of June 30, 2009. In addition, GOM and GOB have aggregate debt outstanding of $23 million and $31 million, respectively, provided by a third party shareholder as of June 30, 2009. 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 2008 and for the six months ended June 30, 2009, we recognized equity earnings of $17 million and $10 million, respectively, from Accroven.

Currently, PDVSA Gas payments are delayed and such delays constitute an event of default under certain of Accroven’s finance agreements. To date Accroven has not been notified by its lenders of the acceleration of its obligations under its financing agreements. The amount owed by PDVSA Gas is approximately $51 million as of June 30, 2009. This delay in payment has resulted in PDVSA being in default under its service agreements with Accroven. Accroven is entitled to enforce its rights under those agreements, which include terminating the agreements but is currently trying to resolve the situation through other means. Negotiations to resolve this situation are ongoing.

In September 2009, we signed a non-binding Letter of Intent with PDVSA Gas pursuant to which we agreed to sell our interest in Accroven to PDVSA Gas. Closing of this transaction is subject to negotiation of definitive documentation and receipt of third party consents.

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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 were 96% and 4%, respectively, as of December 31, 2008.

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


							As of and
							for the
							Six Months
	For the Year Ended December 31,						Ended June 30,
	2006		2007		2008		2009
	(In millions of $, except mmcfd and %)

Average throughput (mmcfd)		773		763		759		784
Maximum capacity (mmcfd)		800		800		800		800

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 as of and for the dates indicated:


										As of and
										for the
	For the Year Ended									Six Months
	December 31,									Ended June 30,
	2006			2007			2008			2009

Average throughput (mmcfd)		905			987			1,077			950
Capacity factor (%)⁽¹⁾		100	%		100	%		100	%		100	%


(1)		Capacity factor refers to contracted capacity.

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 was flowing at approximately 98% of capacity in 2008.

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

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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. 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.

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 but at the current time we do not have any management or control over GTB.

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 directly own 4.00% (4.21% including indirect interests through other shareholders), Shell owns 4.00%, Transredes owns 12.00%, Petrobras indirectly owns 51% and a consortium of non-Bolivian companies own 29%. AEI, Shell and Transredes are collectively called the Bolt Group. Under the TBG shareholder agreement, the Bolt Group shareholders 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, 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.

Emgasud S.A. (Emgasud)

Emgasud currently transports natural gas through pipelines running primarily through Argentina’s Patagonia region. Since 2007, Emgasud has been transporting gas through the Patagonian Pipeline, which has a maximum capacity of approximately 26.1 mmcfd and runs 354 miles from the gas field in Cerro Dragon, Province of Chubut to the delivery point in the city of Esquel. Emgasud 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 24.6 mmcfd of natural gas firm capacity with Camuzzi Gas del Sur S.A. until 2027. Emgasud has also been assigned transportation capacity of approximately 5.8 mmcfd through the TGS system through the San Martin Pipeline 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. In 2008, Emgasud had natural gas transportation volume of 12.4 mmcfd, mainly to residential customers and a power generation plant.

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Natural Gas Distribution

Segment Overview

Our seven businesses in this segment are summarized in the table shown below. Information is as of June 30, 2009.


Natural Gas Distribution
	Concession/License
	and Contract
	Scheduled
	Termination	Renewal	Target
Business	Date	Option	Regulated Return⁽¹⁾	Next Tariff Review

Promigas
Surtigas⁽²⁾	2034	20 years	16.06%	2009 (every 5 years)
Gases de Occidente⁽²⁾⁽³⁾	2014-2047	20 years	16.06%	2009 (every 5 years)
Gases del Caribe⁽²⁾⁽⁴⁾	2028	20 years	16.06%	2009 (every 5 years)
Emgasud	2027	N/A	N/A	Undefined
Cálidda⁽⁵⁾	2033	30 years	12.00%	2009-2010 (every 2-4 years)
BMG⁽⁶⁾	2038-2058 (varies by franchise)	30 years	N/A	Annually
Tongda⁽⁷⁾	2038-2058 (varies by franchise)	30 years	N/A	Annually


⁽¹⁾		Inflation adjusted on regulated asset base before tax except for Cálidda’s return which is after tax.
⁽²⁾		Tariffs will expire in 2009. The new tariff methodology for calculation of tariffs is expected to be released in 2010, and new tariffs are expected to be applied in 2011.
⁽³⁾		Gases de Occidente has an exclusive concession which expires in 2014 and a non-exclusive concession which expires in 2047.
⁽⁴⁾		Includes its consolidated subsidiaries, Gases de la Guajira, Gases del Quinido, Gases del Risaralda and Gas Natural del Centro.
⁽⁵⁾		Cálidda’s main grid tariff review occurs every two years and is expected in 2010. The other grid tariff review occurs every four years and is expected to occur in 2009.
⁽⁶⁾		Includes BMG and its subsidiaries. See “— Beijing MacroLink Gas Co., Ltd. (BMG).”
⁽⁷⁾		Includes Tongda and its subsidiaries. See “— Tongda Energy Private Limited (Tongda).”

For the year ended December 31, 2008, the Natural Gas Distribution segment accounted for 6% of our net revenues, 13% of our operating income and 12% of our Adjusted EBITDA. For the six months ended June 30, 2009, the Natural Gas Distribution segment accounted for 8% of our net revenues, 16% of our operating income and 14% of our Adjusted EBITDA.

Growth of Our Natural Gas Distribution Business

We are developing and expanding our gas distribution segment in Peru and China through our Cálidda, Tongda and BMG businesses. All three companies and their subsidiaries service markets with low penetration rates and significant growth potential.

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

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

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Promigas

Promigas is a Colombian holding company with investments primarily in our Natural Gas Transportation Services, Natural Gas Distribution and Retail Fuel business segments. See “— Natural Gas Transportation and Services — Promigas S.A., ESP (Promigas)” and “— Retail Fuel — Promigas.”

Promigas through the Promigas Pipeline directly serves certain customers and owns interests in three of our businesses providing natural gas distribution services to over 2 million customers throughout Colombia, representing 42% of that country’s total market as of December 31, 2008. 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 ancillary non-bank financing to customers with good payment records to finance items, such as appliances, household items, CNG car conversions and materials for construction. The financing is provided directly by each company as part of its non-regulated business. In the case of Gases del Caribe, Promigas provides the financing and Gases del Caribe receives a fee. Total non-bank financing loans receivable as of June 30, 2009 are $78 million. 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 2008, Surtigas’ network covered 85% of its service area and connected 91% of its connectable households and businesses to natural gas services. Promigas currently owns 99.90% of Surtigas. In 2008, Surtigas recognized revenues of $125 million, operating income of $29 million, depreciation and amortization of $3 million. As of June 30, 2009, Surtigas recognized revenues of $60 million, operating income of $16 million and depreciation and amortization of $1 million. As of June 30, 2009, Surtigas had net debt of $85 million, which is derived from total debt of $88 million, less $3 of cash and cash equivalents.

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


										As of and
										for the
	As of and for the Year Ended									Six Months
	December 31,									Ended June 30,
	2006			2007			2008			2009

Customers (thousands)		404			427			449			460
Annual growth		8	%		6	%		5	%		N/A
Volume transported (Bcf)		11.6			10.5			11.4			6.2
Network penetration⁽¹⁾		95	%		83	%		85	%		86	%
Percent connected⁽²⁾		86	%		89	%		91	%		92	%


(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 gas distribution concession with the Colombian MME which expires in September 2034 and has a 20 year renewal option. Since 1994, a concession has no longer been required to distribute natural gas in Colombia.

The distribution tariffs in Colombia are set every five years by the CREG based on an approved asset rate base, expected future volumes, expected future capital expenditures, recovery of efficient G&A and O&M expenses, and a regulated return. There tariff has four basic components: fuel cost, transportation, distribution and commercialization fee. Fuel and transportation costs are pass-through components and are set by regulators independently of the tariff reviews. The distribution and commercialization tariffs are denominated in Colombian pesos.

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The tariff for Surtigas was last set in 2004 and will expire in 2009. Surtigas is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for USD-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by the regulator.

Natural gas distribution companies in Colombia are obligated to contract 100% of the volume for the regulated natural gas distribution market. Most of Surtigas’ natural gas supply comes from the Guajira field (the price of natural gas from this field has a cap that is pegged to oil prices with a six month lag). During 2009, gas supply contracts have been on average 90% fixed and 10% variable with terms from one to two years.

Customer Base

Surtigas had approximately 460,000 customers as of June 30, 2009. As of December 31, 2008, Surtigas transported 11.4 billion cubic feet of natural gas to approximately 449,000 customers with volumes distributed as follows: 31% residential, 65% industrial, and 4% commercial.

Operations

Surtigas had no service interruption between 2004 and June 30, 2009.

Surtigas has certifications under ISO 9001 and NTC ISO/IEC 17025. As of June 30, 2009, Surtigas had 363 employees.

Financing

As of June 30, 2009, Surtigas had outstanding debt of $88 million.

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

Overview

Gases de Occidente is a natural gas distribution company serving 27 towns in the area of Valle del Cauca and in Cauca, located on Colombia’s west coast. As of 2008, Gases de Occidente’s network covered 99% of the potential market and connected 72% of its connectable households and businesses to natural gas services. Promigas currently directly and indirectly owns 90.10% of Gases de Occidente. In 2008, Gases de Occidente recognized revenues of $196 million, operating income of $45 million, depreciation and amortization of $3 million. As of June 30, 2009, Gases de Occidente recognized revenues of $103 million, operating income of $29 million and depreciation and amortization of less than $2 million. As of June 30, 2009 Gases de Occidente, had net debt of $70 million, which is derived from $71 million of total debt, less $1 million of cash and cash equivalents.

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


										As of and
										for the
	As of and for the Year Ended									Six Months
	December 31,									Ended June 30,
	2006			2007			2008			2009

Customers (thousands)		521			573			619			640
Annual growth		12	%		10	%		8	%		N/A
Volume transported (Bcf)		15.0			17.0			17.6			9.1
Network penetration⁽¹⁾		97	%		94	%		99	%		N/A
Percent connected⁽²⁾		67	%		70	%		72	%		74	%


(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 gas distribution concession with the Colombian MME which expires in September 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 distribute natural gas in Colombia.

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Determination of Gases de Occidente’s regulated tariff occurs in the same fashion as was described for Surtigas. The tariff for Gases de Occidente was last set in 2004 and will expire in 2009. Gases de Occidente is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for USD-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by the regulator.

Natural gas distribution companies in Colombia are obligated to contract 100% of the volume for the regulated natural gas distribution market. Most of Gases de Occidente’s natural gas supply comes from the Cusiana field (the price of natural gas from this field is not capped). During 2009, gas supply contracts have been on average 82% fixed and 18% variable with terms from one to two years.

Customer Base

Gases de Occidente had approximately 640,000 customers as of June 30, 2009. As of December 31, 2008, Gases de Occidente transported 17.6 billion cubic feet of natural gas to 619,000 customers, and volumes were allocated as follows: 73% industrial, 20% residential, and 7% commercial.

Operations

Gases de Occidente had 364 hours of service interruption in 2006, 290 hours in 2007 and 105 in 2008.

Gases de Occidente has certifications under ISO 9001. As of June 30, 2009, Gases de Occidente had 380 direct employees.

Financing

As of June 30, 2009, Gases de Occidente had outstanding debt of $71 million. In July 2009, Gases de Occidente issued debentures in an aggregate principal amount of COP150 billion (approximately $75 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 directly serving 38 municipalities in the departments of Magdalena, Cesar and Atlántico, located on Colombia’s north coast and indirectly serving 35 municipalities in the departments of La Guajira, Quindio, Risaralda, and Caldas. As of December 31, 2008, Gases del Caribe’s network covered 96% of the potential market and connected 82% of its connectable households and businesses to natural gas service. Promigas owns 30.99% of Gases del Caribe.

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


										As of and
										for the
	As of and for the Year Ended									Six Months
	December 31,									Ended June 30,
	2006			2007			2008			2009

Customers (thousands)⁽¹⁾		794			858			921			949
Annual growth		8	%		8	%		7	%		N/A
Volume transported (Bcf)⁽¹⁾		35.7			40.4			39			18.9
Network penetration⁽²⁾		94	%		95	%		96	%		96	%
Percent connected⁽³⁾		81	%		79	%		82	%		83	%


(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 a gas distribution concession with the Colombian MME which expires in September 2028. Since 1994, a concession has no longer been required to distribute natural gas in Colombia.

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Determination of Gases del Caribe’s regulated tariff occurs in the same fashion as was described for Surtigas. Similarly the tariff for Gases del Caribe was last set in 2004 and will expire in 2009. The new methodology for calculation of tariffs is expected to be released in 2010, and new tariffs are expected to be applied in 2011. Gases del Caribe is currently charging the tariff previously approved, as adjusted annually for the U.S. Producer Price Index (for USD-denominated revenues from the fixed and variable charges) and the Colombian Consumer Price Index (for the Colombian peso-denominated revenues from the remuneration of G&A and O&M), according to the methodology established by the regulator.

Natural gas distribution companies in Colombia are obligated to contract 100% of the volume for the regulated natural gas distribution market. Most of Gases del Caribe’s natural gas supply comes from the Guajira field (the price of natural gas from this field has a cap that is pegged to oil prices with a six month lag). During 2009, gas supply contracts have been around 95% fixed 5% variable with terms from one to two years.

Customer Base

As of June 30, 2009, Gases del Caribe served approximately 949,000 customers. As of December 31, 2008, approximately 39 billion cubic feet of natural gas were delivered to approximately 921,000 customers, and volumes were allocated as follows: 84% industrial, 14% residential, and 2% commercial.

Operations

Gases del Caribe had 46.45 hours of service interruption in 2006, 33.03 hours in 2007 and 22.27 hours in 2008.

Gases del Caribe has certifications under ISO 9001 and NTC ISO/IEC 17025. As of June 30, 2009, Gases del Caribe had 697 employees of which 33 employees were unionized.

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

Overview

Cálidda is a Peruvian natural gas distribution company that owns the concession to operate in the Department of Lima and the province of Callao. 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 2008, Cálidda had average throughput of 157 mmcfd and maximum capacity of 225 mmcfd. We recognized from Cálidda in 2008 operating income of $11 million and depreciation and amortization of $6 million. As of June 30, 2009, Cálidda recognized revenues of $50 million, operating income of $8 million and depreciation and amortization of $3 million. As of June 30, 2009, Cálidda had net debt of $19 million, which is derived from total debt of $43 million, less than $18 million of cash and cash equivalents and less than $6 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 2000 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. In 2008, Cálidda had already met these obligations.

Cálidda’s concession covers a main grid, serving eleven large initial customers, and a secondary grid serving the rest of the concession area. On its secondary grid, Cálidda receives a regulated tariff based on its rate base. The distribution tariffs are set every four years by OSINERGMIN based on an approved asset rate base, expected future volumes, recovery of efficient general and administrative and operations and maintenance expenses and a regulated return. The tariff has four basic components: fuel cost, transportation, distribution and commercialization fee. Fuel and transportation costs are pass-through components and are set by regulators independently of the tariff reviews. Additionally Cálidda also receives a guaranteed return on its main grid that is separate from the distribution tariffs and which was also set at the time of the concession.

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The tariff for the secondary grid was last set in 2004 and is in the process of an extraordinary review in order to accommodate new investment which is expected by the end of 2009. We cannot predict the outcome of this tariff review at this time.

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 adjust Cálidda’s future demand requirements and also to synchronize the supply and transportation contracts has been proposed by Cálidda to the Camisea Consortium (this amendment is still pending). Regarding the transmission contract, in August 2008 Cálidda increased the firm and interruptible transportation capacity with Transportadora de Gas del Perú S.A. through June 2012 and August 2033, respectively.

Customer Base

Cálidda’s customers fall into two categories: non-regulated customers (users that consume more than 1 mmcfd) and regulated customers (mainly residential, commercial users and small industries). As of June 30, 2009, Cálidda had approximately 14,000 customers and had a capacity to connect approximately 86,000 customers. Of the 57 billion cubic feet that Cálidda actually delivered as of December 31, 2008, 48% was for power generation, 42% was for the industrial sector, 10% was for NGV and the remaining went to residential and commercial customers.

Operations

As of June 30, 2009, Cálidda constructed, operated and maintained 466 miles of pipelines which consisted of a 20-inch main pipeline and sixteen to 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 June 30, 2009, approximately 73% of its residential customers have utilized this financing.

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

As of June 30, 2009, Cálidda had 186 employees.

Financing

As of June 30, 2009, Cálidda had outstanding debt of $43 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, through its various subsidiaries, 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 15 city gas companies and a minority interest in a long distance pipeline and serves a total of approximately 135,000 connected users out of a total of approximately 1.2 million connectable users as of June 30, 2009. In 2008, we recognized from BMG revenues of $32 million, operating income of $(1) million and depreciation and amortization of $4 million. As of June 30, 2009, BMG recognized revenues of $21 million, operating income of $4 million and depreciation and amortization of $2 million. As of June 30, 2009, BMG had net debt of $2 million, which was derived from total debt of $12 million, less $10 million of cash and cash equivalents.

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BMG Businesses


			AEI
			Ownership
			% as of June 30,
Business	Full Legal Name	Province	2009⁽¹⁾

Chenzhoushi	Chenzhoushi MacroLink Gas Co. Ltd.	Hunan		70.00	%
Fuzhou	Fuzhou MacroLink Gas Co. Ltd.	Jiangxi		70.00	%
Geermu	Geermu MacroLink Gas Co. Ltd.	Qinghai		70.00	%
Huangzhong	Huangzhongxian MacroLink Gas Co. Ltd.	Qinghai		56.00	%
Hunan Huayou⁽²⁾	Hunan Huayou Natural Gas Transmission and Distribution Co. Ltd.	Hunan		16.42	%
Jishou	Jishou MacroLink Gas Co. Ltd.	Hunan		70.00	%
Nanxian	Nanxian MacroLink Gas Co. Ltd.	Hunan		35.70	%
Leduxian	Leduxian MacroLink Gas Co. Ltd.	Qinghai		49.00	%
Liaoyuan	Liaoyuan MacroLink Gas Co. Ltd.	Jilin		70.00	%
Lishui	Lishui MacroLink Gas Co. Ltd.	Zhejiang		52.50	%
Loudi	Loudi MacroLink Gas Co. Ltd.	Hunan		56.00	%
Qianan	Qianan MacroLink Gas Co. Ltd.	Heibei		70.00	%
Wangcheng	Wangchengxian MacroLink Gas Co. Ltd.	Hunan		70.00	%
Wuyi	Wuyi MacroLink Gas Co. Ltd.	Zhejiang		70.00	%
YingKou	YingKou MacroLink Gas Co. Ltd.	Liaoning		70.00	%
Yueqing	Yueqing MacroLink Gas Co. Ltd.	Zhejiang		70.00	%


⁽¹⁾		Represents AEI’s net interest via direct and indirect ownerships.
⁽²⁾		Hunan Huayou is a pipeline company.

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

As of December 31, 2008, BMG distributed approximately 4,200 mmcf of gas to 117,000 customers, 86% of which went to industrial and commercial customers and 14% to residential customers. For the six months ended June 30, 2009, BMG has connected an average of approximately 3,036 customers per month and had approximately 135,000 customers, some of which are large industrial and commercial clients that have either recently started operations in the new industrial parks or are in the process of totally or partially switching from other energy sources to natural gas because of environmental and cost reasons. In addition to these connected customers, BMG is currently in the process of expanding its supply of piped gas to the largest industrial park in Huangzhong, Qinghai Province where several large basic industry clients (industries like zinc, aluminum, nickel and fertilizers) are now building their facilities.

Operations

The BMG companies secure the supply of natural gas from various sources, including domestic gas fields (by way of compressed or liquified gas trucks or long distance pipelines) or domestic coal gas. Some BMG companies distribute re-gasified LPG supplied from domestic LPG stations shipped via trucks.

Financing

Generally, BMG’s subsidiaries obtain financing individually at the local level. However, in most cases, BMG is required to provide corporate guarantees to the subsidiaries’ lenders. From time to time, BMG also extends shareholder loans to its subsidiaries.

Management and Governance

BMG’s affairs and the relationship among its shareholders are regulated by its articles of association and a joint venture agreement. BMG’s other shareholder is MacroLink Holdings Co. Ltd., a Chinese private enterprise, which owns the remaining 30%.

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The board of directors consists of six members appointed by the shareholders. We appoint four of the six directors. Certain decisions of the board require unanimous affirmative votes, certain decisions, including any transaction involving the sale of any assets or equity with a sale price of greater than 10% of BMG’s total shareholders’ equity or the borrowing by BMG of any indebtedness which would cause BMG’s aggregate indebtedness to exceed 50% of its total assets, require the affirmative votes of 80% of the directors, while others such as amendments to BMG’s articles or a reorganization of BMG, require only simple majority of affirmative votes. We also have the right to nominate the Executive Deputy General Manager of the Company.

Tongda Energy Private Limited (Tongda)

Overview

In August 2007, we acquired a 100% equity interest in Tongda. Tongda, through 14 operating subsidiaries, 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 10 city gas companies, servicing a total of approximately 151,000 connected users out of a total of approximately 657,000 connectable users as of June 30, 2009. Tongda also has interests in two operating companies which operate auto-filling stations and two pipeline operating companies. Tongda is in the process of obtaining certain approvals to build an 98-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 2008, we recognized from Tongda revenues of $42 million, operating income of $1 million, and depreciation and amortization of $3 million. As of June 30, 2009, Tongda recognized revenues of $21 million, operating loss of less than $1 million and depreciation and amortization of $2 million. As of June 30, 2009, Tongda had net debt of $(8) million, which was derived from total debt of $8 million, less $16 million of cash and cash equivalents.

Tongda Businesses


			AEI
			Ownership
			% as of June 30,
Business	Full Legal Name	Province	2009⁽¹⁾

Hangzhou Lvneng⁽²⁾	Hangzhou Lvneng Gas Development and Application Co., Ltd.	Zhejiang		70.00	%
Ji’an	Ji’an Natural Gas Co., Ltd.	Jiangxi		70.00	%
Ji-an County	Tongda Energy (Ji-an County) Limited	Jiangxi		91.00	%
Jiangsu Datong⁽³⁾	Jiangsu Datong Piped Natural Gas Co., Ltd.	Jiangsu		100.00	%
Jiangyan	Jiangyan Natural Gas Co., Ltd.	Jiangsu		100.00	%
Laizhou	Laizhou City Pipeline Gas Co., Ltd.	Jiangsu		100.00	%
Shuyang	Shuyang Tongda Natural Gas Co., Ltd.	Jiangsu		100.00	%
Taizhou⁽³⁾	Taizhou Tongda Natural Gas Co., Ltd.	Jiangsu		100.00	%
Tongda Dafeng	Tongda Dafeng Natural Gas Co., Ltd.	Jiangsu		100.00	%
Hangzhou Tongneng⁽²⁾	Hangzhou Tongneng Investment and Management Co., Ltd.	Zhejiang		100.00	%
Longchuan	Longchuan County Pipeline Gas Co., Ltd.	Guangdong		94.00	%
Yangjiang	Yangjiang City Tongneng Natural Gas Co., Ltd.	Guangdong		100.00	%
Yucheng	Yucheng City Pipeline Gas Co., Ltd.	Shandong		100.00	%
Yuyao	Yuyao City Natural Gas Co., Ltd.	Zhejiang		60.00	%


⁽¹⁾		Represents AEI’s net interest via direct and indirect ownerships.
⁽²⁾		Business has stations only.
⁽³⁾		Business has long distance pipelines.

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

As of December 31, 2008, Tongda distributed 2,075 mmcf of gas, to approximately 136,000 customers, 79% of which went to industrial and commercial customers and 21% to residential customers. For the six months

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ended June 30, 2009, we had connected an average of approximately 2,420 customers per month and as of that date had approximately 151,000 customers. We are currently in the process of expanding our throughput capacity and metering stations to several large industrial clients that are in the process of expanding their production/manufacturing facilities and that have requested additional gas volume for their processes. Also, in our Jiangyan franchise in Jiangsu Province, we finalized negotiations to connect and deliver gas to one of the largest state-owned developers currently constructing one of only seven large-scale state-sponsored resort/recreational centers in all of China.

Operations

Tongda secures the supply of natural gas from various sources, including domestic gas fields by way of compressed or liquified gas trucks or long distance pipelines. One company receives 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.

Emgasud S.A. (Emgasud)

Emgasud participates in the gas distribution segment with 482 miles in distribution lines and an annual dispatch of 2.9 billion cubic feet servicing approximately 24,000 customers in various areas in the Province of Buenos Aires as of December 31, 2008. Customers increased to approximately 25,000 as of June 30, 2009. Additionally, Emgasud has a business unit which specializes in the construction of gas distribution networks and high-pressure gas pipelines. Emgasud has a gas distribution license through 2027.

Retail Fuel

Segment Overview

The businesses in this segment are listed in the table below. Information is as of June 30, 2009, unless otherwise indicated. Retail fuel is a non-core business for us and we are evaluating strategic alternatives for this business.

Retail Fuel

AEI Ownership

Approximate

Interest (Direct

Operating

Product

2008

Number of

Business

Country

and Indirect)

Control⁽¹⁾

Sold

Volume Sold

Employees

SIE – Gazel

Colombia, Chile, Mexico, Peru

24.96

Yes

Compressed
Natural Gas

12,119 million
cubic feet

665

SIE – Terpel

Colombia, Ecuador, Panama, Chile

24.96

Yes

Gasoline,
Diesel, Jet
Fuel,
Lubricants

1,660 million
gallons

3,210

3,875


(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.

For the year ended December 31, 2008, the Retail Fuel segment accounted for 56% of our net revenues, 27% of our operating income and 20% of our Adjusted EBITDA. For the six months ended June 30, 2009, the Retail Fuel segment accounted for 52% of our net revenues, 16% of our operating income and 16% of our Adjusted EBITDA.

Sociedad de Inversiones en Energía (SIE)

Overview

Our Retail Fuel business was until July 2009 a subsidiary of Promigas at which time it was spun off and is now an indirect subsidiary of AEI.

SIE operates through two businesses, Organización Terpel S.A. and Gas Natural Comprimido S.A., which cover the Terpel and Gazel business lines, respectively. This business has 1,826 owned or affiliated service stations (1,597 gasoline and 229 CNG) as of June 30, 2009. As of December 31, 2008, Terpel had a market share by volume

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of 38% for gasoline, 12% for lubricants and 51% for aviation fuel in Colombia. Gazel had a 37% market share by volume in the CNG business.

We indirectly own 28.13% of SIE, which owns 87.73% of Terpel which in turn owns 100% of Gazel. In 2008, SIE recognized revenues of $5 billion, operating income of $116 million and depreciation and amortization of $46 million. As of June 30, 2009, SIE recognized revenues of $2 billion, operating income of $47 million and depreciation and amortization of $17 million. As of June 30, 2009, SIE had net debt of $404 million, which is derived from total debt of $470 million, less $66 million of cash and cash equivalents.

Organización Terpel Inversiones S.A. (Terpel)

Terpel’s main business units are wholesale, retail, aviation gasoline distribution and lubricant sales.

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


							As of and
							for the
	As of and for the Year Ended						Six Months
	December 31,						Ended June 30,
	2006		2007		2008		2009

Number of owned stations		160		418		386		377
Number of affiliate stations		1,119		1,178		1,224		1,220
Gallons of sales per day
Wholesale		2,749,854		2,698,455		3,316,485		3,428,861
Retail		418,232		422,096		788,452		773,961
Aviation		166,536		336,114		430,581		445,267
Lubricants		15,569		13,222		13,838		15,067
Fuel margin per gallon ($)
Wholesale	$	0.09	$	0.13	$	0.14	$	0.14
Retail	$	0.13	$	0.22	$	0.38	$	0.37
Aviation	$	0.24	$	0.29	$	0.18	$	0.09
Lubricants	$	2.58	$	3.53	$	3.64	$	2.75

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. Since 2003, Terpel has been able to increase its market share in gasoline distribution from 28% to 38% by marketing and opening new gasoline stations and is currently the Colombian market leader by volume.

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.

In July 2008, the Colombian MME issued a resolution modifying wholesale margins applicable to gasoline and diesel. This resolution approved an increment resulting in a $0.133 margin for gasoline and a $0.14 margin for diesel. These new margins were implemented gradually in August and September 2008.

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 377 company-owned service stations and 1,220 affiliated stations. Terpel has certifications under ISO 14001 and ISO 9001 (lubricants facility), and ISO 14001, ISO 9001 and OHSAS 18001 (Gualanday-Nieve pipeline).

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Terpel is active in the aviation fuel market and services 20 airports nationwide, including Colombia’s largest airport, El Dorado in Bogotá. Market share in the aviation business as of 2008 was 51% and amounted to 157 million gallons sold.

Gas Natural Comprimido S.A. (Gazel)

Overview

Gazel sells CNG as an automotive fuel in Colombia, Peru, Mexico and Chile. Gazel operates 229 service stations under the brand name Gazel.

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 37% share of the market, and is also looking at growth opportunities outside of Colombia. Gazel has 13 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 as of and for the dates indicated:


							As of and
							for the
	As of and for the Year Ended						Six Months
	December 31,						Ended June 30,
	2006		2007		2008		2009

Number of stations		119		163		201		229
Sales per day per station (cubic feet)		236,247		198,565		164,831		149,423
Converted vehicles (cumulative)		179,153		265,030		343,809		368,243
Fuel margin per cubic foot ($)	$	0.005	$	0.007	$	0.009	$	0.008

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. Gazel must maintain a price 40% to 50% lower than gasoline to maintain the current estimated payback time which varies by type of vehicle. As of May 2009, Gazel’s price was 45% 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.

Gazel has certifications under ISO 9001.

AEI Employees

As of June 30, 2009, we had approximately 14,700 employees. As of December 31, 2008, 2007 and 2006, we had approximately 14,200, 14,500 and 10,500 employees, respectively.

AEI Property, Plant and Equipment

Properties by each business segment are presented below, as of June 30, 2009, unless otherwise noted.

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Power Distribution


Business	Location	Approximate Miles of Power Distribution and Transmission Lines

Elektro	Brazil		66,163
Elektra	Panama		5,523
Luz del Sur	Peru		11,482
Chilquinta	Chile		5,118
Delsur	El Salvador		5,296
EDEN⁽¹⁾	Argentina		10,910
EMDERSA	Argentina		15,493


(1)		Pending local anti-trust approval.

Power Generation


		Generating
Business	Power Plant Location	Capacity (MW)		Fuel Type

Trakya	Turkey		478	Natural gas and fuel oil
Cuiabá — EPE	Brazil		480	Natural gas and fuel oil⁽¹⁾
Luoyang	China		270	Coal
PQP	Guatemala		234	Bunker fuel
San Felipe	Dominican Republic		180	Diesel oil/bunker fuel
ENS	Poland		116	Natural gas
Corinto	Nicaragua		71	Bunker fuel
Tipitapa	Nicaragua		51	Bunker fuel
JPPC	Jamaica		60	Bunker fuel
DCL	Pakistan		94	Natural gas
Emgasud	Argentina		109	Natural gas and fuel oil
Amayo	Nicaragua		40	Wind


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

Natural Gas Transportation and Services


Business	Location	Description

Promigas
Promigas Pipeline	Colombia	1,271 miles pipeline system in La Guajira region, to Jobo station in Department of Sucre
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 and 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
Emgasud	Argentina	440 miles of pipeline in the Patagonia region

Natural Gas Distribution


Business	Location	Description

Promigas
Surtigas	Colombia	4,951 miles of mains in Bolívar, Sucre and Cordoba
Gases de Occidente	Colombia	4,155 miles of mains in Valle del Cauca
Gases del Caribe	Colombia	8,670 miles of mains in Magdalena, Cesar, Atlántico and La Guajira
Cálidda	Peru	466 miles of mains in Lima and Callao provinces
BMG	China	870 miles of mains in 15 service areas
Tongda	China	1,299 miles of mains in 10 service areas in Jiangsu province
Emgasud	Argentina	482 miles of mains in Southeast Buenos Aires

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Retail Fuel


Business	Location	Description

SIE
Gazel	Colombia	212 service stations
	Mexico	3 service stations
	Peru	13 service stations
	Chile	1 service station
Terpel	Colombia	1,270 service stations, including 28 supply stations
	Chile	206 service stations
	Ecuador	63 service stations
	Panama	58 service stations

Legal Proceedings

We hold $201 million principal amount of notes of CIESA, which are in default. We were previously party to a restructuring agreement with CIESA pursuant to which this debt was to be exchanged for equity of CIESA upon receipt of all required government approvals. After having granted two extensions, those approvals were not obtained and accordingly, in January 2009, we terminated the restructuring agreement. Following the termination, CIESA filed a complaint against AEI in New York state court seeking a judgment declaring that any claim by AEI against CIESA with respect to this debt is time-barred because the statute of limitations pertaining to any such claim had expired. CIESA subsequently amended its complaint to also include an allegation that AEI’s termination of its restructuring agreement was in breach of that agreement. AEI does not believe that there is any merit to the suit and is vigorously defending the claim. In July 2009, the New York court dismissed CIESA’s complaint. CIESA has submitted a motion to reargue their claim and we have responded to this motion. Separately, in February 2009, AEI filed a petition in Argentina for the involuntary bankruptcy liquidation of CIESA. In July 2009, the Argentine court ruled that if CIESA did not cure its insolvency status within 20 days of us serving this decision on CIESA, CIESA would be put into bankruptcy. We served this decision on CIESA on July 31, 2009. In August 2009, CIESA appealed the bankruptcy court’s decision. In October 2009, the appellate court overturned the bankruptcy court’s decision, rejecting our petition. This decision did not rule on the enforceability of the debt. We are considering several alternative courses of action to pursue our claim. If CIESA does go into bankruptcy, we will request the enforcement of our debt before the bankruptcy court at the proof of claims stage.

Our 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 June 30, 2009, we have accrued liabilities totaling approximately $106 million for claims and suits, as recorded in accrued liabilities and other liabilities. This amount has been determined based on management’s assessment of the ultimate outcomes of the particular cases, and based on our general experience with these particular types of cases. Although the ultimate outcome of such matters cannot be predicted with certainty, we accrue for contingencies associated with litigation when a loss is probable and the amount of the loss is reasonably estimable. We do not believe, taking into account reserves for estimated liabilities, that the currently expected outcome of these proceedings will have a material adverse effect on our financial position, results of operations or liquidity. It is possible, however, that some matters could be decided in a manner that we could be required to pay damages or to make expenditures in amounts materially in excess of that recorded, but cannot be estimated at June 30, 2009.

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 June 30, 2009, we have accrued approximately $17 million related to these cases, excluding those described below.

In July 1998, two separate class actions were filed against Elektro and others. Each of these actions seek the annulment of the privatization of Elektro and allege, among other things, that the price paid for Elektro was low and

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unacceptable. These cases are currently pending. Elektro has been advised by external counsel that it has solid legal grounds on which to have each of the cases dismissed.

In August 2001, Elektro filed two lawsuits against the State Highway Department — DER (the State of Sāo Paulo’s regulatory authority responsible for control, construction and maintenance of the majority of the roads in the state) and other private highway concessionaires aiming to be released from paying certain fees in connection with the construction and maintenance of Elektro’s power lines and infrastructure in the properties belonging to or under the control of the State Highway Department and such concessionaires. The lower court and the State Court ruled in favor of the 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 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 $242 million (based on the exchange rate as of June 30, 2009) is due related to the tax periods involved. In June, 2008, Elektro was notified that an administrative ruling was rendered on these matters that would fully cancel both tax assessments. The ruling is subject to an automatic review by the Administrative Court of Appeal, but Elektro believes that it is likely that the ruling will be confirmed.

In December 2006, the Brazilian National Social Security Institute notified Elektro about several labor and pension issues raised during a two-year inspection, which took place between 2004 and 2006. A penalty was issued to Elektro in the amount of approximately $30 million (based on the exchange rate as of June 30, 2009) for the assessment period from 1998 to 2006. Based upon a Brazilian Federal Supreme Court precedent issued during the second quarter of 2008 regarding the statute of limitations for this type of claim, Elektro believes that a portion of the amount claimed is now time-barred by the statute of limitations. Elektro is in the initial stage of presenting its administrative defense and 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 $49 million as of June 30, 2009 and made a judicial deposit of approximately $21 million (based on the exchange rate as of June 30, 2009) related to this issue. In May 2009, a newly enacted Brazilian law revoked a previous law which resulted in a change to the method by which such contributions should be calculated. Pursuant to a technical notice issued by IBRACON (the local accounting standards board), Elektro has reversed the reserve previously allocated for this contingency. However, the $21 million judicial deposit made by Elektro will not be released until the final decision by the supreme court on their appeal is made.

In March 2007, the Federal Labor District Attorney in Brazil filed a public lawsuit against Elektro seeking to prohibit the company from using contractors for certain of its core business activities. The District Attorney claimed that workers who render services for Elektro should be directly hired by the company rather than by a third party. In June 2009, the court ruled in favor of the Federal Labor District Attorney. Elektro has been advised by external counsel that they have reasonable arguments on which to challenge this decision and have filed an appeal with the Regional Labor Court. This appeal is currently pending.

In December 2008, Elektro received a tax assessment from the São Paulo State Treasury claiming a payment of ICMS (Value Added Tax) of approximately $24 million (based on the exchange rate as of June 30, 2009). Elektro contested the assessment and the administrative tribunal hearing the matter ruled against Elektro. Elektro has appealed the tribunal’s ruling to the Tax Payer Council. Elektro believes that it has good legal grounds on which to dispute this claim.

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pleadings and requested the termination of the PPA based on Furnas’ default to make capacity payments. The tribunal accepted the amendment of EPE’s pleadings in the first quarter of 2009. We expect a decision in this arbitration by the end of 2009. If EPE is unable to satisfactorily resolve the dispute with Furnas, the operations of Cuiaba will be materially adversely affected with a corresponding negative impact on our financial performance and cash flows.

San Felipe Limited Partnership — 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 June 30, 2009, neither CDEEE nor the executive branch has obtained this legislative exemption. In February 2002, the local tax authorities notified San Felipe of a request for tax payment for a total of DOP 716 million (equivalent to approximately $20 million at the exchange rates as of June 30, 2009) of unpaid taxes from January 1998 through June 2001. San Felipe filed an appeal against the request which was rejected by the local tax authorities. In July 2002, San Felipe filed a second appeal before the corresponding administrative body which was rejected in June 2008. In July 2008, San Felipe appealed this ruling before the Tax and Administrative Court. We have accrued approximately $67 million as of June 30, 2009 with respect to the period from January 1998 through June 30, 2009 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.

DCL — DCL entered commercial operations on April 17, 2008. However, 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. Due to the shutdown, DCL has not generated revenues and cash inflows to pay vendors, which has delayed the repairs. On January 24, 2009, DCL received notice of default from one of its senior lenders. Shortly thereafter, two of DCL’s senior lenders filed claims against DCL and Sacoden, which holds AEI’s interest in DCL, in the courts of Sindh Province, Pakistan seeking repayment by DCL of loans totaling PKR3,704 million (equivalent to approximately $45 million at the exchange rates as of June 30, 2009). The lenders petitioned the courts to force a sale of all of DCL’s assets and all of Sacoden’s shares in DCL and to replace DCL’s directors and officers with a court appointed administrator. DCL and Sacoden filed responses to these claims. In June 2009, DCL entered into loan agreements with its senior lenders and Sacoden pursuant to which the senior lenders and Sacoden made loans to DCL to fund its rehabilitation efforts. In connection with these loan agreements, DCL and Sacoden entered into a Standstill Agreement with the senior lenders pursuant to which the parties agreed to refrain from taking legal actions against each other until mid-October. We have completed repairs on the plant, it is operational and final performance testing is underway.

DCL was party to a PPA with Karachi Electric Supply Corporation, or KESC, for the sale of all of the plant’s output of power, which was terminated by KESC in April 2009. DCL has started discussions with KESC with respect to a new power purchase agreement and, once the plant begins operations again, is expected to sell power to KESC on an interim basis while a new power purchase agreement is being negotiated.

If DCL is unable to satisfactorily resolve the dispute with its lenders or enter into an acceptable power purchase agreement, the operations of DCL will be materially adversely affected or the lenders may exercise their right to take ownership of the plant, in either event with a corresponding negative impact on our financial performance and cash flows.

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ECONOMIC AND REGULATORY ASPECTS OF THE
COUNTRIES WHERE WE DO BUSINESS

Introduction

We own and operate essential energy infrastructure assets in emerging markets across multiple segments of the energy industry.

We currently operate in emerging markets in Latin America, Central and Eastern Europe and Asia. Growth in emerging markets, as measured by GDP growth, has consistently outpaced growth in developed markets in the last 15 years. Global Insight expects this trend to continue predicting annual growth of 5.8% for countries which are not members of the OECD for the period 2010-2019 versus 2.3% for OECD countries over the same period. Emerging markets growth is primarily driven by industrialization and urbanization. The correlation between GDP growth and energy consumption such as electricity is high and we expect the growth in emerging markets to drive energy consumption and the associated infrastructure needs. Moreover, the low base consumption level of energy in emerging markets as compared to developed markets provides for more growth potential in emerging markets and will continue to drive overall energy and infrastructure demand. According to the CIA World Factbook, U.S. electricity consumption per capita is currently more than four times Chile’s, more than five times China’s, more than five times Brazil’s, more than 14 times Colombia’s and more than 15 times Peru’s. Natural gas consumption growth in non-OECD countries is also expected to be stronger than that of OECD countries (46% vs. 16% growth from 2006 to 2020) according to the Energy Information Administration’s 2009 International Energy Outlook. We believe this increased consumption growth is primarily driven by increased gas penetration in these countries. Due to the constraints on many of the governments in emerging markets and limitations on 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, nongovernmental entities. This expected growth provides us with a significant opportunity to further expand and diversify our existing energy infrastructure assets and to grow through new brownfield and greenfield development opportunities.

The table below provides summary economic data for the countries where we operate as of the date of this prospectus:


													Sovereign
					2008 Real						2008		Rating
					GDP⁽¹⁾			2008			Contribution		(Standard &
Country	2008 Population⁽¹⁾		2008 GDP⁽¹⁾		Growth (%)			Inflation⁽¹⁾ (%)			Percentage⁽²⁾		Poor’s/Moody’s)⁽³⁾
	(Millions)		(Billions of $)

Argentina		39.7		326.5		7.0	%		8.6	%		1.5%	B-/B3
Bolivia		10.0		17.4		5.9	%		14.0	%		1.7%	B-/B3
Brazil		191.9		1,572.8		5.1	%		5.7	%		36.2%	BBB-/Ba1
Chile		16.8		169.6		3.2	%		8.7	%		3.2%	A+/A1
China		1,327.7		4,401.6		9.0	%		5.9	%		(0.5)%	A+/A1
Colombia		48.3		240.7		2.5	%		7.0	%		35.4%	BB+/Ba1
Dominican Republic		8.9		45.6		4.8	%		10.6	%		0.2%	B/B2
Ecuador		13.9		52.6		5.3	%		8.4	%		NM	CCC+/Ca
El Salvador		5.8		22.1		2.5	%		7.3	%		2.1%	BB/Baa3
Guatemala		13.7		39.0		4.0	%		11.4	%		2.5%	BB/Ba2
Jamaica		2.7		14.4		(1.2	)%		22.0	%		0.4%	CCC+/B2
Mexico		106.3		1,088.1		1.3	%		5.1	%		NM	BBB/Baa1
Nicaragua		6.2		6.4		3.0	%		19.9	%		0.7%	NR/Caa1
Pakistan		160.5		167.6		6.0	%		12.0	%		0.1%	CCC+/B3
Panama		3.4		23.1		9.2	%		8.8	%		4.4%	BB+/Ba1
Peru		28.7		127.6		9.8	%		5.8	%		4.3%	BBB-/Ba1
Poland		38.1		525.7		4.8	%		4.2	%		2.8%	A-/A2
Turkey		69.7		729.4		1.1	%		10.4	%		3.5%	BB-/Ba3
Venezuela		28.1		319.4		4.8	%		30.4	%		1.5%	BB-/B2


(1)		International Monetary Fund World Economic Outlook Database, April 2009. (http://www.imf.org/external/pubs/ft/weo/2009/01/weodata/index.aspx)
(2)		“Contribution Percentage” means the contribution to AEI using Adjusted EBITDA of the businesses operating in the country.
(3)		Long-Term Foreign Currency rating as of December 31.

We discuss below the economic drivers, industry characteristics and regulatory aspects of the major countries in which we do business. This discussion is a summary and is not intended to constitute a complete analysis of the economic environment or the laws and regulations of the principal countries in which we operate.

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Brazil

In Brazil, we own interests in Elektro, EPE, GOB and TBG. Brazil has benefited from improving macroeconomic conditions over the past few years. Brazil’s GDP increased by 5.1% in 2008, with total electricity consumption equivalent to that of the United Kingdom. Brazil’s sovereign credit rating is Ba1 and BBB- by Moody’s and Standard & Poor’s, respectively. According to the Energy Research Agency (Empresa de Pesquisa Energético) of the Brazilian MME in its ten-year expansion plan for electric power 2008-2017 (Plano Decenal de Expansão de Energia Elétrica 2008-2017), Brazilian GDP is expected to grow 4.7% per year in the next three years, and electricity consumption is estimated to grow on average 5.5% per year through 2012.

Macroeconomic Environment

Brazil is Latin America’s largest economy (accounting for 55% of South America’s GDP and 49% of its population in 2008). President Luiz Inacio Lula da Silva has maintained market-friendly economic policies since he took office in 2003, with focus on the free float of the exchange rate, fiscal surplus and inflation targets.

As a result of its conservative monetary policies over the past years, Brazil’s inflation and interest rates have decreased from a high in late 2002, and the Brazilian real has steadily appreciated versus the U.S. dollar. In 2002, the real exceeded R$3.50/U.S.$1.00, and since has appreciated significantly, reaching levels below R$2.00/U.S.$1.00 levels in 2008.

The table below sets forth Brazil’s principal macroeconomic statistics:


	2004			2005			2006			2007			2008

Real GDP Growth (%)⁽¹⁾		5.7	%		3.2	%		4.0	%		5.7	%		5.1	%
Inflation — National Consumer Price Index (ICPA) (%)⁽²⁾		7.60	%		5.69	%		3.14	%		4.46	%		5.90	%
Year-End Exchange Rate (R$/U.S.$)⁽³⁾		2.65			2.34			2.14			1.77			2.34
Interest Rates (SELIC) (%)⁽⁴⁾		17.8	%		18.1	%		13.2	%		11.2	%		13.7	%
Country Risk Premium (EMBI) (bps)⁽⁵⁾		382			311			192			221			428
Sovereign Ratings (Moody’s/Standard & Poor’s)⁽⁶⁾		B1/BB-			Ba3/BB-			Ba1/BB			Ba1/BB+			Ba1/BBB-


(1)		International Monetary Fund World Economic Outlook Database, April 2009. Annual percent change.
(2)		IBGE. Year-on-year inflation rate.
(3)		Central Bank of Brazil. R$/U.S.$ Offer Spot Rate.
(4)		Central Bank of Brazil. End of year interest rate — SELIC.
(5)		JP Morgan’s EMBI Global Index. Year end spread.
(6)		Long-Term Foreign Currency rating as of December 31.

In 2008, Brazil’s macroeconomic environment was affected by the global economic crisis. During the first half of the year the real appreciated significantly against the U.S. dollar while country risk remained low. The second half of the year was characterized by an abrupt increase in country risk and a significant depreciation of the real, trends that have been reverted as global financial conditions eased in 2009. As of August 14, 2009, the country risk as measured by JP Morgan’s EMBI Global Index stands at 256 basis points, a 432 bps reduction from October 2008 high of 688 bps. On April 30, 2008 and May 29, 2008, Standard & Poor’s and Fitch, respectively, upgraded Brazil’s long term foreign currency sovereign debt rating to investment grade.

The Brazilian Power Industry

The Brazilian interconnected power system has an installed generation capacity of 101 GW. More than 70% of Brazil’s installed generation capacity is Hydro. Natural gas, oil and biomass account for 10.4%, 4.1% and 3.9% of Brazil’s installed generation capacity, respectively.

Over the last decade, Brazil’s electricity consumption has grown at an annual rate of 4.6%, with demand decreasing only during the energy rationing in 2001.

Privatization auctions for Brazilian energy assets occurred between 1995 and 2000, attracting U.S. and European investors to the Brazilian power sector. Although the government still controls significant transmission and generation assets, a majority of distribution is in private hands. Privately-owned entities currently own 28% of Brazil’s installed generation capacity (by MW), 12% of transmission lines (by length) and 66% of the distribution market (by customers).

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Historically, Brazil has been the primary market for Bolivian natural gas and Bolivia has supplied the majority of the gas consumed in Brazil. In July 1999, Bolivia began exporting natural gas to Brazil under a 20-year, take-or-pay contract between YPFB, the Bolivian state-owned energy company, and Petrobras for 1,059 mmcfd. In 2006, Bolivia exported to Brazil between 9 billion cubic feet per day (MMcf/d) and 1 Bcf/d of natural gas, more than two-thirds of Bolivia’s total natural gas exports. Recurring social unrest has recently impaired Bolivia’s ability to properly maintain its gas fields and provide reliable gas supply to Brazil. In response, Brazil has expanded initiatives to develop its own gas reserves and also considered importing gas from other neighboring countries, like Peru.

Brazil has also considered expanding the capacity of the Bolivia-to-Brazil Pipeline to 1,200 mmcfd from the current 1,059 mmcfd. Brazil is focusing on maximizing its own hydrocarbon resources and minimizing dependency on Bolivian gas reserves. Additionally, recent and recurring social unrest has directly impacted Bolivia’s ability to be a reliable supplier of natural gas to Brazil. Bolivia supplies the majority of Brazil’s gas consumption (63% of demand in the first half of 2005) and without the development of Brazil’s own reserves or the expansion of exports from Bolivia or potentially Peru, demand has outstripped supply.

Concessions

The Brazilian concession law establishes, among other things, the conditions that concessionaires must comply with when providing electricity services, the rights of customers, and the obligations of concessionaires and the granting authority. Concessions grant rights to generate, transmit or distribute electricity in the relevant concession area for a specified period. This period is usually 35 years for generation concessions and 30 years for transmission or distribution concessions. The Brazilian federal government is considering amending the law with respect to the renewal of electricity concessions. The extent to which the electricity concession law may be amended is not yet known.

Concessionaires must render adequately regular, continuous, efficient and safe service and are strictly liable for direct and indirect damages resulting from inadequate service. The granting authority may intervene in the concession to ensure adequate performance of services and full compliance with contractual and regulatory provisions. The termination of the concession agreement may be accelerated for reasons related to the public interest that must be expressly declared by law or if the concessionaire, among other things, (1) has failed to render adequate service or comply with applicable laws or regulations, or (2) no longer has the technical, financial or economic capacity to provide adequate service. The concessionaire may contest the expropriation or forfeiture in the courts. The concessionaire is entitled to indemnification for its investments in expropriated assets that have not been fully amortized or depreciated, after deduction of any fines and damages due by it.

Regulation of the Brazilian Power Industry

Under the present regulatory structure, the Brazilian government regulates the power industry through the Ministry of Mines and Energy (Ministério de Minas e Energia), or Brazilian MME. The Brazilian MME establishes the energy policy for Brazil and ANEEL implements the policy. ANEEL is the independent federal regulatory agency which has exclusive authority over the Brazilian power industry. ANEEL’s main function is to regulate the power industry and ensure the efficient and economic supply of energy to consumers by monitoring prices and ensuring adherence to market rules by market participants in line with policies dictated by the Brazilian MME. ANEEL supervises concessions for electricity generation, transmission, trading and distribution, including the approval of applications for the setting of tariff rates, and supervising and auditing the concessionaires.

In 2004, the Brazilian government introduced a new set of rules to regulate the industry: The New Industry Model Law. The New Industry Model Law was designed to (1) provide incentives to market participants to build and maintain generation capacity and (2) assure the supply of electricity in Brazil at reasonable tariffs through competitive public electricity auctions. The New Industry Model Law followed the desire of the Brazilian government to restructure the sector following the 2001 energy rationing crisis due to Brazil’s dependence on hydro power resources combined with poor hydro conditions that year.

The New Industry Model Law created two parallel environments for the trading of electricity, with (1) one market for distribution companies, called the regulated market and (2) another market for free customers, generation and electricity trading companies, called the free market. Except in specific cases, the new law does not allow distribution companies to enter into new contracts to buy energy other than contracts entered into pursuant to the regulated market auctions. Every distribution company is obligated to contract for 100% of its

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anticipated energy requirements, subject to the application of penalties. These costs can be passed through the tariff up to 103% of actual demand.

Colombia

In Colombia, we own interests in the Promigas Pipeline, Transmetano, Centragas, GBS, Transoccidente, Transoriente, PSI, Surtigas, Gases de Occidente, Gases del Caribe and SIE. Colombia has traditionally enjoyed a reputation of solid macroeconomic management. In 2008, Colombia’s inflation was 7.0% and GDP grew by 2.5%. Colombia’s sovereign credit rating is Ba1 and BB+ by Moody’s and Standard & Poor’s, respectively. According to base projections by the Mines and Energy Planning Unit of the Colombian MME, Colombia’s GDP is expected to grow 5% per year on average over the 2009-2018 period, and annual electricity consumption growth will average 3.9% per year on average over the same period.

Macroeconomic Environment

Colombia has undergone significant economic recovery since 2000, with strong exports driven by high international oil and commodity prices and more competitive exchange rates. Most recently, robust economic growth has been supported by stronger domestic demand, driven by increased business confidence due to Colombia’s conservative economic policies.

Standard & Poor’s recently reaffirmed Colombia’s long term foreign currency issuer credit rating of BB+ and commented that “successfully withstanding the severe stress imposed on the Colombian economy during the global downturn could set the stage for an upgrade when the global economy starts to recover.” (source: Bloomberg). Colombia’s positive macroeconomic outlook is also reflected in the relatively low country risk as measured by JP Morgan’s EMBI Global index, which after ending 2008 at 498 basis points in line with a global widening of spreads, has fallen back to 226 basis points as of August 7, 2009.

The table below sets forth Colombia’s principal macroeconomic statistics:


	2004			2005			2006			2007			2008

Real GDP Growth (%)⁽¹⁾		4.7	%		5.7	%		6.9	%		7.5	%		2.5	%
Consumer Price Inflation (%)⁽¹⁾		5.9	%		5.0	%		4.3	%		5.5	%		7.0	%
Year-End Exchange Rate (COP$/U.S.$)⁽²⁾		2,390			2,284			2,239			2,015			2,234
Interest Rates (%)⁽³⁾		7.8	%		6.3	%		6.8	%		9.0	%		10.1	%
Country Risk Premium (EMBI) (bps)⁽⁴⁾		332			238			161			195			498
Sovereign Ratings (Moody’s/Standard & Poor’s)⁽⁵⁾		Ba2/BB			Ba2/BB			Ba2/BB			Ba2/BB+			Ba1/BB+


(1)		International Monetary Fund World Economic Outlook Database, April 2009. Annual percent change.
(2)		Central Bank of Colombia.
(3)		Central Bank of Colombia. Interest rate of 90-day certificate of deposit. December average.
(4)		JP Morgan’s EMBI Global Index. Year end spread.
(5)		Long-Term Foreign Currency rating as of December 31.

Regulation

In 1991, the Colombian constitution was modified to contemplate private participation in utility services. These modifications created independent regulatory and control bodies; created the constitutional court; created alternative mechanisms for the resolution of conflicts (conciliations and out-of-court proceedings); and reallocated authority among the executive, legislative and judicial branches of the government. The modification also enabled the creation of national regulatory bodies to set and enforce the rules for private participation in public infrastructure.

These changes meant a significant reduction in legislative power over public utilities. Laws 80 (administrative contracts, 1993), 142 (public utilities, 1994) and 143 (electricity, 1994) governing infrastructure stemmed from the 1991 constitutional reform.

Law 142 created independent regulatory and customer protection agencies at the national level to oversee public services (telephony, electricity, gas, water and sewage). The legislation’s goal was to provide incentives for private participation in utility services, and it defined parameters for sector regulation. Existing concessions were not replaced or terminated under this law, rather, they continue in effect. However, there is open competition for the provision of these services although the barriers to entry are high.

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For concessions granted prior to the passage of Law 142, at the completion of the concessions the Colombian government has the option to purchase the assets at a price to be agreed upon with the concessionaire. The price is negotiated based on fair market value of the assets. If no agreement can be reached by the parties, a third-party valuation expert is employed to determine the selling price.

The Colombian Gas Transportation Industry

In Colombia, gas transporters receive a regulated tariff based on their rate base. The current tariff structure in place minimizes the sensitivity of revenues to volume transported. Transportation tariffs are set every five years by CREG based on an approved asset rate base, expected future volumes and regulated returns and recovery of efficient general and administrative and operations and maintenance expenses. Within the CREG framework there are two basic tariffs: a tariff for firm capacity and a tariff for interruptible capacity. The tariff is based on forecasted volumes with a tracking mechanism for minor differences within a tariff period. Under this framework, savings achieved through cost management and efficiency boost returns, but may be partially lost at the next tariff review.

The Colombian Gas Distribution Industry

Distribution tariffs are set by the CREG and reviewed every five years with the objective to establish returns, capital expenditures and cost recovery for LDCs. The end-user tariff has four basic components: fuel cost, transportation, distribution and commercialization fee. Fuel and transportation costs are pass-through components and are set by regulators independently of the LDC tariff reviews.

As in the transportation tariff, cost management is important for the LDCs. In the short-term, lower costs compared to the approved tariff will increase the LDC’s returns but may be partially lost at the next tariff review.

The Colombian Gasoline and CNG Industry

Gasoline is a competitive market operating under conditions characterized by an oligopoly. Tariffs and margins to gas retailers are regulated by the Colombian MME and have been fairly stable over time. Gasoline volumes have been threatened by illegally imported gas from Venezuela at significantly lower prices and gasoline theft from pipelines. The illegal imports are sold primarily by “white gasoline stations” (stations with no brand). The Colombian government has decreed, under Decree 1717 of 2008, that these stations need to be affiliated to a brand such as, but not limited to, Terpel, Petrobras, Exxon-Mobil or Chevron, by October 31, 2009. With this measure, it is expected that the illegal volumes will be reduced.

The competitiveness of CNG is driven by the price differential between gasoline and natural gas, and the costs associated with making vehicles capable of running on CNG. In order to promote conversions to CNG, private companies and the Colombian government have been subsidizing conversion costs. Annual conversion rates have increased from approximately 6,000 in 2002 to approximately 45,000 in 2008, with a CAGR of 40%. Analysis indicates that the lower cost of CNG generally allows users to recover their conversion investment in six to ten months. CNG must maintain a price 40% to 50% lower than gasoline to maintain the current payback time.

Turkey

In Turkey, we own interests in Trakya. Turkey experienced GDP growth of 1.1% in 2008, and both inflation, which was 10.4% in 2008, and unemployment, which was 13.6% in 2008, are still at high levels. Turkey’s sovereign credit rating is Ba3 and BB- by Moody’s and Standard & Poor’s, respectively.

Macroeconomic Environment

Turkey has a population of 69.7 million people and has experienced consistent economic recovery for the past seven years. During that period, a reformist program based on free float of the currency, greater independence of the Turkish Central Bank and greater fiscal discipline has been imposed. The Turkish lira depreciated by approximately 32% versus the U.S. dollar in 2008. As of August 14, 2009, the country risk as measured by JP Morgan’s EMBI Global Index was 307 basis points.

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The table below sets forth Turkey’s principal macroeconomic statistics:


	2004			2005			2006			2007			2008

Real GDP Growth (%)⁽¹⁾		9.4	%		8.4	%		6.9	%		4.7	%		1.1	%
Consumer Price Inflation (%)⁽¹⁾		8.6	%		8.2	%		9.6	%		8.8	%		10.4	%
Year-End Exchange Rate (TL/U.S.$)⁽²⁾		1.34			1.35			1.41			1.16			1.53
Interest Rates (%)⁽³⁾		18.0	%		13.5	%		17.5	%		15.8	%		15.0	%
Country Risk Premium (EMBI) (bps)⁽⁴⁾		265			223			207			239			532
Sovereign Ratings (Moody’s/Standard & Poor’s)⁽⁵⁾		B1/BB-			Ba3/BB-			Ba3/BB-			Ba3/BB-			Ba3/BB-


(1)		International Monetary Fund World Economic Outlook Database, April 2009. Annual percent change.
(2)		Central Bank of Turkey.
(3)		Central Bank of Turkey. CBRT Interest Rate — Overnight — Borrowing.
(4)		JP Morgan’s EMBI Global Index. Year end spread.
(5)		Long-Term Foreign Currency rating as of December 31.

The Turkish Power Industry

Until 1984, the electricity sector in Turkey was state run. The Turkish Electricity Company, or TEK, was solely responsible for all generation, transmission and distribution of electricity in Turkey. In 1984, private companies were allowed to generate, transmit and distribute electrical energy, provided that they obtained the necessary permits from the governmental authorities. The Turkish Ministry of Energy and Natural Resources was the responsible authority to give authorizations to power generation companies by entering into concession or implementation contracts. In 1994, TEK was broken up into the Turkish Electricity Distribution Company, or TEDAS, and the Turkish Electricity Generation and Transmission Company, or TEAS. TEDAS was responsible for distribution and TEAS was responsible for the generation, transmission and importation of electricity. TEAS played a single-buyer role, purchasing electricity from the private sector and selling it to TEDAS. With the exception of a few self-generation projects and one hydroelectric project, the majority of Turkish private power projects were developed after 1996.

In 2001, a new energy law, the 2001 Electricity Market Law, was passed in Turkey. Designed to meet applicable European Union standards, the new law intended to introduce a free market for the generation, transmission, trading and distribution of electricity in Turkey. The 2001 Electricity Market Law, in line with the aim of liberalizing the energy sector, split TEAS into three different companies: the Turkish Electricity Transmission Company, the Electricity Generation Company and TETAŞ. TETAŞ is the successor entity to TEAS and is responsible for the sale and purchase of electricity at the wholesale level in Turkey.

In 2006, the Privatization Administration declared the intent to commence the privatization of a number of electricity distribution companies. This process was put on hold in late 2006, but resumed in 2008 and is ongoing. We may consider growth opportunities in Turkey that arise from this privatization process.

Regulation of the Turkish Power Industry

The 2001 Electricity Market Law also created an independent regulatory body, the Energy Market Regulation Authority, or EMRA, that oversees the energy, petroleum and natural gas markets in Turkey, whose responsibilities include setting tariffs, issuing licenses, assuring competition and imposing sanctions. An electricity market license regulation was issued by EMRA in August 2002, which imposed a new licensing requirement for all companies engaged in electricity market activities in Turkey. While nothing in the new regulation specifically rejects or amends the rights and obligations of private power generators under existing implementation contracts and other agreements, it does not explicitly grant an exemption to existing operators from the requirements of the new regulation or provide that existing contractual rights prevail in the event of any conflict with requirements of the regulation or any licenses issued pursuant thereto. Among other things, existing private power generators were required to apply for a new license by June 30, 2003. The new license could potentially be withheld or have terms that conflict with the implementation contracts or other agreements. The impact of the 2001 Electricity Market Law and the new electricity market license regulation, and the Turkish government’s implementation of them, remain uncertain. No licenses to independent generating companies operating prior to the 2002 regulation have been issued as of the date of this prospectus.

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Chile

In Chile, we own a 50% interest in Chilquinta, a power distribution company, and through our Colombian subsidiaries Terpel and Gazel, we own a network of 217 service stations.

Chile is one of Latin America’s most stable economies, and has been able to achieve solid economic growth throughout recent years. Its GDP grew by 3.2% in 2008 and by 3.7% compounded over the last 10 years. Chile’s sovereign rating as of August 7, 2009 is A1 and A+ by Moody’s and Standard & Poor’s, respectively. The IMF forecasts a 3.6% GDP CAGR for the 2008-2014 period.

Macroeconomic Environment

Over the last two decades Chile experienced an unprecedented period of economic growth coupled with improving fiscal accounts and controlled inflation. Government spending has been responsibly managed, presenting primarily surpluses in the last 9 years and public debt has decreased significantly from 16% of GDP in 2002 to 5% in 2008. High commodity prices have been a key element for boosting value of exported products, stimulating domestic demand and increasing fiscal revenues. Chile is internationally recognized for having applied sound economic policies over that period.

Chile’s sovereign debt has maintained an investment grade status for over a decade, which is reflected in its relatively low country risk as measured by JP Morgan EMBI Global Index, which stood at 132 as of August 7, 2009. Although the global financial crisis made Chile’s EMBI Global to surge up to 411 points in January 2009, the country’s solid economy and long term outlook dissipated credit concerns and this spread has significantly narrowed since then.

The table below sets forth Chile’s principal macroeconomic statistics:


	2004			2005			2006			2007			2008

Real GDP Growth (%)⁽¹⁾		6.0	%		5.6	%		4.6	%		4.7	%		3.2	%
Consumer Price Inflation (%)⁽¹⁾		1.1			3.1			3.4			4.4			8.7
Year End Exchange Rate (CLP$/U.S.$)⁽²⁾		559.83			514.21			534.43			495.82			629.11
Interest Rates (%)⁽³⁾		1.9	%		3.4	%		5.0	%		5.3	%		7.1	%
Country Risk Premium (EMBI Global) (bps)⁽⁴⁾		64			80			84			151			343
Sovereign Ratings (Moody’s/Standard & Poor’s)⁽⁵⁾		Baa1/A			Baa1/A			A2/A			A2/A+			A2/A+


(1)		Central Bank of Chile. Annual percent change.
(2)		Observado exchange rate published by the Central Bank of Chile on the last banking day of December of each year (i.e. excluding December 31st).
(3)		Central Bank of Chile. Annual average for the Reference Rate for Monetary Policy (Tasa de Referencia de Politica Monetaria)
(4)		JP Morgan’s EMBI Global Index. Year end spread.
(5)		Long Term Foreign Currency rating as of December 31.

The Chilean Power Industry

Industry Structure

The Chilean electricity sector is divided into generation, transmission and distribution segments. Generation companies can either sell their production to distribution companies, unregulated customers and/or other power generation companies in the spot market. Transmission companies can either distribute the energy from generators to large customers or to distribution companies. The distribution activity consists of the sale of energy to end-users at a voltage lower than 23kV.

The Chilean electricity grid is comprised of four interconnected systems. The SING (Sistema Interconectado del Norte Grande) covers the northern part of the country. The vast demand for the SING is derived from large customers, mainly mining companies. The SIC (Sistema Interconectado Central) services the central and southern areas of the country. It is the largest system both in terms of area covered and in terms of population residing in the area. The Magallanes and Aysén systems are smaller and operate in remote areas of the country. There are 3 distribution companies operating in the SING and 28 in the SIC, serving 0.3mm and 4.6mm customers, respectively.

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The SIC and the SING have both been designed to function as near-perfect markets; the lowest cost producer is used to satisfy demand at any point in time. As a consequence, at any specific level of demand, the appropriate supply will be provided at the lowest possible cost of production available, thus minimizing the system’s marginal cost. This coordination and supervision is executed by the CDEC (Centro de Despacho Economico de Carga), an organization that involves industry groups and transmission companies.

Regulation of the Chilean Power Industry

The main objective of the Chilean regulatory system is to establish adequate economic incentives for investors in order to ensure power supply in the long term, while at the same time stimulating efficiency and high productivity that result in low final tariffs.

The electricity sector in Chile is regulated by the Electricity Law, which was first enacted in 1982. The main goal of the Electricity Law is to provide an efficient and simple regulatory framework. Three governmental entities have primary responsibility for the implementation and enforcement of this law: the CNE or National Commission of Energy, the Ministry of Economy and the SEF or Superintendency of Electricity and Fuels. The CNE is primarily responsible for calculating tariffs based on pre-established formulas, both at the retail (regulated customers) and wholesale (node prices) levels. The Ministry of Economy is responsible for granting final approval to the tariffs and wholesale (or node) prices set by the CNE and for regulating the granting of concessions to electricity hydroelectric generation, transmission and distribution companies. It also is in charge of conducting the long term planning of the sector. The SEF sets and enforces the technical standards of the system and the proper compliance with the law.

Distribution tariffs in Chile are the sum of the cost of the energy purchased from generation companies, a transmission fee and the Distribution Added Value (VAD) component which is a markup that distribution companies are allowed to charge their final customers in order to pay for their operating costs (SG&A, maintenance and operating costs, energy costs and losses) and generate an allowed return on investment based on the replacement cost of the assets employed for the distribution activity. In order to determine the VAD, a model company for each of the distribution concessions is employed. Hence, costs and margins are standardized, and final tariffs are determined based on this model company that is supposed to be a company operated in an adequate manner. Final profitability of a firm will depend on whether it can achieve a higher or lower productivity than the model company. VAD reviews are executed every four years, and the last one was held in 2008. The VAD is subject to monthly interim adjustments in order to reflect changes in inflation and foreign exchange, while node prices are reviewed semiannually.

Peru

In Peru, we own interests in Luz del Sur, Cálidda, SIE, Gazel and Fenix. Peru has benefited from improving macroeconomic conditions over the past few years. Peru’s GDP increased by 9.8% in 2008 and has had an average growth rate of 6.8% over the past 7 years. In terms of electricity consumption and production, Peru ranks 59th and 62nd in the world, respectively.

Although the 2008 global financial crisis has slowed Peruvian growth, 3.5% growth is still expected in 2009. Peru’s 2009 sovereign credit rating is Ba1 and BBB− by Moody’s and Standard & Poor’s, respectively. According to the International Monetary Fund, Peruvian GDP is expected to grow at an average rate of 5.5% per year in the next five years.

Macroeconomic Environment

Peru ranks as the third best country for business in Latin America according to Latin Business Chronicle and is in a strong position to run a countercyclical policy in 2009-10 to shore up the economy during the global recession. This is partly due to its sound public finances (Peru is a net public creditor), with a comfortable cushion provided by reserves held by the Banco Central de Reserva del Perú (BCRP, the Central Bank). This has allowed policymakers to take strong monetary and fiscal measures to support growth so far, and they will be prepared to act further. The Central Bank is close to the end of an aggressive easing cycle and in late 2008 the government announced a US$3.2 billion (2.7% of GDP) stimulus package, partly drawing on a US$3.3 billion fiscal stabilization fund. Additionally, the government will seek to bolster private investment via infrastructure concessions and a more attractive operating environment.

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After peaking at 6.7% in December 2008 (a ten-year high), inflation fell to 3.1% in June 2009 and is set to ease further in the outlook period as global commodity prices remain subdued, domestic demand contracts and the high monthly rates of inflation in 2008 fall out of the equation. As such, inflation is expected to move back within the BCRP’s medium-term target of 2% for the remainder of 2009. Year-end rates of 2% in 2009 and 3.3% in 2010 are expected as well, as ample capacity and only a modest recovery in domestic demand helps inflation to trend marginally lower.

The nuevo sol, which has, in line with other emerging market assets, strengthened since March (to Ns3.00:US$1 in late July, from an average Ns3.02:US$1 in June), is expected to weaken only modestly over the forecast period according to the Economist Intelligence Unit. Aggressive monetary easing has boosted market confidence in the Peruvian authorities’ pro-growth response to the downturn, offsetting narrowing interest differentials; falling inflation is also supportive of currency stability. International reserves remain robust at US$32.1 billion in late July, representing 15 months of import cover and well in excess of Peru’s broad external financing requirement.

The table below sets forth Peru’s principal macroeconomic statistics:


	2004			2005			2006			2007			2008

Real GDP Growth (%)⁽¹⁾		5.0	%		6.8	%		7.7	%		8.9	%		9.8	%
Inflation — General Market Price Index (IGP M) (%)⁽¹⁾		3.3	%		1.6	%		2.0	%		1.8	%		5.8	%
Year End Exchange Rate (S/./U.S.$)⁽²⁾		3.28			3.42			3.20			2.99			3.12
Interest Rates (CDI) (%)⁽³⁾		1.4	%		2.9	%		4.3	%		4.7	%		5.9	%
Country Risk Premium (EMBI) (bps)⁽⁴⁾		220			206			118			178			509
Sovereign Ratings (Moody’s/Standard & Poor’s)⁽⁵⁾		Ba3/BB			Ba3/BB			Ba3/BB+			Ba2/BB+			Ba1/BBB-


(1)		International Monetary Fund World Economic Outlook Database, April 2009. Annual percent change.
(2)		Central Reserve Bank of Peru — Annual Report.
(3)		Global Economics Research. Trading Economics (http://www.tradingeconomics.com/Economics/Interest-Rate.aspx?symbol=PEN)
(4)		JP Morgan’s EMBI Global Index. Year end spread.
(5)		Long Term Foreign Currency rating as of December 31.

Despite the steady depreciation of the nuevo sol in relation to the U.S. dollar, the increasing interest rates and the steady decline of the country’s credit rating, Peru has sustained high levels of economic growth. Peru remains advantageously situated to recover relatively quickly from the global financial crisis.

The Peruvian Power Industry

Peru’s total electricity generation was 27,370 GWh in 2006, increasing 9.9% to around 29,943 GWh in 2007. For this last year, 65% of generation came from hydropower plants, and 35% from thermal power plants. On the other hand, total sales of electricity in 2007 totaled 24,722 GWh, where 54% was traded in the regulated market and 46% through open markets.

In recent years, Peru has experienced rapid growth in energy consumption, with the most rapid growth coming from natural gas consumption. This can be attributed to Peru’s rapid industrial growth and the increasing population growth rate will continue to keep energy consumption high. Indeed, total energy demand is projected to grow at 2.6% per year, compared with annual growth in the previous two decades of 0.6%. The industrial sector is expected to maintain the largest share at 35%, followed by transport (33%), residential (24%) and commercial (8%).

The industrial sector is the largest energy consumer in Peru, with the extraction of non-ferrous metals taking the largest share. According to the Asia-Pacific Economic Cooperation, or APEC, the sector’s energy demand is expected to grow at an average annual rate of 2.7% until 2030, faster than its average annual growth of 1.0% over the past two decades. More than half of the energy required in the industrial sector will be used by heavy industry such as mining, chemicals, metals, non-metallic minerals, quarrying and fishing.

Energy demand in the residential sector is projected to increase at an annual rate of 1.5% compared to a decreasing rate of 0.7% annually over the past two decades according to the APEC. This growth will be a result of increased electricity demand and use of petroleum products. Similarly, energy demand in the commercial sector is projected to growth at 4.5% annually as a result of growth in the services industry.

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Peru has substantial reserves of natural gas. However, the development of a domestic natural gas market has been very slow. Plans to extend the natural gas pipeline to other cities have not been realized due to a lack of investment. The government has also been promoting the utilization of natural gas to replace oil in the energy mix and reduce oil dependency. In fact, increasing energy imports, combined with depleting domestic resources, have lead to serious energy supply security concerns. Other factors related to the slow development of the domestic natural gas market include delay in the development and construction of Camisea LNG export facilities, which are expected to be completed soon. The demand for natural gas in Peru has exceeded all official forecasts. As a result, natural gas reserves are already committed and, currently, the licensee of Block 88 (the only natural gas supplier connected to the local gas transportation system) is not executing new gas supply contracts. Although there are some positive results registered by exploration activities conducted in the Camisea area, it has been reported that these reserves will only be commercially available from the year 2014.

Driven by economic development, Peru’s electricity demand is projected to increase to 66 TWh by 2030 (compared to 22 TWh in 2002). As a result, the Peruvian electricity sector will need to invest significantly in electricity generation and transmission facilities to meet this expected demand. Reforms have been undertaken to increase electricity supply security, facilitate investments by the private sector and to improve operational efficiency of the electricity industry. The restructuring of the electricity industry has been carried out since 1992.

Regulation of the Peruvian Power Industry

The Peruvian electricity system has the following main characteristics:


	•	unbundled market (i.e., separation of generating, transmission and distribution functions for all sector enterprises except in isolated regions);

	•	competition in the generation market, with a free-access-right to the electric grid;

	•	a regulated monopoly in transmission and distribution;

	•	a regulated monopoly for the electricity supply to public service costumers (i.e., those with a demand of up to 200 kW);

	•	unregulated prices for the supply to “free customers” (i.e., those with a demand above 200 kW);

	•	a national interconnected grid, managed by the Committee for Economic Operation of the National Grid — COES, a privately governed committee comprised of generators, transmission companies, distribution companies and free costumers; and

	•	an independent regulatory agency, OSINERGMIN.

The legislative framework is mainly comprised of (i) the Electric Concessions Law — ECL, (ii) the Electrical Sector Antitrust Law, and (iii) the Regulatory Agencies Framework Law. In July 2006 the Efficient Generation Law was enacted. This law is aimed at reforming several aspects of the existing regulation in order to ensure the efficient development of power generation and transmission.

The authorities involved in the regulatory policy with respect to the electricity sector are the Ministry of Energy and Mines and OSINERGMIN. In addition, Congress is authorized to legislate on issues directly or indirectly related to the electricity sector.

The Ministry of Energy and Mines is the entity responsible for granting the concessions and authorizations required to develop electricity activities (generation, transmission and distribution). It is also responsible for defining the policies pertaining to the energy sector and approving the transmission plan and the operation procedures proposed by COES.

OSINERGMIN is in charge of supervising and controlling the electric companies, setting the applicable tariffs in accordance with the ECL and its regulations, and approving the terms and conditions governing the contractual relationships between suppliers and clients with respect to all power sales which have public service customers as end users.

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ENVIRONMENTAL CONSIDERATIONS

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

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

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

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MANAGEMENT

Directors and Executive Officers

The following table sets forth our directors and executive officers, their age as of the date of this prospectus and the positions held by them. The business address for each of our directors and executive officers is c/o AEI Services LLC, 700 Milam, Suite 700, Houston, Texas 77002.


Name	Age		Position

Ronald W. Haddock		69	Non-Executive Chairman of the board of directors
James A. Hughes		46	Chief Executive Officer and Director
Eduardo Pawluszek		46	EVP, Chief Financial Officer
Maureen J. Ryan		38	EVP, General Counsel and Chief Compliance Officer
Emilio Vicens		42	EVP, Commercial
Laura C. Fulton		46	EVP, Accounting
Andrew Parsons		46	EVP, Administration
Brian Zatarain		34	EVP, Risk
Brian Stanley		65	EVP, Operations
Robert Barnes		57	Director
Philippe A. Bodson		64	Director
Henri Philippe Reichstul		60	Director
Robert E. Wilhelm		69	Director
George P. Kay		37	Director
Wilfried E. Kaffenberger		65	Director
Julian Green		46	Director

Ronald W. Haddock is the non-executive chairman of our board of directors and has been a director first of PEI, and then of AEI 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, Rubicon Offshore International and Petron Corporation 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.

James A. Hughes joined us in May 2007 as chief operating officer and became our Chief Executive Officer in October 2007. He has been a director of AEI since October 2007. Prior to joining us, Mr. Hughes was a principal of a privately-held company that focused on micro-cap investments in North American distressed manufacturing assets. Previously, 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 moving to their Warsaw, Poland office where he specialized in international project development. Mr. Hughes served on the board of Quicksilver Resources Inc., an exploration and production company until early 2009. Mr. Hughes holds a bachelor of business administration degree from Southern Methodist University in Dallas, Texas and a juris doctor from the University of Texas School of Law in Austin, Texas. He is admitted to the practice of law in Texas.

Eduardo Pawluszek joined us in September 2009 as EVP, Chief Financial Officer. Mr. Pawluszek has significant experience in the energy industry. Prior to joining us, Mr. Pawluszek was the chief executive officer of our subsidiaries Emgasud from February to September 2009 and EDEN from September 2007 to January 2009. Prior to these roles, Mr. Pawluszek served as chief financial officer of TGS from 2005 to 2007 after working as a manager in the area of finance and investor relations for TGS from 1999 to 2005. He worked for the Royal Bank of Canada from 1988 to 1999 focusing on business development with Argentine and Chilean corporate clients and corporate banking. Mr. Pawluszek is currently a member of the board of directors of several of our subsidiaries: Luz del Sur, of which he is the chairman, EDEN, Chilquinta and Emgasud. He also currently serves as the vice president

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and a board member of the Argentine Institute of Financial Executives. Mr. Pawluszek received a degree in public accounting from the University of Buenos Aires and a master in finance and capital markets from the Escuela Superior de Economía y Administración de Empresas.

Maureen J. Ryan joined us in December 2006, and is currently EVP, General Counsel and Chief Compliance Officer for AEI. Prior to joining us, Ms. Ryan was counsel in the mergers and acquisitions department of the New York office of Clifford Chance US LLP, which she had joined in 1995. 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 Vicens joined us in April 2007 and is currently EVP, Commercial 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 his bachelor of arts in Banking and Finance from Universidad Metropolitana in Caracas, Venezuela with honors in 1991 and his master of business administration from Harvard Business School in Boston, Massachusetts.

Laura C. Fulton joined us in March 2008 and is currently EVP, Accounting for AEI. Prior to joining us, Ms. Fulton spent 12 years with Lyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and the Sarbanes-Oxley certification process, and as the assistant controller. Previously, she worked for Deloitte & Touche in its audit and assurance practice for 11 years. Ms. Fulton is a CPA and graduated cum laude from Texas A&M University with a bachelor of business administration in accounting. Ms. Fulton is a member of the American Institute of Certified Public Accountants and serves on the Accounting Department Advisory Board at Texas A&M University.

Andrew Parsons joined PEI in September 2004 and is currently EVP, Administration for AEI. Mr. Parsons is responsible for the Administration department which includes internal audit, Sarbanes-Oxley project management and special projects, human resources, information technology and communications. Mr. Parsons has been with AEI and PEI since 2004 working as the 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 bachelor of arts with honors from Carleton University and a master of business administration from the University of Houston.

Brian Zatarain joined PEI in January 2002 and is currently EVP, Risk 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 PEI, from March 2000 to May 2006 primarily focused on acquisitions, greenfield development and asset management. Previously, Mr. Zatarain worked at Coastal Power for three years supporting the execution of its Latin American energy infrastructure acquisition and greenfield development strategy. Mr. Zatarain holds a bachelor of arts in economics from the University of Texas and a master of business administration from Duke University.

Brian Stanley joined PEI in January 2002 and is currently EVP, Operations for AEI with technical and operational responsibility for all of our assets worldwide. He served as Enron’s operations manager of the Teesside Power Station in the UK, assuming the position of plant manager in 1993. He held other positions within Enron, including general manager of Enron Power Operations, responsible for all power plants in the United States and

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Central America, vice president asset management Enron Europe with responsibility for power generation facilities in Europe, and president and chief executive officer of Enron Engineering & Operational Services responsible for global construction, engineering and operations of power generation and gas processing facilities. He has over 45 years of 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).

Robert Barnes has been a director first of PEI, and then of AEI since May 2006. Mr. Barnes was, in 1997, one of the founding members of Alchemy Partners LLP, a private equity advisory firm. 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 AEI since July 2003. Mr. Bodson has extensive experience with utility and industrial concerns with international activities, which includes having served as chief executive officer of Glaverbel from 1980 to 1989, Tractebel from 1989 to 1999 and Lernout & Hauspie (post-bankruptcy) in 2001. Mr. Bodson also has extensive board experience, having served as a director for Glaverbel, Tractebel, Electrabel, Société Générale, A.G., Société Générale de Banque, Compagnie Immobiliere de Belgique, Hermes Focus Asset Management Europe, Louis de Waele, British Telecom Belgium, Diamond Boart and Fortis, and serving today as chairman of the board of HAMON, Exmar and Floridienne, and as director of Cobepa 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 Liège 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 AEI since December 2003. He is currently the chief executive officer of Brenco, a Brazilian ethanol production company. Mr. Reichstul has also been chairman of G & R — Gestão Empresarial, a consulting firm, since 2002. 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, Peugeot 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 AEI since December 2003. Mr. Wilhelm was employed by Exxon Mobil (and predecessor companies) from 1963 until he retired in 2000. Mr. Wilhelm currently is an independent energy consultant and venture capital investor. During his career with Exxon,

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Mr. Wilhelm held a variety of operating assignments, primarily in the international petroleum business, including chief executive officer for Latin America and executive vice president for all international petroleum activities. 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 Energy Efficiency Center 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 master of business administration from the Harvard Business School in 1964.

George P. Kay has been a director of AEI since May 2008. Mr. Kay has been a vice president of GIC Special Investments Pte Ltd. since April 2006, where he is responsible for infrastructure investments in the UK, North America and South America. Mr. Kay is based in London and he currently also serves on the board of directors of Associated British Ports plc and is a member of its remuneration and nomination committee. Prior to joining GIC Special Investments Pte Ltd., Mr. Kay worked in principal finance for the Commonwealth Bank of Australia from September 2000 to April 2006. Prior to that, Mr. Kay worked for Westpac Banking Corporation as senior credit analyst. He received his master of applied finance from Macquarie University, Australia and a bachelor of commerce from University of Canterbury, New Zealand where he studied accounting and economics.

Wilfried E. Kaffenberger has been a director of AEI since August 2009. Mr. Kaffenberger is currently a director of NWS Holdings, a Hong Kong-based company which owns and operates infrastructure and service businesses in Hong Kong, Macao and China and is a director of BAA Airports Limited, a London-based company which operates major airports in the United Kingdom. In 2008, he retired from the role of chief executive officer of AIG Asian Infrastructure Fund II, a $1.6 billion private equity investment organized in 1997. For the 11 year period from 1997, Mr. Kaffenberger was managing director of Emerging Markets Partnership, an asset management firm focused on equity investments in emerging markets. Prior to that, he was vice president, Investment Operations for the International Finance Corporation (IFC), an affiliate of the World Bank focused on investing in private companies in emerging markets. His career at the IFC, in various positions, covers 25 years. He received a bachelor of science degree from Princeton University in 1966 and a master of business administration from Harvard Business School in 1968.

Julian Green has been a director of AEI since September 22, 2009. He was a founding shareholder of Ashmore in 1999 and director until 2004. He was a member of the Investment Committee at Ashmore since its inception until September 21, 2009 and was the senior portfolio manager with daily responsibility for fixed income investment management. He joined Grindlays Bank plc in 1985. In 1990, he joined the ANZ Emerging Markets Group within Grindlays Bank as an originator/distributor and then in 1992 became an original member of the Investment Committee of the ANZ Emerging Markets Fund Management Group, which later became Ashmore through a management buyout. He received a BSc in Management Sciences from the London School of Economics in 1985. He is a member of the Development Committee of the London School of Economics and an associate of the Chartered Institute of Bankers.

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International Management

The following table sets forth certain members of our international management team, their years of experience as of the date of this prospectus 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
Name	Position	the Energy Industry

Antonio Celia Martínez-Aparicio	CEO of Promigas	25
Carlos Marcio Ferreira	CEO of Elektro	5
Pablo Ferrero	EVP, Southern Cone	18
Roberto Figueroa	EVP, Central America and Caribbean	22
Jacek Glowacki	VP, AEI Europe	28
Colin Tam	CEO of AEI Asia	37

Duties of Directors

Under Cayman Islands law, our directors have a fiduciary duty to act honestly, in good faith and with a view to our best interests. Our directors also have a duty to exercise the skills they actually possess and such care and diligence that a reasonably prudent person would exercise in comparable circumstances. In fulfilling their duty of care to us, our directors must ensure compliance with our Amended and Restated Memorandum and Articles of Association, 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;

	•	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.

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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, Barnes and Kaffenberger. 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 of the Securities Act. Our board of directors has determined that each of Messrs. Barnes, Bodson, Wilhelm and Kaffenberger is an “independent director” within the meaning of NYSE Manual Section 303A and meets the criteria for independence set forth in Section 10A(m)(3) and Rule 10A-3 of the Exchange Act.

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;

	•	establishing clear hiring policies for employees or former employees of the independent auditors;

	•	reviewing with management and the independent auditors our annual audited financial statements and periodic financial statements and any major related issues, critical accounting policies, including financial reporting issues that could have a material impact on our financial statements, and major issues regarding accounting principles and financial statements presentations;

	•	resolving disagreements between our independent auditors and our management regarding financial reporting;

	•	reviewing with the independent auditors any problems or difficulties encountered in the course of any audit work and management’s response;

	•	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 an annual proxy statement, as applicable;

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	•	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 our 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 elected annually for one-year terms by majority vote of the board of directors. Mr. Bodson is the chairman of our compensation committee. Our board of directors has determined that Messrs. Reichstul and Bodson qualify as “independent directors” under the listing standards set forth in NYSE Manual Section 303A.

Our compensation committee is responsible for, among other things:


	•	reviewing our executive compensation, incentive-based, equity-based, general compensation and other employee benefits plans and our goals and objectives with respect to such plans and amend or recommend amending such plans or our goals and objectives with respect to such plans as appropriate;

	•	evaluating annually the performance of our executive officers in light of the goals and objectives of our executive compensation plans, and determining and approving the compensation level of such executive officers based on this evaluation, including the long-term incentive component of their compensation, if any; and

	•	evaluating annually the appropriate level of compensation for board and committee service by non-employee members of the board of directors.

Nominating and Corporate Governance Committee

The nominating and corporate governance committee of our board of directors recommends to our board of directors individuals qualified to serve as directors of AEI and on committees of our board, advises our board of directors with respect to corporate governance principles applicable to us as well as the board composition, procedures and committees and oversees the evaluation of our board of directors and our management. The nominating and corporate governance committee is currently comprised of Messrs. Haddock, Wilhelm and Bodson. The members of the nominating and corporate governance committee are elected annually to one-year terms by majority vote of our board of directors. Mr. Haddock is the chairman of our nominating and corporate governance committee. Our board of directors has determined that Messrs. Haddock, Wilhelm and Bodson qualify as “independent directors” under the listing standards set forth in NYSE Manual Section 303A.

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;

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	•	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 the 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.

Board Observer

We have entered into a board observer agreement with Ashmore, pursuant to which we granted to Ashmore the right to designate observers to our board of directors. This agreement will become effective upon completion of this offering. The observers will have the right to attend meetings of our board of directors and its committees and receive notice of all such meetings and information that is distributed to directors in connection with such meetings. We may exclude the observers from attending any meeting or receiving any materials if our board of directors determines that granting access to such information could result in a breach of any contractual or legal obligation of AEI or is inconsistent with our board of director’s fiduciary duties. In addition, if we are considering any transaction in which Ashmore or any of its Affiliates has an existing interest, then we may elect not to provide the materials relating to such transaction to the observers and the observers will excuse themselves from that portion of the meeting.

Subject to certain limited exceptions, Ashmore has agreed to maintain confidential all information that it may receive from the observers. This arrangement does not have a specified term and will continue until terminated by either Ashmore or AEI. There are no restrictions on termination by either party to the agreement.

Corporate Governance

We have adopted a code of conduct that was approved by our board of directors, and that is applicable to all of our directors, officers and employees. Our code of business conduct is publicly available on our website. In addition, our board of directors has adopted a set of corporate governance guidelines.

Interested Transactions

A director may vote with respect to any contract or transaction in which he or she is interested, provided that the nature of the interest of any director in such contract or transaction is disclosed by him or her at or prior to its consideration and any vote in that matter.

Remuneration and Borrowing

The directors may determine remuneration to be paid to the directors. The compensation committee assists the directors in reviewing and approving the compensation structure for the directors. The directors may exercise all the powers of our company to borrow money and to mortgage or charge its undertaking, property and uncalled

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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.

Indemnification

We have entered into indemnification agreements with our directors and executive officers. With specified exceptions, these agreements provide for indemnification for related expenses including, among other things, attorneys’ fees, judgments, fines and settlement amounts incurred by any of these individuals in any action or proceeding.

There is no currently pending material litigation or proceeding involving any of our directors or officers for which indemnification is sought.

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 an annual equity grant. In 2008, we paid our directors an aggregate of $991,667 in director fees. For fiscal year 2008, we issued grants of restricted shares and options to our directors in February 2009 with a fair value on the date of grant of $160,006 in aggregate.

With respect to 2008, we paid our executive officers an aggregate of $3,786,938 (pretax) in salaries and cash bonuses. For fiscal year 2008, we issued grants of restricted shares and options to our executive officers in February 2009 and in February 2008 with a fair value on the date of grant of $1,923,373 in aggregate. The equity ownership of our executive officers and directors is described below. 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.

Annual executive cash bonuses and option awards are calculated based on the achievement of financial and operational targets that are established at the beginning of each year. The measures used for financial targets are Adjusted EBITDA, Net Income, and cash to the Company. The actual 2009 financial targets that will be used to determine executive cash bonus and option awards are Adjusted EBITDA equal to $1,160 million, Net Income equal to $207 million, and cash to the Company equal to $450 million. Operational targets measure physical asset performance over the course of a year and are a mix of availability, environmental, health and safety measures which vary by asset type. The operational measures and the related 2009 targets are: power plant availability equal to 92.69%, pipeline availability equal to 99.96%, gas processing availability equal to 95.33%, duration of electrical outages equal to 8.44 hours per year, frequency of electrical outages equal to 5.99 system outages per year, lost time incident frequency rate equal to 0.26, number of fatalities equal to zero, and reportable spills equal to zero.

Annual executive cash bonuses and option awards are also impacted by individual executive performance, which is measured by reviewing the achievement of individual objectives and by evaluating each executive’s level of proficiency in the following competencies: general characteristics, teamwork, professional competencies, problem solving and thinking skills, managerial skills, international skills and values, ethics and controls. Each executive’s proficiency is rated in a 360° review process that requires anonymous feedback on each competency from subordinates, coworkers, peers and supervisors. Based on the results of the review process and the attainment of individual objectives, an overall rating is assigned to each executive to determine individual performance. The results are reviewed and approved by the Compensation Committee of the Board of Directors.

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Share Ownership of Directors and Executive Officers

As of the date of this prospectus, our directors and executive officers, as a group, beneficially own 1,798,438 of our ordinary shares. In addition, our directors and executive officers hold 128,623 unvested shares. Our directors and executive officers, as a group, beneficially own vested options to acquire 79,077 of our ordinary shares, exercisable at prices ranging from $11.18 to $16.00 per share. In addition, our directors and executive officers hold 728,529 unvested options. The total number of outstanding shares as of the date of this prospectus is 244,117,724.


	Ordinary Shares Held by Directors and Executive Officers
	Ordinary
	Shares
	Beneficially		Total Options		Grand Total
Name	Owned		Owned		Owned		Percent

Directors and Executive Officers
Ronald W. Haddock⁽¹⁾		1,552,804		1,553		1,554,357		^*
James A. Hughes⁽²⁾		4,051		22,595		26,646		^*
Robert Barnes⁽³⁾		270		1,386		1,656		^*
Philippe A. Bodson⁽⁴⁾		35,947		1,386		37,333		^*
George P. Kay		—		—		—		—
Henri Philippe Reichstul⁽⁵⁾		32,406		1,219		33,625		^*
Robert E. Wilhelm⁽⁶⁾		37,257		1,553		38,810		^*
Wilfried E. Kaffenberger		—		—		—		—
Julian Green		—		—		—		^*
Eduardo Pawluszek⁽⁷⁾		220		1,209		1,429		^*
Maureen J. Ryan⁽⁸⁾		3,021		18,619		21,640		^*
Emilio Vicens⁽⁹⁾		1,474		8,877		10,351		^*
Laura C. Fulton⁽¹⁰⁾		246		1,848		2,094		^*
Andrew Parsons⁽¹¹⁾		40,516		6,044		46,560		^*
Brian Zatarain⁽¹²⁾		17,942		4,380		22,322		^*
Brian Stanley⁽¹³⁾		72,284		8,408		80,692		^*
All Directors and Executive Officers as a Group		1,798,438		79,077		1,877,515		^*


⁽¹⁾		1,552,804 shares are vested and 2,300 shares are unvested. 1,553 options are vested and 13,243 options are unvested. 1,130 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 423 options have an exercise price of $16.00/share and an expiration date of 2/22/2018
⁽²⁾		4,051 shares are vested and 42,174 shares are unvested. 22,595 options are vested and 246,632 option are unvested. 12,917 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 9,678 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽³⁾		270 shares are vested and 2,053 shares are unvested. 1,386 options are vested and 11,824 options are unvested. 1,008 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 378 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽⁴⁾		35,947 shares are vested and 2,053 shares are unvested. 1,386 options are vested and 11,824 options are unvested. 1,008 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 378 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽⁵⁾		32,406 shares are vested and 1,806 shares are unvested. 1,219 options are vested and 10,406 options are unvested. 887 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 332 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽⁶⁾		37,257 shares are vested and 2,300 shares are unvested. 1,553 options are vested and 13,243 options are unvested. 1,130 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 423 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽⁷⁾		220 shares are vested and 4,640 shares are unvested. 1,209 options are vested and 28,143 options are unvested. 1,209 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽⁸⁾		3,021 shares are vested and 20,619 shares are unvested. 18,619 options are vested and 115,273 options are unvested. 15,716 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 2,903 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽⁹⁾		1,474 shares are vested and 12,196 shares are unvested. 8,877 options are vested and 69,556 options are unvested. 6,458 options have an exercise price of $13.60/share and an expiration date of 9/13/2014. 2,419 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽¹⁰⁾		246 shares are vested and 6,192 shares are unvested. 1,848 options are vested and 37,198 options are unvested. 1,848 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽¹¹⁾		40,516 shares are vested and 12,767 shares are unvested. 6,044 options are vested and 58,655 options are unvested. 3,625 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 2,419 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽¹²⁾		17,942 shares are vested and 7,828 shares are unvested. 4,380 options are vested and 45,691 options are unvested. 2,687 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 1,693 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.
⁽¹³⁾		72,284 shares are vested and 11,695 shares are unvested. 8,408 options are vested and 66,841 options are unvested. 6,158 options have an exercise price of $11.18/share and an expiration date of 2/28/2014. 2,250 options have an exercise price of $16.00/share and an expiration date of 2/22/2018.


*		Owns less than 1.00% based on the total number of outstanding shares of 244,117,724 as of the date of this prospectus.

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

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of participants under the 2007 Incentive Plan, a maximum of 15,660,340 shares of ordinary shares are available for grants of all equity awards under the 2007 Incentive Plan. Unless the administration of the 2007 Incentive Plan has been expressly assumed by the board pursuant to a resolution of the board, the compensation committee has full authority and discretion to administer the 2007 Incentive Plan and to take any action that is necessary or advisable in connection with the administration of the 2007 Incentive Plan. The 2007 Incentive Plan may be amended from time to time by the compensation committee or the board. Neither the compensation committee nor the board will authorize the amendment of any outstanding option to reduce the option price without the further approval of our shareholders. Furthermore, no share option will be cancelled and replaced with share options having a lower price without further approval of our 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%.

Grants to Employees and Directors

The compensation committee and the board of directors have approved a one-time, special grant of ordinary shares following completion of this offering to certain employees, including our executive officers, and to independent directors. The total dollar value of the grant, which will be made under our 2007 Incentive Plan, will be $7,997,880 and the aggregate number of ordinary shares to be granted will be 533,192, which is based on the mid-point of the range set forth on the cover page of this prospectus.

The ordinary shares granted will vest over the schedule described in “— AEI 2007 Incentive Plan” beginning on the date of grant. The grants are intended to reward these employees and independent directors for their prior service with our company and their efforts in connection with this offering, to encourage performance following the completion of this offering and to align the interests of our executive officers with those of our shareholders.

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 company and personal 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 restricted share units, 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. One executive officer in Poland as well as certain other employees in Poland and Turkey have been awarded share appreciation rights under the 2007 Incentive Plan.

Stock Ownership Plan

Our compensation committee is evaluating the possibility of adopting a stock ownership plan for executive officers which would require a minimum ownership amount of our ordinary shares. No firm proposal has been put forward by the compensation committee to the board as yet and there is no assurance a stock ownership plan in any form will be adopted.

Employment Agreements

We have not entered into employment agreements with any of our executive officers.

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PRINCIPAL AND SELLING SHAREHOLDERS

The following table sets forth information with respect to the beneficial ownership of our ordinary shares, as of the date of this offering, and as adjusted to reflect the sale of the ordinary shares offered in this offering for:


	•	each person known to us to own beneficially more than 5% of our ordinary shares; and

	•	each selling shareholder participating in this offering.

If one or more of the selling shareholders determines not to sell in this offering, the Ashmore Funds or another of the selling shareholders may decide, but are not obligated, to increase the amount of ordinary shares they sell in this offering.

The selling shareholders have generally acquired the shares that are being sold pursuant to this registration statement in privately negotiated transactions either for cash, the contribution of assets or in exchange for debt. In addition, some selling shareholders acquired shares from former shareholders.

The table below does not reflect the exercise of the underwriters’ option to purchase up to an additional 7,500,000 ordinary shares, which would be sold by the selling shareholders on a pro rata basis. The total number of outstanding shares as of the date of this prospectus is 244,117,724.


	Ordinary Shares Held by Principal and Selling Shareholders
						Ordinary
						Shares to be
						Sold by Selling
	Ordinary Shares Beneficially					Shareholders		Ordinary Shares Beneficially
	Owned Prior to this Offering					in this Offering		Owned After this Offering
	Number		Percent			Number		Number		Percent

Ashmore Cayman SPC No. 3 Limited on behalf of and for the account of AEI Segregated Portfolio⁽¹⁾⁽²⁾		20,865,705		8.55	%		4,240,295		16,625,410		6.38	%
Ashmore Global Special Situations Fund 2 Limited⁽¹⁾⁽³⁾		13,169,905		5.39	%		8,096,173		5,073,731		1.95	%
Ashmore Global Special Situations Fund 3 Limited Partnership⁽¹⁾⁽³⁾		23,013,134		9.43	%		—		23,013,134		8.82	%
Ashmore Global Special Situations Fund 4 Limited Partnership⁽¹⁾⁽³⁾		10,977,303		4.50	%		—		10,977,303		4.21	%
Ashmore Global Special Situations Fund 5 Limited Partnership⁽¹⁾⁽³⁾		1,000,000		0.41	%		—		1,000,000		0.38	%
Ashmore SICAV Emerging Markets Debt Fund⁽¹⁾⁽³⁾		4,263,396		1.75	%		—		4,263,396		1.63	%
Ashmore Global Opportunities Limited⁽¹⁾⁽³⁾		6,237,039		2.55	%		—		6,237,039		2.39	%
Asset Holder PCC Limited in respect of Ashmore Emerging Markets Liquid Investment Portfolio⁽¹⁾⁽³⁾		1,325,066		0.54	%		218,528		1,106,538		0.42	%
EMDCD Ltd.⁽¹⁾⁽⁴⁾		5,091,645		2.09	%		3,623,823		1,467,822		0.56	%
Ashmore Emerging Markets Global Investment Portfolio Limited⁽¹⁾⁽³⁾		1,435,248		0.59	%		—		1,435,248		0.55	%
FCI Ltd.⁽¹⁾⁽²⁾		44,028,859		18.04	%		7,261,174		36,767,685		14.10	%
Ashmore Growing Multi Strategy Fund Limited⁽¹⁾⁽³⁾		1,005,938		0.41	%		—		1,005,938		0.39	%
Ashmore Emerging Markets Debt and Currency Fund⁽¹⁾⁽³⁾		1,233,864		0.51	%		—		1,233,864		0.47	%

Total Ashmore Funds		133,647,102		54.75	%		23,439,993		110,207,109		42.26	%

Buckland Investment Pte Ltd.⁽⁵⁾		54,588,392		22.36	%		—		54,588,392		20.93	%
Sherbrooke, Ltd.⁽⁶⁾		13,931,097		5.71	%		2,374,871		11,556,226		4.43	%
CVI GVF (Lux) Master S.a.r.l⁽⁷⁾		8,964,174		3.67	%		1,910,183		7,053,991		2.70	%
Investment Partners (B) Ltd.⁽⁸⁾		1,534,489		0.63	%		326,986		1,207,503		0.46	%
Finisterre Special Situations Master Fund⁽⁹⁾		378,832		0.16	%		80,726		298,106		0.11	%
Goldman Sachs & Co.⁽¹⁰⁾		4,573,841		1.87	%		974,644		3,599,197		1.38	%
Ashfield Investments N.V. ⁽¹¹⁾		568,248		0.23	%		121,088		447,160		0.17	%
Montpelier Global Funds Ltd.⁽¹²⁾		2,272,991		0.93	%		484,354		1,788,637		0.69	%
LM Moore SP Investments LTD.⁽¹³⁾		1,894,159		0.78	%		403,628		1,490,531		0.57	%
Old Lane HMA Master Fund, LP⁽¹⁴⁾		216,595		0.09	%		46,154		170,441		0.07	%
Old Lane Cayman Master Fund, LP⁽¹⁴⁾		763,848		0.31	%		162,769		601,079		0.23	%
Old Lane US Master Fund, LP⁽¹⁵⁾		301,181		0.12	%		64,179		237,002		0.09	%
TRG Global Opportunity Master Fund, Ltd.⁽¹⁶⁾		2,802,813		1.15	%		597,254		2,205,559		0.85	%
TRG Special Opportunity Master Fund, Ltd. ⁽¹⁶⁾		3,711,908		1.52	%		790,974		2,920,934		1.12	%
VR Global Partners LP⁽¹⁷⁾		439,719		0.18	%		93,700		346,019		0.13	%
Castlerigg LATAM Investments LLC⁽¹⁸⁾		785,714		0.32	%		167,428		618,286		0.24	%
LAIG⁽¹⁹⁾		883,929		0.36	%		188,357		695,572		0.27	%
Black River Emerging Markets Credit Fund Ltd.⁽²⁰⁾		597,265		0.24	%		127,272		469,993		0.18	%
Ponderosa Assets, L.P. ⁽²¹⁾		1,228,956		0.50	%		261,879		967,077		0.37	%
D. E. Shaw Laminar Portfolios, L.L.C. ⁽²²⁾		2,707,265		1.11	%		576,893		2,130,372		0.82	%
D. E. Shaw Laminar Emerging Markets, L.L.C.⁽²³⁾		407,641		0.17	%		86,864		320,777		0.12	%
GPU Argentina Holdings, Inc. ⁽²⁴⁾		249,363		0.10	%		53,137		196,226		0.08	%


(1)		These funds have directly or indirectly appointed Ashmore as their investment manager. Ashmore’s parent company is Ashmore Group plc, a public company.

(2)		The address of Ashmore Cayman SPC No. 3 Limited on behalf of and for the account of AEI Segregated Portfolio and FCI Ltd. is c/o International Management Services Ltd, Harbour Centre, 4th Floor, North Church Street, P.O. Box 61GT, George Town, Grand Cayman, Cayman Islands.

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(3)		The address of Ashmore Global Special Situations Fund 2 Limited, Ashmore Global Special Situations Fund 3 Limited Partnership, Ashmore Global Special Situations Fund 4 Limited Partnership, Ashmore Global Special Situations Fund 5 Limited Partnership, Ashmore SICAV Emerging Markets Debt Fund, Ashmore Global Opportunities Limited, Asset Holder PCC Limited in respect of Ashmore Emerging Markets Liquid Investment Portfolio, Ashmore Emerging Markets Global Investment Portfolio Limited, Ashmore Growing Multi Strategy Fund Limited and Ashmore Emerging Markets Debt and Currency Fund is Trafalgar Court, Les Banques, St. Peter Port, Guernsey GYI 3QL.

(4)		The address of EMDCD Ltd. is c/o M & C Corporate Services, P.O. Box 309GT, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands, British West Indies.

(5)		The address of Buckland Investment Pte Ltd. is 168 Robinson Road, #37-01 Capital Tower, Singapore, 068912, Singapore. Buckland Investment Pte Ltd shares the power to vote and the power to dispose of the shares with each of GIC Special Investments Pte Ltd and the Government of Singapore Investment Corporation Pte Ltd., each of which is a Singapore private limited company. No individual has beneficial ownership over these shares. Voting and investment decisions relating to these shares are made by the GIC Special Investments Pte Ltd. investment committee, which is currently comprised of eight members: Teh Kok Peng, Ng Kin Sze, Ang Eng Seng, Kunna Chinniah, Tay Lim Hock, Eugene Wong, John Tang and Mayukh Mitter. The investment committee acts by majority vote and no member may act individually to vote or sell these shares. Beneficial ownership is disclaimed by the investment committee and its members. Each of the reporting persons disclaim beneficial ownership of the shares, except to the extent of their pecuniary interest therein.

(6)		The address of Sherbrooke, Ltd. is c/o Walkers Corporate Services Limited, Walkers House, P.O. Box 908GT, Mary Street, Grand Cayman, Cayman Islands. Eton Park Capital Management, L.P. is the investment manager for Sherbrooke, Ltd. Eric M. Mindich controls Eton Park Capital Management, L.P. as the managing member of its general partner, Eton Park Capital Management, L.L.C.

(7)		The address of CVI GVF (Lux) Master S.a.r.l is 11-13 Boulevard de la Foire, L-1528 Luxembourg, Luxembourg. John Brice, Mirko Fischer, David Fry, Patrick Lsurger and Peter Vorbrich exercise voting control for CVI GVF (Lux) Master Sarl.

(8)		The address of Investment Partners (B) Ltd. is c/o Maples Corporate Services Limited, P.O. 309, Ugland House, Grand Cayman KY1-1104, Cayman Islands. The investment manager of Investment Partners (B), Ltd. is BlackRock Financial Management, Inc., which is a wholly-owned subsidiary of BlackRock, Inc., a publicly traded corporation.


(9)		The address of Finisterre Special Situations Master Fund is P.O. Box 309, Ugland House, South Church Street, Georgetown, Cayman Islands. Finisterre Special Situations Master Fund is managed by Finisterre Capital LLP, represented by Rafaël Biosse Duplan, a partner of Finisterre Capital LLP and the portfolio manager of Finisterre Special Situations Master Fund.


(10)		The address of Goldman Sachs & Co. is 1 New York Plaza, New York, New York 10004. Goldman Sachs & Co. is a broker-dealer and an underwriter with respect to the shares that it is offering for resale. Goldman Sachs & Co. is a wholly owned subsidiary of The Goldman Sachs Group, Inc., an SEC reporting company.


(11)		The address of Ashfield Investments N.V. is Schottegatweg Oost 28, P.O. Box 3700, Curacao, Netherlands Antilles. Montpelier Investment Management LLP exercises voting control over Ashfield Investments N.V. Montpelier Asset Management Limited which is beneficially owned by Nicholas Cournoyer has the majority of the voting rights in Montpelier Investment Management LLP.


(12)		The address of Montpelier Global Funds Ltd. is c/o Montpelier Investment Management LLP, 243 Knightsbridge, London SW7 1DN United Kingdom. Montpelier Investment Management LLP exercises voting control over Montpelier Global Funds Ltd. Montpelier Asset Management Limited which is beneficially owned by Nicholas Cournoyer has the majority of the voting rights in Montpelier Investment Management LLP.


(13)		The address of LM Moore SP Investments Ltd. is c/o Moore Capital Management, LP, 1251 Avenue of the Americas, 52nd Floor, New York, New York 10020. The investment manager of LM Moore SP Investments Ltd. is Moore Capital Management, LP. Louis Moore Bacon is the controlling shareholder of the general partner of Moore Capital Management, LP.


(14)		The address of Old Lane HMA Master Fund, LP and Old Lane Cayman Master Fund, LP is c/o M & C Corporate Services, P.O. Box 309GT, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands, British West Indies. Old Lane HMA Master Fund, LP and Old Lane Cayman Master Fund,

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		LP are affiliates of Citigroup Global Markets Inc., a broker-dealer and an underwriter with respect to the offering to which this prospectus relates. Citigroup Alternative Investments LLC, a wholly-owned subsidiary of Citigroup Inc., a public company, controls the general partner of and serves as investment manager to Old Lane HMA Master Fund, LP and Old Lane Cayman Master Fund, LP. Old Lane HMA Master Fund, LP and Old Lane Cayman Master Fund, LP acquired the shares to be resold in the ordinary course of business and at the time of the purchase, had no agreements or understandings directly or indirectly to distribute them.


(15)		The address of Old Lane US Master Fund, LP is 399, Park Avenue, New York, New York 10043. Old Lane US Master Fund, LP is an affiliate of Citigroup Global Markets Inc., a broker-dealer and an underwriter with respect to the offering to which this prospectus relates. Citigroup Alternative Investments LLC, a wholly-owned subsidiary of Citigroup Inc., a public company, controls the general partner of and serves as investment manager to Old Lane HMA Master Fund, LP and Old Lane Cayman Master Fund, LP. Old Lane US Master Fund, LP acquired the shares to be resold in the ordinary course of business and, at the time of the purchase, had no agreements or understandings directly or indirectly to distribute them.


(16)		The address of TRG Global Opportunity Master Fund, Ltd. and TRG Special Opportunity Master Fund, Ltd. is Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands. TRG Management LP controls TRG Global Opportunity Master Fund Ltd and TRG Special Opportunity Master Fund Ltd. through an investment management agreement. Nicolás Rohatyn is the beneficial owner of more than 10% TRG Management LP.


(17)		The address of VR Global Partners LP is Aurora Business Park, 77, Sadovnicheskaya nab., bld. 1, Moscow 115035. Richard Deitz exercises sole voting power for VR Global Partners LP.


(18)		The address of Castlerigg LATAM Investments LLC is c/o Sandell Asset Management Corporation, 40 West 57th Street, 26th Floor, New York, New York 10019. Sandell Asset Management Corp. (“SAMC”) is the investment manager of Castlerigg Master Investments Ltd. (“Castlerigg”). Castlerigg is the controlling shareholder of Castlerigg LATAM Investments LLC. Thomas Sandell is the controlling person of SAMC and may be deemed to share beneficial ownership of the shares beneficially owned by Castlerigg. Castlerigg International Ltd. (“Castlerigg International”) is the controlling shareholder of Castlerigg International Holdings Limited (“International Holdings”) and Castlerigg GS Holdings, Ltd. (“GS Holdings”). International Holdings and GS Holdings are the beneficial owners of Castlerigg Offshore Holdings, Ltd. (“Offshore Holdings”). Offshore Holdings is the controlling shareholder of Castlerigg. Each of International Holdings, GS Holdings, Offshore Holdings and Castlerigg International may be deemed to share beneficial ownership of the shares beneficially owned by Castlerigg Master Investments Ltd. SAMC, Mr. Sandell, International Holdings, GS Holdings, Offshore Holdings and Castlerigg International each disclaims beneficial ownership of the securities with respect to which indirect beneficial ownership is described.


(19)		The address of LAIG is 1st Floor, Windward 1, Regatta Office Park, P.O. Box 10338, Grand Cayman, KYI-1003, Cayman Islands. Jorge de Pablo exercises voting control over LAIG.


(20)		The address of Black River Emerging Markets Credit Fund Ltd. is c/o Black River Asset Management LLC, 12700 Whitewater Drive, Minnetonka, Minnesota 55343-9438. The advisory company for Black River Emerging Markets Credit Fund Ltd. is Black River Asset Management LLC. Dan Chapman is the portfolio manager and exercises voting control.


(21)		The address of Ponderosa Assets, L.P. (“Ponderosa”) is c/o Citibank, N.A., 388 Greenwich Street, New York, New York 10013. Ponderosa is managed by Citibank, N.A. as sole portfolio manager. Citibank, N.A. and Citigroup Global Markets, Inc., a broker-dealer and one of the underwriters of this offering, are affiliates of Citigroup, an SEC reporting company. On September 3, 2009, AEI LLC, an affiliate of AEI, entered into an agreement with Ponderosa and one of its subsidiaries, pursuant to which Ponderosa granted to AEI LLC an option to acquire all of the outstanding shares of Enron Pipeline Company Argentina S.A., an Argentine corporation, and certain rights and obligations relating thereto, for $3,000,000, which is payable by delivery to Ponderosa of 202,020 ordinary shares of AEI. The option expires on December 3, 2010, or earlier upon the occurrence of certain events. Exercise of the option is conditional on, among other things, obtaining certain Argentine government approvals. Ponderosa acquired the ordinary shares when it sold to us Ponderosa’s economic rights in a certain litigation claim for cash and our ordinary shares. At the time Ponderosa acquired the ordinary shares, it had no agreements or understandings directly or indirectly to distribute them.


(22)		The address of D. E. Shaw Laminar Portfolios, L.L.C. is 120 West 45th Street, 39th Floor, New York, NY 10036. D. E. Shaw & Co., L.P., as investment adviser, has voting and investment control over the AEI shares beneficially owned by D. E. Shaw Laminar Portfolios, L.L.C. Anne Dinning, Julius Gaudio, Lou Salkind, Maximilian Stone and Eric Wepsic, or their designees, exercise voting and investment control over such shares on D. E. Shaw & Co., L.P.’s behalf. D. E. Shaw Laminar Portfolios, L.L.C. is an affiliate of D. E. Shaw Securities, L.L.C., a broker-dealer. D. E. Shaw Laminar Portfolios, L.L.C. is an affiliate of D. E. Shaw Laminar Emerging Markets, L.L.C. D. E. Shaw Laminar Portfolios, L.L.C. acquired the ordinary shares to be resold in the ordinary course of business and, at the time of the purchase, had no agreements or understandings directly or indirectly to distribute them.


(23)		The address of D. E. Shaw Laminar Emerging Markets, L.L.C. is 120 West 45th Street, 39th Floor, New York, NY 10036. D. E. Shaw & Co., L.P., as investment adviser, has voting and investment control over the shares beneficially owned by D. E. Shaw Laminar Emerging Markets, L.L.C. Anne Dinning, Julius Gaudio, Lou Salkind, Maximilian Stone and Eric Wepsic, or their designees, exercise voting and investment control over such shares on D. E. Shaw & Co., L.P.’s behalf. D. E. Shaw Laminar Emerging Markets, L.L.C. is an affiliate of D. E. Shaw Laminar Portfolios, L.L.C. D. E. Shaw Laminar Emerging Markets, L.L.C. is an affiliate of D. E. Shaw Securities, L.L.C., a broker-dealer. D. E. Shaw Laminar Emerging Markets, L.L.C. acquired the ordinary shares to be resold in the ordinary course of business and, at the time of the purchase, had no agreements or understandings directly or indirectly to distribute them.


(24)		The address of GPU Argentina Holdings, Inc. is Av. De Libertador 498 7° piso, C.A.B.A. (1001), Buenos Aires, Argentina. Enrique Wifredo Ruete Aguirre exercises voting control over the shares held by GPU Argentina Holdings, Inc.

As of the date of this prospectus, 5.5% of our outstanding ordinary shares are held by 109 record holders in the United States.

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RELATED PARTY TRANSACTIONS

See “Underwriting” for a description of our relationships with the underwriters.

Ashmore Management Services Agreement

Effective May 20, 2006, we entered into a management services agreement with Ashmore for the provision of certain services, including operational, administrative and technical services. To date, Ashmore has provided services with respect to strategic and development activities and we expect they will continue to provide similar services in the future.

The management services agreement provides for successive one-year terms and is automatically renewed in May each year unless terminated. The management services agreement may be terminated by either party 30 days prior to the end of a term. During the term, we may terminate upon 90 days’ written notice generally or 14 days’ written notice for a particular subsidiary if there has been a sale or change of control of such subsidiary. In addition, we may terminate for non-performance by Ashmore. Ashmore may terminate if we fail to pay invoices within 60 days of the invoice date.

Under the management services agreement, we must pay to Ashmore the actual costs of employees performing the services (including salary, bonus, benefits and long-term incentive grants) and reasonable and documented expenses, such as travel costs and the services of third party professionals. The aggregate maximum amount of fees that may be paid under the agreement during each one-year term is $4.5 million. We have paid Ashmore $3.5 million and $4.5 million, respectively, under this agreement in each of the last two one-year terms. The majority of the amounts were for services provided with respect to strategic and business development activities.

PIK Notes

On May 24, 2007, we completed the redemption of our $527 million subordinated PIK Notes, plus $52 million in accrued interest and issued new subordinated PIK Notes in the aggregate principal amount of $300 million. Several of our shareholders hold some of the new subordinated PIK Notes.

On March 11, 2009, we amended the note purchase agreement in order to issue an option to all of our PIK note holders to exchange their PIK notes for our ordinary shares. The option period is for up to one year. The initial exchange rate is 63 ordinary shares per $1,000 for each principal amount of PIK notes exchanged. This rate adjusts downward relative to the increase of interest on the notes. Additionally, the amendment allows us to purchase the PIK notes in the open market, subject to certain conditions. In March, August and October 2009, various Ashmore Funds exercised their option to convert their PIK notes and related interest receivable in the amount of $118 million for 7,412,142 ordinary shares, $57 million for 3,438,069 ordinary shares and $21 million for 1,233,864 ordinary shares, respectively.

Familial Relationships

The wife of the former Vice Chairman of our board of directors was previously a senior vice president of PEI. She currently is providing services to us for a transaction under a consulting agreement pursuant to which she receives a fixed fee and potentially a success fee. We paid her approximately $358,000 in 2008 and approximately $218,000 through June 30, 2009.

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DESCRIPTION OF SHARE CAPITAL

The following is a brief description of our share capital. As of the date of this prospectus, an aggregate of 244,117,724 ordinary shares were issued and outstanding. Shareholders approved a five for one stock split on December 20, 2007. Our ordinary shares are registered pursuant to Section 12(g) of the Exchange Act pursuant to a registration statement on Form 20-F which became effective on March 31, 2009.

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, or the Articles, and to the relevant provisions of the Companies Law (2007 Revision) of the Cayman Islands.

Ordinary Shares

Our Articles 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. The ordinary shares in the capital of the company are registered shares. We are not permitted by the laws of the Cayman Islands to issue bearer shares. Absent anything to the contrary contained in our Articles, there are no restrictions on the free transferability of ordinary shares in respect of exempted companies incorporated in the Cayman Islands.

The only issued and outstanding class of shares in the capital of the company are ordinary shares, all of which permit the holders to receive notice of, attend and vote at our general meetings.

Meetings

Pursuant to our Articles, we are required to convene an annual general meeting of shareholders at least once in each calendar year at such time and place as our directors appoint, provided that the period between the date of one annual general meeting and that of the next will not be longer than the period permitted by the rules and regulations applicable to the listing of the ordinary shares on the New York Stock Exchange.

In addition, any of our director may convene an extraordinary general meeting to be held at such time and place as the directors appoint. The directors shall, upon the requisition in writing of one or more shareholders holding in the aggregate not less than 20% of our total paid-up share capital as at the date of the requisition carries the right of voting at general meetings, convene an extraordinary general meeting and in the event that the directors fail to convene any such meeting, such shareholders shall be entitled to convene such a meeting.

The Board may, in its sole discretion, determine that a general meeting shall not be held at any place, but may instead be held solely by means of remote communication that enables shareholders and proxies entitled to attend and vote at the meeting to listen to the meeting or to watch and listen the meeting and, in either case, to participate fully in the deliberations of the meeting including to be able to submit questions to the chairman of the meeting which, if deemed appropriate, may be addressed at the meeting.

Ten days prior notice at the least specifying the place, the day and the hour of meeting and, in the case of special business, the general nature of that business shall be given as follows: we may give notice to any shareholder either personally or by sending it by post, telex, telefax or electronic mail to such shareholder at its registered address as shown in the Register of Members (or where the notice is given by electronic mail by sending it to the e-mail address provided by such member for the purpose).

Dividends

Holders of ordinary shares are entitled to dividends as and when declared, subject to any provisions set forth in our Articles. 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 our dividend policy, see “Dividend Policy.”

For a description of laws or regulations affecting dividends and other payments in respect of the ordinary shares, see “Taxation.”

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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. There are no provisions that grant major shareholders different voting rights in respect of the shares held by them, or that restrict minor shareholders from exercising the voting rights in respect of the shares held by them.

After completion of this offering, the Ashmore Funds will own approximately 42.26% of our outstanding ordinary shares, or 39.11% if the underwriters’ option to purchase additional shares is exercised in full. As a result, after completion of this offering, the Ashmore Funds will continue to be able to significantly influence the management and affairs of our company in all matters requiring shareholder approval, including the election of our board of directors and significant corporate transactions.

Directors

Our Articles 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 “Management” for further information regarding the board of directors.

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.

The actions relevant to the variation of specific class rights attaching to shares in the capital of the company are set out in our Articles, which provide that any variation to our Articles generally (or the rights of a particular class of shares specifically) requires the adoption of a special resolution of the shareholders (or of the particular class, as the case may be), being either (a) a resolution passed at a meeting of shareholders by three quarters of the votes represented at such meeting; or (b) a unanimous written resolution of all shareholders.

Rights in a Winding-Up

Subject to the provisions set forth in our Articles, 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.

Additional Issuances of Ordinary Shares

As of the date of this offering, there were 4,755,882,276 authorized but unissued ordinary shares, including 10,556,665 ordinary shares reserved for issuance under our equity incentive plans and 10,504,986 ordinary shares reserved for PIK Notes exchange. For more information about these plans, see Note 23 to the consolidated financial statements for the year ended December 31, 2008 included in this prospectus. 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 Articles, 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 Articles, our board of directors may, without shareholder action, issue ordinary shares out of the already existing authorized share capital.

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Transfer Agent and Registrar

Computershare Trust Company, N.A. 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.

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 “Enforcement of Civil Liabilities” and “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.

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ORDINARY SHARES ELIGIBLE FOR FUTURE SALE

Upon completion of this offering, we will have issued and outstanding 260,784,391 ordinary shares.

Lock-up Agreements

In connection with this offering, we have agreed for a period of time which will run from the date of the final prospectus and continue for 180 days after the date of the final prospectus, or such earlier date that Goldman, Sachs & Co. and Credit Suisse Securities (USA) LLC consent to in writing, not to (i) offer, sell, issue, contract to sell, pledge or otherwise dispose of our ordinary shares or securities convertible into or exchangeable or exercisable for any of our ordinary shares, (ii) offer, sell, issue, contract to sell, contract to purchase or grant any option, right or warrant to purchase any of our ordinary shares or securities convertible into or exchangeable or exercisable for any of our ordinary shares, (iii) enter into any swap, hedge or any other agreement that transfers, in whole or in part, the economic consequences of ownership of any of our ordinary shares or securities convertible into or exchangeable or exercisable for any of our ordinary shares, (iv) establish or increase a put equivalent position or liquidate or decrease a call equivalent position in any of our ordinary shares or securities convertible into or exchangeable or exercisable for any of our ordinary shares within the meaning of Section 16 of the Exchange Act or (v) file with the SEC a registration statement under the Securities Act relating to any of our ordinary shares or securities convertible into or exchangeable or exercisable for any of our ordinary shares, or (vi) publicly disclose our intention to make any offer, sale, issue, contract to sell, pledge, disposition or filing, without the prior written consent of Goldman, Sachs & Co., subject to certain exceptions; provided, however, that if (1) during the last 17 days of the 180-day period (as described above), we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the 180-day period (as described above), we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period (as described above), then in each case the 180-day period (as described above) will be extended until the expiration of the 18-day period beginning on the date of release of the earnings results or the occurrence of the materials news or material event, as applicable. See “Underwriting.”

Each of the selling shareholders, members of the board of directors, executive officers and certain non-selling shareholders has entered into a similar lock-up agreement. As a result of discussions with the underwriters, we determined that the following non-selling shareholders would be subject to lock-up provisions: all executive officers and directors, parties to our existing registration rights agreement (described below) and any affiliate of an underwriter currently holding ordinary shares. The lock-up agreements for legal entities are subject to certain exceptions for corporate actions, such as transfers to affiliates and permitted transferees and the lock-up agreements for natural persons are subject to certain exceptions, such as payment of taxes in respect of grants.

Other than this offering, we are not aware of any plans by any significant shareholders to dispose of significant numbers of our ordinary shares. However, one or more existing shareholders or owners of securities convertible or exchangeable into or exercisable for our ordinary shares may dispose of significant numbers of our ordinary shares. We cannot predict what effect, if any, future sales of our shares, or the availability of ordinary shares for future sale, will have on the market price of our ordinary shares from time to time.

Existing Registration Rights Agreement

We are party to an existing registration rights agreement, dated December 29, 2006, which provides the holders of our ordinary shares party to the agreement (our Existing 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, at any time six months after the effective date of our initial public offering, a written request from Existing Investors holding 7.5% or more of the ordinary shares subject to the agreement (referred to therein as Registrable Securities), 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 Existing 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 Existing 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,

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TAXATION

The following is a general summary of the material Cayman Islands and U.S. federal income tax consequences relevant to an investment in 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 (“Clifford Chance”). 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, partners in partnerships that invest in ordinary shares, holders who are not U.S. Holders, holders who own (directly or through attribution) 10% or more of our ordinary shares, investors that will hold our ordinary shares as part of a straddle, hedge, conversion, constructive sale, or other integrated transaction for U.S. federal income tax purposes, or investors that have a functional currency other than the U.S. dollar, all of whom may be subject to tax rules that differ significantly from those summarized below. In addition, this summary does not discuss any non-U.S., state or local tax considerations. This summary assumes that investors will hold their ordinary shares as “capital assets” (generally, property held for

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investment) for U.S. federal income tax purposes. U.S. Holders are urged to consult their tax advisors regarding the U.S. federal, state, local and non-U.S. income and other tax considerations relevant to an investment in the ordinary shares.

For purposes of this summary, a “U.S. Holder” is a beneficial owner of ordinary shares that is for U.S. federal income tax purposes (i) an individual who is a citizen or resident of the United States, (ii) a corporation created in, or organized under the law of, the United States or any State or political subdivision thereof, (iii) an estate the income of which is includible in gross income for U.S. federal income tax purposes regardless of its source, or (iv) a trust the administration of which is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust.

Dividends

The U.S. dollar value of any distributions paid by us out of our earnings and profits, as determined under U.S. federal income tax principles, generally will be subject to tax as foreign source ordinary dividend income and will be includible in a U.S. Holder’s gross income upon receipt. Dividends received on our shares will not be eligible for the dividends received deduction generally allowed to corporations. Subject to certain limitations, dividends paid by qualified foreign corporations to certain non-corporate U.S. holders in taxable years beginning before January 1, 2011, are taxable at a favorable rate (generally 15%). A foreign corporation is treated as a qualified foreign corporation with respect to dividends paid on stock that is readily tradable on a securities market in the United States, such as the NYSE where we intend to apply to list our ordinary shares. U.S. Holders should consult their own tax advisors to determine whether the favorable rate will apply to any dividends received from AEI and whether any special rules will apply that limit their ability to be taxed at this favorable rate (including the rules described below under “Passive Foreign Investment Company Rules”).

Sale or Other Disposition of Ordinary Shares

Subject to the discussion of the passive foreign investment company rules 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. A U.S. Holder’s adjusted basis in its ordinary shares will generally equal the U.S. dollar value of the amount paid for such shares. Any capital gain or loss will be long-term capital gain or loss if the ordinary shares have been held for more than one year. The deductibility of capital losses is subject to limitations.

Passive Foreign Investment Company Rules

In general, a non-U.S. corporation is classified as a “passive foreign investment company” as defined in Section 1297 of the Internal Revenue Code of 1986, as amended (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.

Our counsel, Clifford Chance, has advised us, and has delivered an opinion that (1) AEI should not be treated as a PFIC for its most recently completed taxable year and (2) AEI should not be treated as a PFIC for its current or future taxable years. This opinion is based on, and its validity is conditioned on the accuracy of, representations made by us to Clifford Chance regarding our income, assets and operations. Among other representations that we have made, we have represented that we expect that in the future, the relative fair market

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value of our assets that produce or are held for the production of “passive income” will not change materially compared to the fair market value of our other assets, and we have also represented that we expect that in the future the nature of our business operations and the composition of our income and assets will not change materially. Clifford Chance’s opinion is based on, and the validity of its opinion is conditioned on, an assumption that our expectations will prove to be accurate as well as certain other assumptions.

Due to the nature of the PFIC rules, Clifford Chance is only able to opine that AEI should not be treated as a PFIC for AEI’s most recently completed taxable year or for AEI’s current or future taxable years. Clifford Chance’s opinion is not unqualified for two principal reasons. First, the PFIC rules are fact-intensive: they depend, to a significant extent, on the particular facts relating to AEI’s assets and income in 2008 and 2009 (a year which is not yet completed), as well as AEI’s assets and income in future periods. Second, there is little direct legal authority regarding how the PFIC statute applies to AEI and other companies. The PFIC statute was enacted in largely its current form over 20 years ago, and the Treasury Department has issued no regulations that apply the statutory definition of a PFIC to any type of companies, other than proposed regulations that (if finalized) would apply to banks, securities brokers and dealers and similar financial institutions. In addition, the Internal Revenue Service (the “IRS”) has issued little administrative guidance relating to PFICs. Nor have courts provided a body of case law regarding PFICs. Clifford Chance is not, as of the date hereof, aware of legal authority on point that is contradictory to its conclusion.

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 a special interest charge on any gain from the sale or other disposition of the ordinary shares and being subject to additional tax form filing requirements. In addition, non-corporate U.S. Holders will not be eligible for the favorable reduced rate of taxation described above (under “Dividends”) on any dividends received, if we are a PFIC in the taxable year in which such dividends are paid or in the preceding taxable year. U.S. Holders should consult their own tax advisors about the application of the PFIC rules to them, including the availability of certain elections.

Backup withholding and information reporting requirements

U.S. federal backup withholding and information reporting requirements may apply to certain payments of dividends on, and proceeds from the sale, taxable exchange or redemption of ordinary shares held by U.S. Holders. A portion of any such payment may be withheld as a backup withholding against a U.S. Holder’s potential U.S. federal income tax liability if such U.S. Holder fails to establish that it is exempt from these rules, furnish a correct taxpayer identification number or otherwise fail to comply with such backup withholding and information reporting requirements. Corporate U.S. Holders are generally exempt from the backup withholding and information requirements, but may be required to comply with certification and identification requirements in order to establish their exemption. Any amounts withheld under the backup withholdings rules from a payment to a U.S. Holder will be credited against such U.S. Holder’s U.S. federal income tax liability, if any, or refunded if the amount withheld exceeds such tax liability, provided the required information is furnished to the Internal Revenue Service.

The above summary is not intended to constitute a complete analysis of all U.S. federal income tax consequences to a U.S. Holder of acquiring, holding, and disposing of, ordinary shares. U.S. Holders should consult their own tax advisors with respect to the U.S. federal, state, local and non-U.S. consequences of acquiring, holding and disposing of ordinary shares.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated , 2009, we and the selling shareholders have agreed to sell to the underwriters named below, for whom Goldman, Sachs & Co., Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and J.P. Morgan Securities Inc. are acting as Representatives and joint book running managers, or the Representatives, the following respective numbers of ordinary shares opposite their names below:


	Number of
Underwriter	Ordinary Shares

Goldman, Sachs & Co.
Credit Suisse Securities (USA) LLC
Citigroup Global Markets Inc.
J.P. Morgan Securities Inc.
Itaú USA Securities, Inc.
Deutsche Bank Securities Inc.
Morgan Stanley & Co. Incorporated
UBS Securities LLC

Total		50,000,000

The underwriters are committed to take and pay for all of the shares being offered, if any are taken, other than the shares covered by the option described below unless and until this option is exercised. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

If the underwriters sell more shares than the total number set forth in the table above, the underwriters have an option to buy up to an additional 7,500,000 shares from the selling shareholders. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above.

The underwriters propose to offer the ordinary shares initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $ per share. After the initial public offering the Representatives may change the public offering price. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The following table summarizes the compensation and estimated expenses we and the selling shareholders will pay to the underwriters, based on discounts and commissions of %, assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares:

Per Share

Total

No Exercise

Full Exercise

No Exercise

Full Exercise

Underwriting discounts and commissions paid by us

Expenses payable by us

Underwriting discounts and commissions paid by selling shareholders

Expenses payable by the selling shareholders

In connection with this offering, we will reimburse the underwriters for up to $175,000 of their roadshow and FINRA related expenses.

The underwriters will not confirm sales to any accounts over which they exercise discretionary authority without first receiving a written consent from those accounts.

We have agreed with the underwriters, subject to certain exceptions, not to dispose of or hedge any ordinary shares or securities convertible or exchangeable into ordinary shares during the period from the date of the final prospectus continuing through the date 180 days after the date of the final prospectus, except with the prior written consents of Goldman, Sachs & Co. and Credit Suisse Securities (USA) LLC.

Our selling shareholders, officers, directors and certain of our non-selling shareholders have agreed with the underwriters, subject to certain exceptions, not to dispose of or hedge any ordinary shares or securities

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convertible into or exchangeable for ordinary shares during the period from the date of this prospectus continuing through the date 180 days after the date of the final prospectus, except with the prior written consents of Goldman, Sachs & Co. and Credit Suisse Securities (USA) LLC.

The 180-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the 180-day restricted period we issue an earnings release or announces material news or a material event; or (2) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period following the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event, as applicable.

We and the selling shareholders have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

Our ordinary shares have been approved for listing on the NYSE, subject to official notice of issuance. In connection with the listing of the ordinary shares on the NYSE, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 2,000 beneficial holders.

Philippe A. Bodson, a member of our board of directors, is a member of the advisory board of Credit Suisse, an affiliate of Credit Suisse Securities (USA) LLC. Certain of the underwriters or their affiliates have provided advisory, banking and other financial services to us or our affiliates from time to time for which they have received customary fees and expenses. In particular, Credit Suisse Securities (USA) LLC and J.P. Morgan Securities Inc. are joint lead arrangers, joint bookrunners and joint syndication agents under our credit facility and Credit Suisse Securities (USA) LLC is the sole structuring and sole documentation agent under our credit facility. Affiliates of certain of the underwriters are lenders under our credit facility and an affiliate of Credit Suisse Securities (USA) LLC and an affiliate of J.P. Morgan Securities Inc. are the administrative agent and the collateral agent, respectively, under our credit facility. Affiliates of Citigroup Global Markets Inc. are lenders, provide standby letters of credit and other lines of credit, and serve as a trading counterparty to us and some of our subsidiaries. J.P. Morgan Securities Inc. provided valuation services to PEI in connection with its acquisition by AEIL and also provided advisory services to us in connection with our acquisition of stakes in Chilquinta and in Luz del Sur. J.P. Morgan Securities Inc. also advised the party from whom we purchased Delsur and is a counterparty to our interest rate swap agreement. An affiliate of J.P. Morgan Securities Inc. was one of the sellers of the EMDERSA shares we recently purchased, and received a portion of the purchase price in ordinary shares. Affiliates of Citigroup Global Markets Inc. advised the party from whom Elektra was acquired, provided advisory services to us in connection with our acquisition of Delsur, and advised the party from whom we purchased Chilquinta and Luz del Sur. An affiliate of Credit Suisse Securities (USA) LLC was the lender under a credit facility for one of our wholly-owned subsidiaries, which holds the interests in Luz del Sur. The facility was repaid. Affiliates of Citigroup Global Markets Inc. have also served as book-runner or arranger on several local debt offerings of Luz del Sur. Certain of the underwriters or their affiliates may in the future continue to provide advisory, banking and other financial services to us or our affiliates for which they will receive customary compensation.

Currently, affiliates of Goldman, Sachs & Co., Citigroup Global Markets Inc., J.P. Morgan Securities Inc. and Deutsche Bank Securities Inc., underwriters in this offering, own 1.87%, 0.52%, 0.27% and 0.84%, respectively, of our ordinary shares.

Prior to this offering, there has been no public market for our ordinary shares. The initial public offering price will be determined by negotiations between us and the Representatives. In determining the initial public offering price, we and the Representatives expect to consider a number of factors including:


	•	the information set forth in this prospectus and otherwise available to the Representatives;

	•	our earnings and other financial operating information in recent periods;

	•	our future prospects and the history and prospects of our industry in general;

	•	an assessment of our management;

	•	our prospects for future earnings;

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	•	the price-earnings ratios, market prices of shares, as well as financial and operating information, of other companies engaged in businesses similar to those of our company;

	•	the general condition of the securities markets, and the initial public offering market in particular, at the time of the offering; and

	•	other factors deemed relevant by the Representatives and us.

Neither we nor the Representatives can assure you that an active market will develop for our ordinary shares or that the shares will trade in the public market at or above the initial public offering price.

In connection with the offering, the underwriters may purchase and sell ordinary shares in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Shorts sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional shares from the selling shareholders in the offering. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase additional shares pursuant to the option granted to them. “Naked” short sales are any sales in excess of such option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the ordinary shares in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of ordinary shares made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the company’s stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common stock. As a result, the price of the ordinary shares may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued at any time. These transactions may be effected on the New York Stock Exchange, in the over-the-counter market or otherwise.

A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The Representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

Stamp Taxes

If you purchase ordinary shares offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Conflict of Interest

An affiliate of UBS Securities LLC owns in excess of 10% of our issued and outstanding subordinated debt in the form of PIK notes, and consequently UBS Securities LLC has a “conflict of interest” with us within the meaning of NASD Conduct Rule 2720 (“Rule 2720”) of the Financial Industry Regulatory Authority, Inc. Therefore, this offering will be conducted in accordance with Rule 2720(a)(1).

Foreign Selling Restrictions

The ordinary shares are offered for sale in those jurisdictions in the United States, Europe, Asia and elsewhere where it is lawful to make such offers.

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NOTICE TO PROSPECTIVE INVESTORS IN THE EUROPEAN ECONOMIC AREA

IN RELATION TO EACH MEMBER STATE OF THE EUROPEAN ECONOMIC AREA WHICH HAS IMPLEMENTED THE PROSPECTUS DIRECTIVE (EACH, A RELEVANT MEMBER STATE), EACH UNDERWRITER HAS REPRESENTED AND AGREED THAT WITH EFFECT FROM AND INCLUDING THE DATE ON WHICH THE PROSPECTUS DIRECTIVE IS IMPLEMENTED IN THAT RELEVANT MEMBER STATE (THE RELEVANT IMPLEMENTATION DATE) IT HAS NOT MADE AND WILL NOT MAKE AN OFFER OF SHARES TO THE PUBLIC IN THAT RELEVANT MEMBER STATE PRIOR TO THE PUBLICATION OF A PROSPECTUS IN RELATION TO THE SHARES WHICH HAS BEEN APPROVED BY THE COMPETENT AUTHORITY IN THAT RELEVANT MEMBER STATE OR, WHERE APPROPRIATE, APPROVED IN ANOTHER RELEVANT MEMBER STATE AND NOTIFIED TO THE COMPETENT AUTHORITY IN THAT RELEVANT MEMBER STATE, ALL IN ACCORDANCE WITH THE PROSPECTUS DIRECTIVE, EXCEPT THAT IT MAY, WITH EFFECT FROM AND INCLUDING THE RELEVANT IMPLEMENTATION DATE, MAKE AN OFFER OF SHARES TO THE PUBLIC IN THAT RELEVANT MEMBER STATE AT ANY TIME:

(A) TO LEGAL ENTITIES WHICH ARE AUTHORIZED OR REGULATED TO OPERATE IN THE FINANCIAL MARKETS OR, IF NOT SO AUTHORIZED OR REGULATED, WHOSE CORPORATE PURPOSE IS SOLELY TO INVEST IN SECURITIES;

(B) TO ANY LEGAL ENTITY WHICH HAS TWO OR MORE OF (1) AN AVERAGE OF AT LEAST 250 EMPLOYEES DURING THE LAST FINANCIAL YEAR; (2) A TOTAL BALANCE SHEET OF MORE THAN €43,000,000 AND (3) AN ANNUAL NET TURNOVER OF MORE THAN €50,000,000, AS SHOWN IN ITS LAST ANNUAL OR CONSOLIDATED ACCOUNTS;

(C) TO FEWER THAN 100 NATURAL OR LEGAL PERSONS (OTHER THAN QUALIFIED INVESTORS AS DEFINED IN THE PROSPECTUS DIRECTIVE) SUBJECT TO OBTAINING THE PRIOR CONSENT OF THE REPRESENTATIVES FOR ANY SUCH OFFER; OR

(D) IN ANY OTHER CIRCUMSTANCES FALLING WITHIN ARTICLE 3(2) OF THE PROSPECTUS DIRECTIVE,

PROVIDED THAT NO SUCH OFFER OF SHARES SHALL RESULT IN A REQUIREMENT FOR THE PUBLICATION BY THE COMPANY OR ANY UNDERWRITER OF A PROSPECTUS PURSUANT TO ARTICLE 3 OF THE PROSPECTUS DIRECTIVE.

FOR THE PURPOSES OF THIS PROVISION, THE EXPRESSION AN “OFFER OF SHARES TO THE PUBLIC” IN RELATION TO ANY SHARES IN ANY RELEVANT MEMBER STATE MEANS THE COMMUNICATION IN ANY FORM AND BY ANY MEANS OF SUFFICIENT INFORMATION ON THE TERMS OF THE OFFER AND THE SHARES TO BE OFFERED SO AS TO ENABLE AN INVESTOR TO DECIDE TO PURCHASE OR SUBSCRIBE THE SHARES, AS THE SAME MAY BE VARIED IN THAT RELEVANT MEMBER STATE BY ANY MEASURE IMPLEMENTING THE PROSPECTUS DIRECTIVE IN THAT RELEVANT MEMBER STATE AND THE EXPRESSION PROSPECTUS DIRECTIVE MEANS DIRECTIVE 2003/71/EC AND INCLUDES ANY RELEVANT IMPLEMENTING MEASURE IN EACH RELEVANT MEMBER STATE.

NOTICE TO PROSPECTIVE INVESTORS IN THE UNITED KINGDOM

THIS PROSPECTUS IS ONLY BEING DISTRIBUTED TO, AND IS ONLY DIRECTED AT, PERSONS IN THE UNITED KINGDOM THAT ARE QUALIFIED INVESTORS WITHIN THE MEANING OF ARTICLE 2(1)(E) OF THE PROSPECTUS DIRECTIVE THAT ARE ALSO (I) INVESTMENT PROFESSIONALS FALLING WITHIN ARTICLE 19(5) OF THE FINANCIAL SERVICES AND MARKETS ACT 2000 (FINANCIAL PROMOTION) ORDER 2005 (THE “ORDER”) OR (II) HIGH NET WORTH ENTITIES, AND OTHER PERSONS TO WHOM IT MAY LAWFULLY BE COMMUNICATED, FALLING WITHIN ARTICLE 49(2)(A) TO (D) OF THE ORDER (EACH SUCH PERSON BEING REFERRED TO AS A “RELEVANT PERSON”). THIS PROSPECTUS AND ITS CONTENTS ARE CONFIDENTIAL AND SHOULD

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NOT BE DISTRIBUTED, PUBLISHED OR REPRODUCED (IN WHOLE OR IN PART) OR DISCLOSED BY RECIPIENTS TO ANY OTHER PERSONS IN THE UNITED KINGDOM. ANY PERSON IN THE UNITED KINGDOM THAT IS NOT A RELEVANT PERSON SHOULD NOT ACT OR RELY ON THIS DOCUMENT OR ANY OF ITS CONTENTS.

NOTICE TO RESIDENTS OF THE CAYMAN ISLANDS

THIS IS NOT AN OFFER TO THE PUBLIC IN THE CAYMAN ISLANDS TO SUBSCRIBE FOR SHARES, AND APPLICATIONS ORIGINATING FROM THE CAYMAN ISLANDS WILL ONLY BE ACCEPTED FROM EXEMPTED CAYMAN ISLANDS COMPANIES, TRUSTS REGISTERED AS EXEMPTED IN THE CAYMAN ISLANDS, CAYMAN ISLANDS EXEMPTED LIMITED PARTNERSHIPS OR COMPANIES INCORPORATED IN OTHER JURISDICTIONS AND REGISTERED AS FOREIGN CORPORATIONS IN THE CAYMAN ISLANDS.

AS PART OF OUR AND THE UNDERWRITERS’ RESPONSIBILITY FOR THE PREVENTION OF MONEY LAUNDERING, WE AND THE UNDERWRITERS (INCLUDING THEIR AFFILIATES, SUBSIDIARIES OR ASSOCIATES) WILL REQUIRE A DETAILED VERIFICATION OF THE PURCHASER’S IDENTITY AND THE SOURCE OF PAYMENT. DEPENDING ON THE CIRCUMSTANCES OF EACH APPLICATION, A DETAILED VERIFICATION MIGHT NOT BE REQUIRED WHERE:

(A) THE PURCHASER IS A RECOGNIZED FINANCIAL INSTITUTION WHICH IS REGULATED BY A RECOGNIZED REGULATORY AUTHORITY AND CARRIES ON BUSINESS IN A COUNTRY LISTED IN SCHEDULE 3 OF THE MONEY LAUNDERING REGULATIONS (AS AMENDED); OR

(B) THE APPLICATION FOR ORDINARY SHARES IS MADE THROUGH A RECOGNIZED INTERMEDIARY WHICH IS REGULATED BY A RECOGNIZED REGULATORY AUTHORITY AND CARRIES ON BUSINESS IN A COUNTRY RECOGNIZED IN A SCHEDULE 3 COUNTRY. IN THIS SITUATION WE AND/OR THE UNDERWRITERS, AS APPLICABLE, MAY RELY ON A WRITTEN ASSURANCE FROM THE INTERMEDIARY THAT THE REQUISITE IDENTIFICATION PROCEDURES ON THE APPLICANT FOR BUSINESS HAVE BEEN CARRIED OUT; OR

(C) THE SUBSCRIPTION PAYMENT IS REMITTED FROM AN ACCOUNT (OR JOINT ACCOUNT) HELD IN THE PURCHASER’S NAME AT A BANK IN THE CAYMAN ISLANDS OR A BANK REGULATED IN A SCHEDULE 3 COUNTRY. IN THIS SITUATION, WE AND/OR THE UNDERWRITERS MAY REQUIRE EVIDENCE IDENTIFYING THE BRANCH OR OFFICE OF THE BANK FROM WHICH THE MONIES HAVE BEEN TRANSFERRED, VERIFY THAT THE ACCOUNT IS IN THE NAME OF THE PURCHASER AND RETAIN A WRITTEN RECORD OF SUCH DETAILS.

WE AND THE UNDERWRITERS RESERVE THE RIGHT TO REQUEST SUCH INFORMATION AS IS NECESSARY TO VERIFY THE IDENTITY OF A PURCHASER. IN THE EVENT OF DELAY OR FAILURE BY THE APPLICANT TO PRODUCE ANY INFORMATION REQUIRED FOR VERIFICATION PURPOSES, WE AND/OR THE UNDERWRITERS, AS APPLICABLE, WILL REFUSE TO ACCEPT THE APPLICATION AND THE SUBSCRIPTION MONIES RELATING THERETO.

IF ANY PERSON WHO IS RESIDENT IN THE CAYMAN ISLANDS HAS A SUSPICION THAT A PAYMENT TO US AND/OR THE UNDERWRITERS (BY WAY OF SUBSCRIPTION OR OTHERWISE) CONTAINS THE PROCEEDS OF CRIMINAL CONDUCT, THAT PERSON IS REQUIRED TO REPORT SUCH SUSPICION PURSUANT TO THE PROCEEDS OF CRIMINAL CONDUCT LAW (AS AMENDED).

BY SUBSCRIBING, PURCHASERS CONSENT TO THE DISCLOSURE BY US AND/OR THE UNDERWRITERS OF ANY INFORMATION ABOUT THEM TO REGULATORS AND OTHERS UPON REQUEST IN CONNECTION WITH MONEY LAUNDERING AND SIMILAR MATTERS BOTH IN THE CAYMAN ISLANDS AND IN OTHER JURISDICTIONS.

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NOTICE TO RESIDENTS OF BRAZIL

THE OFFER AND SALE OF ORDINARY SHARES WILL NOT BE CARRIED OUT BY ANY MEANS THAT WOULD CONSTITUTE A PUBLIC OFFERING IN BRAZIL UNDER LAW NO. 6,385, OF DECEMBER 7, 1976, AS AMENDED, AND UNDER CVM RULE (INSTRUÇÃO) NO. 400, OF DECEMBER 29, 2003, AS AMENDED. THE OFFER AND SALE OF THE ORDINARY SHARES HAVE NOT BEEN AND WILL NOT BE REGISTERED WITH THE COMISSÃO DE VALORES MOBILIÁRIOS IN BRAZIL. ANY REPRESENTATION TO THE CONTRARY IS UNTRUTHFUL AND UNLAWFUL. ANY PUBLIC OFFERING OR DISTRIBUTION, AS DEFINED UNDER BRAZILIAN LAWS AND REGULATIONS, OF THE INTERESTS IN BRAZIL IS NOT LEGAL WITHOUT SUCH PRIOR REGISTRATION. DOCUMENTS RELATING TO THE OFFERING OF THE ORDINARY SHARES, AS WELL AS INFORMATION CONTAINED THEREIN, MAY NOT BE SUPPLIED TO THE PUBLIC IN BRAZIL, AS THE OFFERING OF THE ORDINARY SHARES IS NOT A PUBLIC OFFERING OF SECURITIES IN BRAZIL, NOR MAY THEY BE USED IN CONNECTION WITH ANY OFFER FOR SALE OF THE ORDINARY SHARES TO THE PUBLIC IN BRAZIL.

THIS OFFER OF THE ORDINARY SHARES IS ADDRESSED TO YOU PERSONALLY, UPON YOUR REQUEST AND FOR YOUR SOLE BENEFIT, AND IS NOT TO BE TRANSMITTED TO ANYONE ELSE, TO BE RELIED UPON BY ANYONE ELSE OR FOR ANY OTHER PURPOSE EITHER QUOTED OR REFERRED TO IN ANY OTHER PUBLIC OR PRIVATE DOCUMENT OR TO BE FILED WITH ANYONE WITHOUT OUR PRIOR, EXPRESS AND WRITTEN CONSENT.

NOTICE TO RESIDENTS OF CHILE

AEI AND THE ORDINARY SHARES ARE NOT REGISTERED IN THE SECURITIES REGISTRY MAINTAINED BY THE SUPERINTENDENCIA DE VALORES Y SEGUROS DE CHILE (CHILEAN SECURITIES AND INSURANCE SUPERINTENDENCY OR “SVS”) PURSUANT TO THE SECURITIES MARKET LAW OF CHILE, AS AMENDED, NOR SUBJECT TO THE OVERSIGHT OF THE SVS.

NOTICE TO RESIDENTS OF COLOMBIA

THE SECURITIES HAVE NOT BEEN AND WILL NOT BE REGISTERED ON THE COLOMBIAN NATIONAL REGISTRY OF SECURITIES AND ISSUERS OR IN THE COLOMBIAN STOCK EXCHANGE. THEREFORE, THESE SECURITIES MAY NOT BE PUBLICLY OFFERED IN COLOMBIA. THIS MATERIAL IS FOR YOUR SOLE AND EXCLUSIVE USE AS A DETERMINED ENTITY AND INCLUDING ANY OF YOUR SHAREHOLDERS, ADMINISTRATORS OR EMPLOYEES, AS APPLICABLE. YOU ACKNOWLEDGE THE COLOMBIAN LAWS AND REGULATIONS (SPECIFICALLY FOREIGN EXCHANGE AND TAX REGULATIONS) APPLICABLE TO ANY TRANSACTION OR INVESTMENT CONSUMMATED PURSUANT HERETO AND REPRESENT THAT YOU ARE THE SOLE LIABLE PARTY FOR FULL COMPLIANCE WITH ANY SUCH LAWS AND REGULATIONS.

NOTICE TO PROSPECTIVE INVESTORS IN FRANCE

THIS OFFERING MEMORANDUM HAS NOT BEEN PREPARED IN THE CONTEXT OF A PUBLIC OFFERING OF SECURITIES IN FRANCE (APPEL PUBLIC À L’ÉPARGNE) WITHIN THE MEANING OF ARTICLE L.411-1 AND SEQ. OF THE FRENCH CODE MONÉTAIRE ET FINANCIER AND ARTICLES 211-1 AND SEQ. OF THE AUTORITÉ DES MARCHÉS FINANCIERS (“AMF”) REGULATIONS AND HAS THEREFORE NOT BEEN SUBMITTED TO THE AMF FOR PRIOR APPROVAL OR OTHERWISE. THE ORDINARY SHARES HAVE NOT BEEN OFFERED OR SOLD AND WILL NOT BE OFFERED OR SOLD, DIRECTLY OR INDIRECTLY, TO THE PUBLIC IN FRANCE AND NEITHER THIS OFFERING MEMORANDUM NOR ANY OTHER OFFERING MATERIAL RELATING TO THE SECURITIES HAS BEEN DISTRIBUTED OR CAUSED TO BE DISTRIBUTED OR WILL BE DISTRIBUTED OR CAUSED TO BE DISTRIBUTED TO THE PUBLIC IN FRANCE, EXCEPT ONLY TO PERSONS LICENSED TO PROVIDE THE INVESTMENT SERVICE OF PORTFOLIO MANAGEMENT FOR THE ACCOUNT OF THIRD PARTIES AND/OR TO “QUALIFIED INVESTORS” (AS DEFINED IN ARTICLE L.411-2, D.411-1

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AND D.411-2 OF THE FRENCH CODE MONÉTAIRE ET FINANCIER) AND/OR TO A LIMITED CIRCLE OF INVESTORS (AS DEFINED IN ARTICLE L.411-2, D.411-4 OF THE FRENCH CODE MONÉTAIRE ET FINANCIER) ON THE CONDITION THAT NO SUCH OFFERING MEMORANDUM NOR ANY OTHER OFFERING MATERIAL RELATING TO THE SECURITIES SHALL BE DELIVERED BY THEN TO ANY PERSON NOR REPRODUCED (IN WHOLE OR IN PART). SUCH “QUALIFIED INVESTORS” ARE NOTIFIED THAT THEY MUST ACT IN THAT CONNECTION FOR THEIR OWN ACCOUNT IN ACCORDANCE WITH THE TERMS SET OUT BY ARTICLE L.411-2 OF THE FRENCH CODE MONÉTAIRE ET FINANCIER AND BY ARTICLE 211-4 OF THE AMF REGULATIONS AND MAY NOT RE-TRANSFER, DIRECTLY OR INDIRECTLY, THE SECURITIES IN FRANCE, OTHER THAN IN COMPLIANCE WITH APPLICABLE LAWS AND REGULATIONS AND IN PARTICULAR THOSE RELATING TO A PUBLIC OFFERING (WHICH ARE, IN PARTICULAR, EMBODIED IN ARTICLES L.411-1, L.412-1 AND L.621-8 AND SEQ. OF THE FRENCH CODE MONÉTAIRE ET FINANCIER).

NOTICE TO RESIDENTS OF HONG KONG

THE SHARES MAY NOT BE OFFERED OR SOLD BY MEANS OF ANY DOCUMENT OTHER THAN (I) IN CIRCUMSTANCES WHICH DO NOT CONSTITUTE AN OFFER TO THE PUBLIC WITHIN THE MEANING OF THE COMPANIES ORDINANCE (CAP.32, LAWS OF HONG KONG), OR (II) TO “PROFESSIONAL INVESTORS” WITHIN THE MEANING OF THE SECURITIES AND FUTURES ORDINANCE (CAP.571, LAWS OF HONG KONG) AND ANY RULES MADE THEREUNDER, OR (III) IN OTHER CIRCUMSTANCES WHICH DO NOT RESULT IN THE DOCUMENT BEING A “PROSPECTUS” WITHIN THE MEANING OF THE COMPANIES ORDINANCE (CAP.32, LAWS OF HONG KONG), AND NO ADVERTISEMENT, INVITATION OR DOCUMENT RELATING TO THE SHARES MAY BE ISSUED OR MAY BE IN THE POSSESSION OF ANY PERSON FOR THE PURPOSE OF ISSUE (IN EACH CASE WHETHER IN HONG KONG OR ELSEWHERE), WHICH IS DIRECTED AT, OR THE CONTENTS OF WHICH ARE LIKELY TO BE ACCESSED OR READ BY, THE PUBLIC IN HONG KONG (EXCEPT IF PERMITTED TO DO SO UNDER THE LAWS OF HONG KONG) OTHER THAN WITH RESPECT TO SHARES WHICH ARE OR ARE INTENDED TO BE DISPOSED OF ONLY TO PERSONS OUTSIDE HONG KONG OR ONLY TO “PROFESSIONAL INVESTORS” WITHIN THE MEANING OF THE SECURITIES AND FUTURES ORDINANCE (CAP. 571, LAWS OF HONG KONG) AND ANY RULES MADE THEREUNDER.

NOTICE TO RESIDENTS OF JAPAN

THE SECURITIES HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER THE FINANCIAL INSTRUMENTS AND EXCHANGE LAW OF JAPAN (THE FINANCIAL INSTRUMENTS AND EXCHANGE LAW) AND EACH UNDERWRITER HAS AGREED THAT IT WILL NOT OFFER OR SELL ANY SECURITIES, DIRECTLY OR INDIRECTLY, IN JAPAN OR TO, OR FOR THE BENEFIT OF, ANY RESIDENT OF JAPAN (WHICH TERM AS USED HEREIN MEANS ANY PERSON RESIDENT IN JAPAN, INCLUDING ANY CORPORATION OR OTHER ENTITY ORGANIZED UNDER THE LAWS OF JAPAN), OR TO OTHERS FOR RE-OFFERING OR RESALE, DIRECTLY OR INDIRECTLY, IN JAPAN OR TO A RESIDENT OF JAPAN, EXCEPT PURSUANT TO AN EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF, AND OTHERWISE IN COMPLIANCE WITH, THE FINANCIAL INSTRUMENTS AND EXCHANGE LAW AND ANY OTHER APPLICABLE LAWS, REGULATIONS AND MINISTERIAL GUIDELINES OF JAPAN.

NOTICE TO RESIDENTS OF KUWAIT

NO OFFERING OF SHARES IS BEING MADE IN KUWAIT, AND NO AGREEMENT RELATING TO THE SALE OF THE SHARES WILL BE CONCLUDED IN KUWAIT. THIS MEMORANDUM IS PROVIDED AT THE REQUEST OF THE RECIPIENT AND IS BEING FORWARDED TO THE ADDRESS SPECIFIED BY THE RECIPIENT. NEITHER THE AGENT NOR THE OFFERING HAVE BEEN LICENSED BY THE KUWAIT MINISTRY OF COMMERCE AND INDUSTRY OR ARE OTHERWISE REGULATED BY THE LAWS OF KUWAIT.

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THEREFORE, NO SERVICES RELATING TO THE OFFERING, INCLUDING THE RECEIPT OF APPLICATIONS AND/OR THE ALLOTMENT OF THE SHARES, MAY BE RENDERED WITHIN KUWAIT BY THE AGENT OR PERSONS REPRESENTING THE OFFERING.

NOTICE TO RESIDENTS OF MEXICO

THE ORDINARY SHARES HAVE NOT BEEN AND WILL NOT BE REGISTERED WITH THE NATIONAL REGISTRY OF SECURITIES MAINTAINED BY THE NATIONAL BANKING AND SECURITIES COMMISSION AND MAY NOT BE PUBLICLY OFFERED IN MEXICO, EXCEPT PURSUANT TO THE FOLLOWING EXEMPTIONS:

(I) SALES THAT ARE PART OF AN OFFERING EXCLUSIVELY MADE TO QUALIFIED INVESTORS OR INSTITUTIONAL INVESTORS, WHO ARE HIGH NET WORTH INDIVIDUALS OR COMPANIES;

(II) OFFERS AND SALES OF EQUITY SECURITIES OF AN ENTITY NOT DIRECTED TO MORE THAN 100 PERSONS;

(III) OFFERS AND SALES MADE PURSUANT TO THE TERMS AND CONDITIONS OF AN EMPLOYEE BENEFIT PLAN OF THE ISSUER OF THE SECURITIES OR THE ENTITIES CONTROLLED BY IT; OR

(IV) OFFERS AND SALES MADE TO SHAREHOLDERS OR MEMBERS OF ENTITIES WHICH PRINCIPAL CORPORATE PURPOSE IS TO RENDER SERVICES TO SAID INDIVIDUALS.

NOTICE TO RESIDENTS OF PERU

THE PUBLIC OR PRIVATE OFFERING AND PLACEMENT OF THE ORDINARY SHARES IN THE REPUBLIC OF PERU SHOULD COMPLY WITH THE CORRESPONDING REQUIREMENTS FORESEEN IN THE “SECURITIES MARKET LAW” (LEY DE MERCADO DE VALORES) AND IN THE OTHER APPLICABLE REGULATIONS. ADDITIONAL REQUIREMENTS SHOULD BE COMPLIED IN CASES OF PRIVATE OFFERINGS DIRECTED TO PRIVATE PENSION FUNDS.

NOTICE TO RESIDENTS OF QATAR

THIS OFFER OF ORDINARY SHARES OF AEI (THE “SECURITIES”) DOES NOT CONSTITUTE A PUBLIC OFFER OF SECURITIES IN THE STATE OF QATAR UNDER LAW NO. 5 OF 2002 (THE “COMMERCIAL COMPANIES LAW”).

THE POTENTIAL INVESTOR OR RECIPIENT OF THIS PRIVATE PLACEMENT MEMORANDUM SHOULD READ THIS DOCUMENT CAREFULLY BEFORE DECIDING WHETHER TO PURCHASE SECURITIES AND SHOULD PAY PARTICULAR ATTENTION TO THE INFORMATION UNDER THE HEADING “INVESTMENT RISKS”. INVESTORS SHOULD BE AWARE THAT THEY MAY BE REQUIRED TO BEAR THE FINANCIAL RISKS OF THIS INVESTMENT FOR AN INDEFINITE PERIOD OF TIME.

INVESTORS IN THE SECURITIES ARE WARNED THAT THE NATURE OF THE PROPOSED INVESTMENT INVOLVES CONSIDERABLE RISK WHICH MAY RESULT IN INVESTORS LOSING THEIR ENTIRE INVESTMENT. THE COMPANY RECOMMENDS THAT AN INVESTMENT IN THE SECURITIES SHOULD NOT CONSTITUTE A SUBSTANTIAL PROPORTION OF AN INVESTMENT PORTFOLIO AND CAUTIONS THAT SUCH AN INVESTMENT MAY NOT BE APPROPRIATE FOR ALL POTENTIAL HOLDERS OF THE SECURITIES. ATTENTION IS DRAWN TO THE FOLLOWING RISKS LISTED ON PAGE 11.

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THE POTENTIAL INVESTOR OR RECIPIENT OF THIS PRIVATE PLACEMENT MEMORANDUM RECEIVED THE DOCUMENT ON A CONFIDENTIAL BASIS AND SHALL NOT DISCLOSE THE EXISTENCE OR THE CONTENTS OF THE MEMORANDUM TO ANY PERSON OR ENTITY.

NOTICE TO RESIDENTS OF SAUDI ARABIA

THIS DOCUMENT MAY NOT BE DISTRIBUTED IN THE KINGDOM OF SAUDI ARABIA EXCEPT TO SUCH PERSONS AS ARE PERMITTED UNDER THE OFFERS OF SECURITIES REGULATIONS DATED 20/8/1425 AH CORRESPONDING TO 4/10/2004 (AS AMENDED BY RESOLUTION NUMBER 1-28-2008 DATED 17/8/1429H CORRESPONDING TO 18/8/2008G)) (THE “REGULATIONS”) ISSUED BY THE CAPITAL MARKET AUTHORITY. THE CAPITAL MARKET AUTHORITY DOES NOT MAKE ANY REPRESENTATION AS TO THE ACCURACY OR COMPLETENESS OF THIS DOCUMENT AND EXPRESSLY DISCLAIMS ANY LIABILITY WHATSOEVER FOR ANY LOSS ARISING FROM, OR INCURRED IN RELIANCE UPON, ANY PART OF THIS DOCUMENT. NO ACTION HAS BEEN OR WILL BE TAKEN IN THE KINGDOM OF SAUDI ARABIA THAT WOULD PERMIT A PUBLIC OFFERING OR PRIVATE PLACEMENT OF THE SHARES IN THE KINGDOM OF SAUDI ARABIA, OR POSSESSION OR DISTRIBUTION OF ANY OFFERING MATERIALS IN RELATION THERETO. THE SHARES MAY ONLY BE OFFERED AND SOLD IN THE KINGDOM OF SAUDI ARABIA THROUGH PERSONS AUTHORIZED TO DO SO IN ACCORDANCE WITH PART 4 (PRIVATE PLACEMENTS) ARTICLE 12 (A) (1) OF THE REGULATIONS AND, IN ACCORDANCE WITH PART 4 (PRIVATE PLACEMENTS) ARTICLE 11(A)(1) OF THE REGULATIONS, THE SHARES WILL BE OFFERED TO NO MORE THAN 60 OFFEREES IN THE KINGDOM OF SAUDI ARABIA WITH EACH SUCH OFFEREE PAYING AN AMOUNT NOT LESS THAN SAUDI RIYALS ONE MILLION OR AN EQUIVALENT AMOUNT IN ANOTHER CURRENCY . INVESTORS ARE INFORMED THAT ARTICLE 17 OF THE REGULATIONS PLACES RESTRICTIONS ON SECONDARY MARKET ACTIVITY WITH RESPECT TO THE SHARES. ANY RESALE OR OTHER TRANSFER, OR ATTEMPTED RESALE OR OTHER TRANSFER, MADE OTHER THAN IN COMPLIANCE WITH THE ABOVE-STATED RESTRICTIONS SHALL NOT BE RECOGNIZED BY US. PROSPECTIVE PURCHASERS OF THE SHARES SHOULD CONDUCT THEIR OWN DUE DILIGENCE ON THE ACCURACY OF THE INFORMATION RELATING TO THE SHARES. IF YOU DO NOT UNDERSTAND THE CONTENTS OF THIS DOCUMENT YOU SHOULD CONSULT AN AUTHORISED FINANCIAL ADVISER.

NOTICE TO RESIDENTS OF SINGAPORE

THIS PROSPECTUS HAS NOT BEEN REGISTERED AS A PROSPECTUS WITH THE MONETARY AUTHORITY OF SINGAPORE. ACCORDINGLY, THIS PROSPECTUS AND ANY OTHER DOCUMENT OR MATERIAL IN CONNECTION WITH THE OFFER OR SALE, OR INVITATION FOR SUBSCRIPTION OR PURCHASE, OF THE SHARES MAY NOT BE CIRCULATED OR DISTRIBUTED, NOR MAY THE SHARES BE OFFERED OR SOLD, OR BE MADE THE SUBJECT OF AN INVITATION FOR SUBSCRIPTION OR PURCHASE, WHETHER DIRECTLY OR INDIRECTLY, TO PERSONS IN SINGAPORE OTHER THAN (I) TO AN INSTITUTIONAL INVESTOR UNDER SECTION 274 OF THE SECURITIES AND FUTURES ACT, CHAPTER 289 OF SINGAPORE (THE “SFA”), (II) TO A RELEVANT PERSON, OR ANY PERSON PURSUANT TO SECTION 275(1A), AND IN ACCORDANCE WITH THE CONDITIONS, SPECIFIED IN SECTION 275 OF THE SFA OR (III) OTHERWISE PURSUANT TO, AND IN ACCORDANCE WITH THE CONDITIONS OF, ANY OTHER APPLICABLE PROVISION OF THE SFA.

WHERE THE SHARES ARE SUBSCRIBED OR PURCHASED UNDER SECTION 275 BY A RELEVANT PERSON WHICH IS: (A) A CORPORATION (WHICH IS NOT AN ACCREDITED INVESTOR) THE SOLE BUSINESS OF WHICH IS TO HOLD INVESTMENTS AND THE ENTIRE SHARE CAPITAL OF WHICH IS OWNED BY ONE OR MORE INDIVIDUALS, EACH OF WHOM IS AN ACCREDITED INVESTOR; OR (B) A TRUST (WHERE THE TRUSTEE IS NOT AN ACCREDITED INVESTOR) WHOSE SOLE PURPOSE IS TO HOLD INVESTMENTS AND EACH BENEFICIARY IS AN ACCREDITED INVESTOR, SHARES, DEBENTURES AND UNITS OF SHARES AND DEBENTURES OF

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THAT CORPORATION OR THE BENEFICIARIES’ RIGHTS AND INTEREST IN THAT TRUST SHALL NOT BE TRANSFERABLE FOR 6 MONTHS AFTER THAT CORPORATION OR THAT TRUST HAS ACQUIRED THE SHARES UNDER SECTION 275 EXCEPT: (1) TO AN INSTITUTIONAL INVESTOR UNDER SECTION 274 OF THE SFA OR TO A RELEVANT PERSON, OR ANY PERSON PURSUANT TO SECTION 275(1A), AND IN ACCORDANCE WITH THE CONDITIONS, SPECIFIED IN SECTION 275 OF THE SFA; (2) WHERE NO CONSIDERATION IS GIVEN FOR THE TRANSFER; OR (3) BY OPERATION OF LAW.

NOTICE TO RESIDENTS OF THE UNITED ARAB EMIRATES AND DUBAI INTERNATIONAL
FINANCIAL CENTRE

THIS PROSPECTUS HAS NOT BEEN REVIEWED, APPROVED OR LICENSED BY THE CENTRAL BANK OF THE UNITED ARAB EMIRATES (THE “UAE”), EMIRATES SECURITIES AND COMMODITIES AUTHORITY OR ANY OTHER RELEVANT LICENSING AUTHORITY IN THE UAE INCLUDING ANY LICENSING AUTHORITY INCORPORATED UNDER THE LAWS AND REGULATIONS OF ANY OF THE FREE ZONES ESTABLISHED AND OPERATING IN THE TERRITORY OF THE UAE, IN PARTICULAR THE DUBAI INTERNATIONAL FINANCIAL SERVICES AUTHORITY (THE “DFSA”), A REGULATORY AUTHORITY OF THE DUBAI INTERNATIONAL FINANCIAL CENTRE (THE “DIFC”).

THIS PROSPECTUS IS NOT INTENDED TO CONSTITUTE AN OFFER, SALE OR DELIVERY OF SHARES OR OTHER SECURITIES UNDER THE LAWS OF THE UNITED ARAB EMIRATES (UAE). THE ORDINARY SHARES HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER FEDERAL LAW NO. 4 OF 2000 CONCERNING THE EMIRATES SECURITIES AND COMMODITIES AUTHORITY AND THE EMIRATES SECURITY AND COMMODITY EXCHANGE, OR WITH THE UAE CENTRAL BANK, THE DUBAI FINANCIAL MARKET, THE ABU DHABI SECURITIES MARKET OR WITH ANY OTHER UAE EXCHANGE.

THE ISSUE OF ORDINARY SHARES AND INTERESTS THEREIN HAVE NOT BEEN APPROVED OR LICENSED BY THE UAE CENTRAL BANK OR ANY OTHER RELEVANT LICENSING AUTHORITIES IN THE UAE, AND DO NOT CONSTITUTE A PUBLIC OFFER OF SECURITIES IN THE UAE IN ACCORDANCE WITH THE COMMERCIAL COMPANIES LAW, FEDERAL LAW NO. 8 OF 1984 (AS AMENDED) OR OTHERWISE.

IN RELATION TO ITS USE IN THE UAE, THIS PROSPECTUS IS STRICTLY PRIVATE AND CONFIDENTIAL AND IS BEING DISTRIBUTED TO A LIMITED NUMBER OF SOPHISTICATED INVESTORS AND MUST NOT BE PROVIDED TO ANY PERSON OTHER THAN THE ORIGINAL RECIPIENT, AND MAY NOT BE REPRODUCED OR USED FOR ANY OTHER PURPOSE. THE INTERESTS IN THE ORDINARY SHARES MAY NOT BE OFFERED OR SOLD DIRECTLY OR INDIRECTLY TO THE PUBLIC IN THE UAE. MANAGEMENT OF THE COMPANY, AND THE REPRESENTATIVES REPRESENT AND WARRANT THAT THE ORDINARY SHARES WILL NOT BE OFFERED, SOLD, TRANSFERRED OR DELIVERED TO THE PUBLIC IN THE UAE OR ANY OF ITS FREE ZONES INCLUDING, IN PARTICULAR, THE DIFC.

THIS STATEMENT RELATES TO AN EXEMPT OFFER IN ACCORDANCE WITH THE OFFERED SECURITIES RULES OF THE DUBAI FINANCIAL SERVICES AUTHORITY. THIS STATEMENT IS INTENDED FOR DISTRIBUTION ONLY TO PERSONS OF A TYPE SPECIFIED IN THOSE RULES. IT MUST NOT BE DELIVERED TO, OR RELIED ON BY, ANY OTHER PERSON. THE DUBAI FINANCIAL SERVICES AUTHORITY HAS NO RESPONSIBILITY FOR REVIEWING OR VERIFYING ANY DOCUMENTS IN CONNECTION WITH EXEMPT OFFERS. THE DUBAI FINANCIAL SERVICES AUTHORITY HAS NOT APPROVED THIS DOCUMENT NOR TAKEN STEPS TO VERIFY THE INFORMATION SET OUT IN IT, AND HAS NO RESPONSIBILITY FOR IT. THE SECURITIES TO WHICH THIS DOCUMENT RELATES MAY BE ILLIQUID AND/OR SUBJECT TO RESTRICTIONS ON THEIR RESALE. PROSPECTIVE PURCHASERS OF THE SECURITIES OFFERED SHOULD CONDUCT THEIR OWN DUE DILIGENCE ON THE SECURITIES. IF YOU DO NO UNDERSTAND THE CONTENTS OF THIS DOCUMENT YOU SHOULD CONSULT AN AUTHORISED FINANCIAL ADVISER.

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ENFORCEMENT OF CIVIL LIABILITIES

We are registered under the laws of the Cayman Islands as an exempted company with limited liability. We are registered in the Cayman Islands because of certain benefits associated with being a Cayman Islands corporation, such as political and economic stability, an effective judicial system, a favorable tax system, the absence of foreign exchange control or currency restrictions and the availability of professional and support services. However, the Cayman Islands has a less developed body of securities laws as compared to the United States and provides protections for investors to a significantly lesser extent. Our constituent documents do not contain provisions requiring that disputes, including those arising under the securities laws of the United States, between us, our officers, directors and shareholders be arbitrated.

Substantially all of our assets are located outside the United States. 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 investors to effect service of process within the United States upon us or these persons, or to enforce against us or them judgments obtained in United States courts, including judgments predicated upon the civil liability provisions of the securities laws of the United States or any state in the United States. It may also be difficult for you to enforce in U.S. courts judgments obtained in U.S. courts based on the civil liability provisions of the U.S. federal securities laws against us, our officers and directors.

We have appointed Corporation Service Company as our agent to receive service of process with respect to any action brought against us in the United States District Court for the Southern District of New York under the federal securities laws of the United States or of any State of the United States or any action brought against us in the Supreme Court of the State of New York in the County of New York under the securities laws of the State of New York.

Walkers, our counsel as to Cayman Islands law, have advised us that there is uncertainty as to whether the courts of the Cayman Islands (1) recognize or enforce judgments of United States courts obtained against us or our directors or officers predicated upon the civil liability provisions of the securities laws of the United States or any state in the United States, or (2) entertain original actions brought in the Cayman Islands against us or our directors or officers predicated upon the securities laws of the United States or any state in the United States.

Walkers has further advised us that the courts of the Cayman Islands would recognize as a valid judgment, a final and conclusive judgment in personam obtained in the federal or state courts in the United States under which a liquidated sum of money is payable (not being in respect of penalties or taxes or a fine or similar fiscal or revenue obligations) and would give a judgment based thereon provided that (i) such courts had proper jurisdiction over the parties subject to such judgment, (ii) such courts did not contravene the rules of natural justice of the Cayman Islands, (iii) such judgment was not obtained by fraud, (iv) the enforcement of the judgment would not be contrary to the public policy of the Cayman Islands, (v) no new admissible evidence relevant to the action is submitted prior to the rendering of the judgment by the courts of the Cayman Islands, and (vi) there is due compliance with the correct procedures under the laws of the Cayman Islands.

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EXPERTS

The consolidated financial statements of AEI and subsidiaries as of December 31, 2008 and 2007, and for each of the three years in the period ended December 31, 2008 and the consolidated statements of income, shareholders’ equity and cash flows for the 249-day period ended September 6, 2006 of Prisma Energy International Inc. and subsidiaries (a predecessor entity of AEI), included in this prospectus and the related financial statement schedule included elsewhere in the Registration Statement, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report on AEI and subsidiaries consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph concerning the retrospective adjustments related to the January 1, 2009 adoption of Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51 (SFAS 160), and which report on Prisma Energy International Inc. and subsidiaries consolidated statements of income, shareholders’ equity and cash flows expresses an unqualified opinion and includes explanatory paragraphs relating to a change in method of accounting for stock-based compensation and the retrospective adjustments related to the application of SFAS 160). Such consolidated financial statements and financial statement schedule have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form F-1 under the Securities Act with respect to the ordinary shares offered hereby. For the purposes of this section, the term registration statement means the original registration statement and any and all amendments including the schedules and exhibits to the original registration statement or any amendment. This prospectus does not contain all of the information set forth in the registration statement we filed. For further information regarding us and the ordinary shares offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including its exhibits and schedules, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling 1-202-551-8909, and you may obtain copies at prescribed rates from the Public Reference Section of the SEC at its principal office in Washington, D.C. 20549. The SEC maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC.

We file Annual Reports on Form 20-F with, and furnish other information under cover of a Report on Form 6-K to, the SEC under the Exchange Act. As a foreign private issuer, 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 intend to make available annual reports within 90 days after the end of each fiscal year. We also intend to furnish shareholders with quarterly reports containing selected unaudited financial data for the first three quarters of each fiscal year. The financial statements will be prepared in accordance with GAAP and those reports will include a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section for the relevant periods. We intend to make the quarterly reports available within 45 days after the end of each of the first three fiscal quarters of each 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.

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GLOSSARY OF TECHNICAL TERMS


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

Dispatch		System operators dispatch power generators based on an “economic dispatch” model that balances the generator cost of electricity against the need to maintain the voltage frequency of the systems and the reliability of the system. Therefore there are times when AEI generation is not the most economical source of power. We measure the dispatch factor as the amount of energy that was sold in a period of time divided by net capacity of the plant multiplied by availability in that period multiplied by hours in that period of time.

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

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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

LPG		Liquefied petroleum gas

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

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GLOSSARY OF DEFINED TERMS

Certain terms used in the prospectus are defined below:


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

AEI Delaware		AEI LLC (formerly known as Ashmore Energy International LLC)

AEIL		Ashmore Energy International Limited

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)

Amayo		Consorcio Eolico Amayo S.A., our Nicaraguan Power Generation business

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

Ashmore		Ashmore Investment Management Limited

Ashmore Funds		Investment funds directly or indirectly managed by Ashmore

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

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

BMG		Beijing MacroLink Gas Co. Ltd., 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

CDEEE		Corporación Dominicana de Empresas Eléctricias Estatales

Centragas		Centragas, our Colombian Natural Gas Transportation and Services business

Centrans		Centrans Energy Services Inc.

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

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

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Colombian MME		Colombian Ministry of Mines and Energy

Corinto		Empresa Energética Corinto Ltd., our Nicaraguan Power Generation business

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

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

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

EC		Electricidad de CentroAmerica S.A. de C.V., our wholly owned subsidiary which provides operations and management services to 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

EKCE		Elektro Comercializadora de Energia Ltda., Elektro’s marketing company

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

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

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

EMDERSA		Empresa Distribuidora Electrica Regional S.A., an Argentine Power Distribution holding company

EMHC		EMHC Ltd., a wholly owned subsidiary of PEI

EMRA		Turkish Energy Market Regulatory Authority

Energía Distribuida		Two generation projects (Energía Distribuida I and Energía Distribuida II) being developed and commissioned by Emgasud

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

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

Fenix		Empresa Electrica de Generacion de Chilca S.A., our 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

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Gases de Occidente		Gases de Occidente S.A. E.S.P., our Colombian Natural Gas Distribution business

Gases del Caribe		Gases del Caribe S.A. E.S.P., our Colombian Natural Gas Distribution business

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

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

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

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

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

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

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

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

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Proenergía		Proenergía is the holding company of our Retail Fuel businesses

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.

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

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)

Surtigas		Surtigas S.A. E.S.P., our Colombian Natural Gas Distribution business

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

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

TEAS		Turkish Electricity Generation and Transmission Company

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.

TEDAS		Turkish Electricity Distribution Company

TEK		Turkish Electricity Company

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

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., an Argentine Natural Gas Transportation and Services business

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AEI AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2009		December 31, 2008
	(Millions of dollars (U.S.), except share and par value data)

ASSETS
Current assets:
Cash and cash equivalents	$	524	$	736
Restricted cash		57		83
Accounts and notes receivable:
Trade (net of allowance of $77 and $69, respectively)		892		863
Unconsolidated affiliates		15		11
Inventories		255		239
Prepaids and other current assets		334		384

Total current assets		2,077		2,316
Property, plant and equipment, net		3,842		3,524
Investments in and notes receivable from unconsolidated affiliates		1,092		907
Goodwill		635		614
Intangibles, net		404		393
Other assets		1,259		1,199

Total assets	$	9,309	$	8,953


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	577	$	572
Unconsolidated affiliates		30		30
Current portion of long-term debt, including related party		634		547
Accrued and other liabilities		652		594

Total current liabilities		1,893		1,743
Long-term debt, including related party		2,915		3,415
Deferred income taxes		232		199
Other liabilities		1,369		1,331
Commitments and contingencies
Equity:
Common stock, $0.002 par value, 5,000,000,000 shares authorized; 234,230,825 and 224,624,481 shares issued and outstanding		—		—
Additional paid-in capital		1,899		1,754
Retained earnings		448		280
Accumulated other comprehensive income (loss)		90		(204	)

Total equity attributable to AEI shareholders		2,437		1,830
Equity attributable to noncontrolling interests		463		435

Total equity		2,900		2,265

Total liabilities and equity	$	9,309	$	8,953

See notes to unaudited condensed consolidated financial statements.

F-2

AEI AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	Millions of dollars (U.S.), except per share data

Revenues	$	1,856		$	2,434		$	3,703		$	4,604

Costs of sales		1,418			1,931			2,816			3,642


Operating expenses:
Operations, maintenance, and general and administrative expenses		187			221			364			449
Depreciation and amortization		69			80			129			132
Taxes other than income		10			15			21			26
(Gain) loss on disposition of assets		5			15			10			(53	)

Total operating expenses		271			331			524			554


Equity income from unconsolidated affiliates		23			33			50			68

Operating income		190			205			413			476


Other income (expense):
Interest income		18			18			35			41
Interest expense		(80	)		(101	)		(159	)		(193	)
Foreign currency transaction gains (losses), net		45			(7	)		6			23
Gain on early retirement of debt		3			—			3			—
Other income (expense), net		56			(5	)		50			2

Total other income (expense)		42			(95	)		(65	)		(127	)

Income before income taxes		232			110			348			349
Provision for income taxes		51			41			127			119

Net income		181			69			221			230
Less: Net income - noncontrolling interests		56			18			53			124

Net income attributable to AEI shareholders	$	125		$	51		$	168		$	106


Basic earnings per share:
Net income attributable to AEI shareholders	$	0.54		$	0.23		$	0.73		$	0.50

Diluted earnings per share:
Net income attributable to AEI shareholders	$	0.53		$	0.23		$	0.72		$	0.50

See notes to unaudited condensed consolidated financial statements.

F-3

AEI AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Six Months
	Ended June 30,
	2009			2008
	(Millions of dollars (U.S.))

Cash flows from operating activities:
Net income	$	221		$	230
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		129			132
Increase (decrease) in deferred revenue		33			(23	)
Deferred income taxes		24			26
Equity earnings from unconsolidated affiliates		(50	)		(68	)
Distributions from unconsolidated affiliates		11			19
Foreign currency transaction gain, net		(6	)		(23	)
(Gain) loss on disposition of assets		10			(53	)
Gain on early retirement of debt		(3	)		—
Changes in operating assets and liabilities, net of translation, acquisitions, dispositions and non-cash items:
Trade receivables, net		8			(107	)
Accounts payable, trade		(24	)		120
Inventories		(2	)		(71	)
Prepaids and other current assets		3			3
Other		(58	)		(13	)

Net cash provided by operating activities		296			172

Cash flows from investing activities:
Proceeds from sale of investments		60			38
Capital expenditures		(166	)		(140	)
Cash paid for acquisitions, exclusive of cash and cash equivalents acquired		(22	)		(219	)
Cash and cash equivalents acquired		—			75
Net (increase) decrease in restricted cash		26			(20	)
Contribution to unconsolidated subsidiaries		(7	)		—
Other		5			(9	)

Net cash used in investing activities		(104	)		(275	)

Cash flows from financing activities:
Issuance of long-term debt		378			167
Repayment of long-term debt		(813	)		(161	)
Increase (decrease) in short-term borrowings		68			(64	)
Proceeds from issuance of common shares		—			200
Dividends paid to noncontrolling interest		(39	)		(53	)
Other		(6	)		1

Net cash provided by (used in) financing activities		(412	)		90

Effect of exchange rate changes on cash		8			8

Decrease in cash and cash equivalents		(212	)		(5	)
Cash and cash equivalents, beginning of period		736			516

Cash and cash equivalents, end of period	$	524		$	511


Cash payments for income taxes, net of refunds	$	79		$	47

Cash payments for interest, net of amounts capitalized	$	116		$	118

Non-cash exchange of related party debt for common shares	$	118		$	—

See notes to unaudited condensed consolidated financial statements.

F-4

AEI AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS


1.	BASIS OF PREPARATION

AEI, together with its consolidated subsidiaries, manages, operates and owns interests in essential energy infrastructure businesses in emerging markets across 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 June 30, 2009 include direct and indirect investments in the international businesses described below and are collectively referred to as the “Operating Companies”:


	2009	2009
	Ownership	Accounting	Location of
Company Name	Interest (%)	Method	Operations	Segment

Accroven SRL (“Accroven”)	49.25	Equity Method	Venezuela	Natural gas transportation and services
Beijing MacroLink Gas Co. Ltd (“BMG”)^(a)	70.00	Consolidated	China	Natural gas distribution
Gas Natural de Lima y Callao S.A. (“Calidda”)	80.85	Consolidated	Peru	Natural gas distribution
Chilquinta Energía S.A. (“Chilquinta”)^(b)	50.00	Equity Method	Chile	Power distribution
Consorcio Eolico Amayo S.A. (“Amayo”)^(c)(d)	12.72	Equity Method	Nicaragua	Power generation
DHA Cogen Limited (“DCL”)^(a)	60.22	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 Energía Norte, S.A. (“EDEN”)	90.00	Consolidated	Argentina	Power distribution
Elektra Noreste S.A. (“Elektra”)	51.00	Consolidated	Panama	Power distribution
Elektrocieplownia Nowa Sarzyna Sp. z.o.o. (“ENS”)	100.00	Consolidated	Poland	Power generation
Elektro — Eletricidade e Serviços S.A. (“Elektro”)	99.68	Consolidated	Brazil	Power distribution
Emgasud S.A. (“Emgasud”)^(a)(e)	37.00	Equity Method	Argentina	Power generation
Empresa Distribuidora Electrica Regional S.A. (“Emdersa”)^(c)	19.91	Equity Method	Argentina	Power distribution
Empresa Energetica Corinto Ltd. (“Corinto”)^(d)	57.67	Consolidated	Nicaragua	Power generation
EPE — Empresa Produtora de Energia Ltda. (“EPE”)^(f)	50.00	Consolidated	Brazil	Power generation
Empresa Electrica de Generacion de Chilca S.A. (“Fenix”)^(a)	85.00	Consolidated	Peru	Power generation
				Natural gas transportation
Gas Transboliviano S.A. (“GTB”)^(g)	17.65	Cost Method	Bolivia	and services
				Natural gas transportation
GasOcidente do Mato Grosso Ltda. (“GOM”)^(f)	50.00	Consolidated	Brazil	and services
				Natural gas transportation
GasOriente Boliviano Ltda. (“GOB”)^(f)	50.00	Consolidated	Bolivia	and services
Generadora San Felipe Limited Partnership (“Generadora San Felipe”)^(h)	100.00	Consolidated	Dominican Republic	Power generation
Jaguar Energy Guatemala LLC (“Jaguar”)^(a)	100.00	Consolidated	Guatemala	Power generation
Jamaica Private Power Company (“JPPC”)	84.42	Consolidated	Jamaica	Power generation
Luoyang Yuneng Sunshine Cogeneration Company Limited (“Luoyang”)^(a)	50.00	Consolidated	China	Power generation
Operadora San Felipe Limited Partnership (“Operadora San Felipe”)^(h)	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
Tipitapa Power Company Ltd (“Tipitapa”) ^(a)(d)	57.67	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

F-5


	2009	2009
	Ownership	Accounting	Location of
Company Name	Interest (%)	Method	Operations	Segment

Transborder Gas Services Ltd. (“TBS”)^(f)	50.00	Consolidated	Brazil, Bolivia	Natural gas transportation and services
Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. TBG (“TBG”)⁽ⁱ⁾	4.00	Cost Method	Brazil	Natural gas transportation and services
Transredes-Trasporte de Hidrocarburos S.A. (“Transredes”)^(g)	1.28	Cost Method	Bolivia	Natural gas transportation and services


(a)		The Company’s initial or additional interest was acquired during 2008.
(b)		POC holds the interest in the operations referred to as “Luz del Sur”. Chilquinta holds a 50% interest in a related service company, Tecnored S.A. (“Tecnored”).
(c)		The Company’s initial or additional interest was acquired during 2009 (see Note 3).
(d)		During the first quarter of 2009, as part of the Nicaragua Energy Holdings (“NEH”) transaction, AEI’s ownership in Corinto increased from 50% to 57.67% and AEI’s ownership in Tipitapa decreased from 100% to 57.67%. In addition, AEI owns, through its 57.67% interest in NEH, a 12.72% equity interest in Amayo (see Note 3).
(e)		In June 2009, the Company increased its ownership interest in Emgasud S.A. from 31.89% to 37.00%.
(f)		These four companies comprise the integrated project “Cuiabá”.
(g)		In May 2008, the Company’s ownership in Transredes, held through a 50.00% ownership in the holding company TR Holdings Ltda. (“TR Holdings”), decreased from 25% to 0% and the Company’s indirect ownership in GTB through Transredes decreased from 12.75% to 0% in 2008. The company maintains a 1.28% direct ownership interest in Transredes. The Company’s direct and indirect ownership in GTB is 17.65% as of June 30, 2009. Due to the decrease in ownership, the Company’s investments in Transredes and GTB are now accounted for using the cost method.
(h)		The Company comprises an integrated part of the operation referred to collectively as “San Felipe”.
(i)		Ownership interest based on direct ownership. Total ownership, including indirect interests held through TR Holdings, is 4.21%.

The accompanying unaudited condensed consolidated financial statements 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 three years ended December 31, 2008 and our audited recasted financial statements as of and for the three years ended December 31, 2008 as filed with the Securities and Exchange Commission.

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.	ACCOUNTING AND REPORTING CHANGES

Recent Accounting Policies — In September 2006, the Financial Accounting Standards Board (“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 became 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 was deferred until fiscal years beginning after November 15, 2008. 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 statements of operations. The Company adopted the remaining requirements of SFAS No. 157 on January 1, 2009, and the adoption will impact the recognition of nonfinancial assets and liabilities in future business combinations and the future determinations of impairment for nonfinancial assets and liabilities.

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.

F-6

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 nature and financial effects of the business combination. The Company adopted SFAS No. 141R on January 1, 2009 and is applying the provisions to business combinations entered into subsequent to that date.

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 adopted SFAS No. 160 on January 1, 2009 and has incorporated the changes in its financial statement presentation for all periods presented. The retrospective application of this standard reclassifies minority interest expense of $18 million and $124 million for the three months and six months ended June 30, 2008, respectively, as net income attributable to noncontrolling interests below net income in the presentation of net income attributable to AEI, reclassifies minority interest of $435 million as of December 31, 2008 previously included in total liabilities as noncontrolling interest in equity and separately reflects changes in noncontrolling interest in changes in equity and comprehensive income.

In November 2008, the FASB issued Emerging Issues Task Force (“EITF”) Issue No. 08-6, “Equity Method Investment Accounting Considerations”. EITF Issue No. 08-6 establishes that the accounting application of the equity method is affected by the accounting for business combinations and the accounting for consolidated subsidiaries, which were affected by the issuance of SFAS No. 141R and SFAS No. 160. EITF Issue No. 08-6 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years, consistent with the effective dates of SFAS No. 141R and SFAS No. 160. The Company adopted EITF Issue No. 08-6 on January 1, 2009 and is applying the provisions to acquisitions of equity method investments.

Although past transactions would have been accounted for differently under SFAS No. 141R and EITF Issue No. 08-6, application of these statements in 2009 will not affect historical amounts.

In March 2008, the 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. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008. The Company adopted SFAS No. 161 on January 1, 2009 and has incorporated the changes in its financial statements.

In April 2009, the FASB issued FASB Staff Position (“FSP”) FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which requires disclosures about fair value of financial instruments in interim reporting periods of publicly traded companies that were previously only required to be disclosed in annual financial statements. The provisions of FSP FAS 107-1 and APB 28-1 are effective for interim and annual periods ending after June 15, 2009. The Company has incorporated the additional disclosure requirements in its financial statements for the quarter ended June 30, 2009.

In April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This FSP provides additional guidance on estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for an asset or liability have significantly decreased in relation to normal market activity for the asset or liability. FSP FAS 157-4 also provides guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009 and the Company has incorporated the additional disclosure requirements in its consolidated financial statements beginning with the quarter ended June 30, 2009.

F-7

securities to make it more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This FSP does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual periods ending after June 15, 2009. The Company has incorporated the additional disclosure requirements in its consolidated financial statements beginning with the quarter ended June 30, 2009.

In May 2009, the FASB issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions of SFAS No. 165 are effective for interim and annual periods ending after June 15, 2009. The Company adopted SFAS No. 165 as of June 30, 2009 and there was no significant impact on the Company’s consolidated financial statements.

In June 2009, the FASB issued Statement No. 166, “Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140” (“SFAS No. 166”). SFAS No. 166 amends FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities”, to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement in transferred financial assets. The provisions of SFAS No. 166 are effective for interim and annual reporting periods beginning after November 15, 2009. The Company will adopt this Statement on January 1, 2010 and apply this Statement and related disclosure provisions to transfers occurring on or after the effective date.

In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 amends certain requirements of FASB Interpretation No. 46 (Revised December 2003), “Consolidation of Variable Interest Entities” to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. The provision of SFAS No. 167 are effective for interim and annual reporting periods beginning after November 15, 2009. The Company will adopt this Statement on January 1, 2010 and has not determined the impact, if any, on its consolidated financial statements.

In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification^tm and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 replaced FASB Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles” and identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company will adopt this Statement for the interim period ending September 30, 2009 and incorporate the new codification in its consolidated financial statements. While the adoption of SFAS No. 168 will not have an impact on AEI’s consolidated financial statements, SFAS No. 168 will impact the reference to authoritative and non-authoritative accounting literature within the notes.


3.	ACQUISITIONS

2009 Acquisitions

Nicaragua Energy Holdings — On January 1, 2009, AEI contributed its 50% interest in its subsidiary Corinto and its 100% interest in its subsidiary Tipitapa to Nicaragua Energy Holdings (“NEH”). Centrans Energy Services Inc. (“Centrans”) also contributed its 50% interest in Corinto and 49% of its 45% interest in Consorcio Eolico Amayo, S.A. (“Amayo”) to NEH. Amayo is a 40 MW wind generation greenfield development project located in Rivas province, Nicaragua. As a result, AEI owns 57.67% and Centrans owns 42.33% of NEH. Centrans was given a call option that may be exercised at any time prior to December 8, 2013 to increase its interest in NEH up to 50.00%. The Company accounted for the exchange of ownership interests in Corinto and Tipitapa as an equity transaction and the interests were contributed to NEH at the carrying value. The acquisition of an ownership interest in Amayo by NEH was accounted for as a business combination. AEI consolidated NEH, which consolidates

F-8

Corinto and Tipitapa and accounts for Amayo under the equity method, from January 1, 2009. The Company is in the process of finalizing its purchase price allocation.

Trakya — On May 1, 2009, AEI signed an agreement to purchase an additional 31% of Trakya. The closing of this transaction is subject to a number of conditions, including obtaining regulatory and third party consents. If these consents are obtained, the Company anticipates that this transaction will be completed in the second half of 2009.

2009 Acquisitions of Equity Investments

Emdersa — On May 22, 2009, AEI acquired from a third party a 19.91% interest in Empresa Distribuidora Electrica Regional S.A. (“Emdersa”), an Argentine holding company that controls or owns equity interest in three power distribution companies. AEI paid cash of $7 million and contributed 1,497,760 shares of AEI in exchange for the 19.91% ownership interest of Emdersa. The acquisition was accounted for as a business combination and the Company accounts for this investment under the equity method as of May 22, 2009. The Company is in the process of finalizing its purchase price allocation.

Emgasud — On June 17, 2009, AEI paid cash of $15 million to acquire additional shares of Emgasud, which increased AEI’s ownership interest in Emgasud from 31.89% to 37%. The Company continues to account for this investment under the equity method.

2008 Acquisitions

Sociedad de Inversiones en Energía (“SIE”) — On January 2, 2008, Promigas contributed its ownership interests in its wholly owned subsidiary, Gas Natural Comprimido (“Gazel”), to SIE in exchange for additional shares of SIE. As a result of the transaction, Promigas’ ownership in SIE increased from 37.19% as of December 31, 2007 to 54% with SIE owning 100% of Gazel. The transaction was accounted for as a simultaneous common control merger. A gain of $74 million, net of tax of $0 million, net income of noncontrolling interest of $58 million, and incremental goodwill in the amount of $255 million were recorded in first quarter 2008 related to this transaction. As a result of the final purchase price allocation, the gain was reduced by $6 million and goodwill was reduced to $188 million in the third quarter of 2008. SIE’s balances and results of operations have been consolidated with those of the Company prospectively from January 2, 2008.

BMG — On January 30, 2008, the Company completed its acquisition of a 70% interest in BMG and its subsidiaries for $58 million in cash and recorded $5 million of goodwill upon finalization of the purchase price allocation. A portion of the interest purchased was funded in December 2007 (a 10.23% interest accounted for under the cost method in 2007). As a result of the January 2008 transaction, BMG was consolidated from January 30, 2008 forward. BMG builds city gas pipelines and sells and distributes piped gas in the People’s Republic of China.

Luoyang — On February 5, 2008, the Company acquired for $14 million in cash a 48% interest in Luoyang located in the Henan Province, People’s Republic of China. Luoyang owns and operates a power plant consisting of two coal-fired circulating fluidized-bed boilers and two 135 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.

Tipitapa — The Company acquired 100% of Tipitapa on June 11, 2008 for $18 million in cash. The excess of $4 million of fair value of the net assets of Tipitapa over the purchase price was applied as a reduction to the fixed assets. Tipitapa, a Power Generation Company with operations in Nicaragua, provides 51 MW of generation capacity and associated energy through a long-term power purchase agreement (“PPA”) with two Nicaraguan distribution companies, both majority owned by a third party.

2008 Acquisitions of additional interests in entities already consolidated in 2007

Promigas — During the six months ended June 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.

F-9

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-fired generating facility. A subsidiary of the Company also executed power purchase agreements to sell capacity and energy for a 15 year term. Subject to obtaining financing and completion of other project milestones, we anticipate that the power generation plant construction will begin in the second half of 2009 and is expected to be completed in 2012. The plant will be located 80 kilometers south of Guatemala City in the Department of Escuintla, Guatemala.

2008 Acquisition 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 in the advanced stages of developing a 544 MW combined cycle power plant in Chilca, Peru. The interest was acquired for $100 million cash paid at the closing. AEI is obligated to pay, if certain conditions are met, an additional $20 million to the previous shareholders with 37.5% due at the commencement of construction and the remainder at full commencement of commercial operations.


4.	OTHER INCOME

Elektro — Elektro has three separate ongoing lawsuits against the Brazilian Federal Tax Authority in each of the Brazilian federal, superior and supreme courts relating to the calculation of the social contribution on revenue and the contribution to the social integration program. Elektro had previously accrued approximately $49 million and made a judicial deposit of approximately $21 million (based on the exchange rate as of June 30, 2009) related to this issue. In May 2009, a newly enacted Brazilian law revoked a previous law which resulted in a change to the method by which such contributions should be calculated. Due to the revocation and pursuant to a technical notice issued by IBRACON (the local Brazilian accounting standards board), Elektro has reversed the reserve allocated for this contingency which was previously recorded as other expense. The impact of this reversal resulted in $49 million ($32 million net of tax) in income which is reflected as Other income (expense), net in the unaudited condensed consolidated statements of operations. The $21 million judicial deposit made by Elektro remains as restricted cash and will not be released until the final decision by the supreme court on their appeal is made.


5.	(GAIN) LOSS ON DISPOSITION OF ASSETS

(Gain) loss on disposition of assets consists of the following:


	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2009		2008			2009		2008
	Millions of dollars (U.S.)					Millions of dollars (U.S.)

Gain on exchange for additional shares of SIE (see Note 3)	$	—	$	—		$	—	$	(74	)
Loss on sale of debt securities (see Note 12)		—		14			—		14
Loss on sale of operating equipment		5		5			10		11
Other		—		(4	)		—		(4	)

	$	5	$	15		$	10	$	(53	)

The gain on the exchange for additional shares of SIE was subsequently reduced to $68 million as a result of finalizing the purchase price allocation in the third quarter of 2008.


6.	CASH AND CASH EQUIVALENTS

Cash and cash equivalents include the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Parent Company	$	8	$	284
Consolidated Holding and Service Companies		66		35
Consolidated Operating Companies		450		417

Total cash and cash equivalents	$	524	$	736

F-10

Cash remittances from the consolidated Holding Companies, Service Companies, and Operating Companies to the Parent Company are made through payment of dividends, capital reductions, advances against future dividends, or repayment of shareholder loans. The ability and timing for many of these companies to make cash remittances is subject to their operational and financial performance, compliance with their respective shareholder and financing agreements, and with governmental, regulatory, and statutory requirements.

Cash and cash equivalents held by the consolidated Holding Companies, Service Companies, and Operating Companies that are denominated in currencies other than the U.S. dollar are as follows (translated to U.S. dollars at period-end exchange rates):


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Brazilian Real	$	134	$	111
Colombian Peso		86		96
Chilean Peso		26		14
Chinese Renminbi		20		15
Polish Zloty		8		8
Other		19		16

Total foreign currency cash and cash equivalents	$	293	$	260

Restricted cash consists of the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Current restricted cash:
Collateral and debt reserves for financing agreements (see Note 14)	$	50	$	63
Restricted due to long-term power purchase agreements		2		—
Collateral for contracts		1		5
Other		4		15

Total current restricted cash		57		83

Noncurrent restricted cash (included in other assets, see Note 12):
Amounts in escrow accounts related to taxes		27		24
Collateral and debt reserves for financing agreements		3		3
Restricted due to long-term power purchase agreements		6		5
Collateral for contracts		17		16
Other		3		1

Total non-current restricted cash		56		49

Total restricted cash	$	113	$	132


7.	INVENTORIES

Inventories consist of the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Materials and spare parts	$	91	$	141
Fuel		164		98

Total inventories	$	255	$	239

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8.	PREPAIDS AND OTHER CURRENT ASSETS

Prepaids and other current assets consist of the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Prepayments	$	26	$	29
Regulatory assets		21		25
Deferred income taxes		101		71
Receivable from YPFB		—		60
Taxes other than income		39		36
Government subsidy — Delsur		13		20
Net investments in direct financing leases		—		10
Current marketable securities		1		7
Other		133		126

Total prepaid and other current assets	$	334	$	384

As a result of ongoing analysis of contracts as part of the initial purchase price allocation for DCL, the power purchase agreement was determined to be an operating lease versus a financing lease. Accordingly, the lease receivable balance was reclassified to property, plant and equipment during the first quarter of 2009. Subsequently in the second quarter, the power purchase agreement was terminated (see Note 21).

In October 2008, the Company reached a settlement with Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), the Bolivian state-owned energy company, related to its investment in Transredes pursuant to which YPFB agreed to pay the Company $120 million in two installments. The first payment of $60 million was received in October 2008 and the second payment of $60 million was received in March, 2009.


9.	PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant, and equipment, net consist of the following:


	June 30,			December 31,
	2009			2008
	Millions of dollars (U.S.)

Machinery and equipment	$	2,173		$	1,888
Pipelines		820			777
Power generation equipment		933			862
Land and buildings		445			378
Vehicles		37			29
Furniture and fixtures		35			31
Other		73			106
Construction-in-process		216			209

Total		4,732			4,280
Less accumulated depreciation and amortization		(890	)		(756	)

Total property, plant and equipment, net	$	3,842		$	3,524

Depreciation and amortization expense is summarized as follows:


	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	Millions of dollars (U.S.)				Millions of dollars (U.S.)

Depreciation and amortization of property, plant and equipment, including those recorded under capital leases	$	63	$	73	$	116	$	122
Amortization of intangible assets, net		6		7		13		10

Total	$	69	$	80	$	129	$	132

The Company capitalized interest of $4 million and $3 million for the three months ended June 30, 2009 and 2008, respectively, and $6 million and $5 million for the six months ended June 30, 2009 and 2008, respectively.

F-12


10.	INVESTMENTS IN AND NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES

The Company’s investments in and notes receivable from unconsolidated affiliates consist of the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Equity method:
Accroven	$	33	$	24
Amayo (see Note 3)		9		—
BMG’s equity method investments		1		1
Chilquinta		348		266
EEC Holdings		7		7
Emdersa (see Note 3)		29		—
Emgasud (see Note 3)		62		49
POC		369		341
Promigas’ equity method investments		49		41
Subic		9		9
Tecnored		27		21

Total investments — equity method		943		759
Total investments — cost method		28		28

Total investments in unconsolidated affiliates		971		787

Notes receivable from unconsolidated affiliates:
Chilquinta		98		98
GTB		15		14
TBG		8		8

Total notes receivable from unconsolidated affiliates		121		120

Total investments in and notes receivable from unconsolidated affiliates	$	1,092	$	907

In February 2009, the 15-year build-to-operate-transfer agreement (“BOT”) between Subic and the National Power Corporation of the Philippines (“NPC”) expired on schedule and the plant was turned over to the NPC without additional compensation. The Company’s remaining investment balance in the holding company of Subic will be realized from the expected return of invested capital to shareholders upon final dissolution of the holding companies.

The Company’s share of the underlying net assets of its investments at fair value in POC, Chilquinta, Tecnored, Emgasud, Amayo and Emdersa was less than the carrying amount of the investments. The basis differential of $227 million represents primarily indefinite-lived intangible concession rights and goodwill which are tested annually for impairment.

Except for the $227 million of goodwill and intangibles noted above, the Company’s share of the underlying net assets of its remaining equity investments exceeded the purchase price of those investments. The credit excess of $34 million as of June 30, 2009 is being amortized into income on the straight-line basis over the estimated useful lives of the underlying assets.

Equity income from unconsolidated affiliates is as follows:


	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2009			2008		2009			2008
	Millions of dollars (U.S.)					Millions of dollars (U.S.)

Accroven	$	3		$	4	$	10		$	8
Chilquinta		7			10		13			20
Emgasud		(1	)		—		(1	)		—
POC		10			8		18			16
Promigas’ equity income from investments in unconsolidated affiliates		3			4		6			9
Subic		—			2		2			5
Tecnored		1			1		2			2
TR Holdings and GTB		—			4		—			8

Total	$	23		$	33	$	50		$	68

F-13

Dividends received from unconsolidated affiliates amounted to $5 million and $6 million for the three months ended June 30, 2009 and 2008, respectively, and $11 million and $19 million for the six months ended June 30, 2009 and 2008, respectively.

Equity income from TR Holdings and GTB ceased in May 2008 as a result of the nationalization of TR Holdings’ investment in Transredes.


11.	GOODWILL AND INTANGIBLES

The Company’s changes in the carrying amount of goodwill are as follows:


	2009		2008
	Millions of dollars (U.S.)

Balance at January 1	$	614	$	402
Acquisitions:
New acquisitions (see Note 3)		—		311
Acquired goodwill from consolidation of new acquisitions		—		48
Translation adjustments and other		21		9

Balance at June 30	$	635	$	770

The Company’s carrying amounts of intangibles are as follows:


	June 30, 2009						December 31, 2008
	Cost		Accum. Amort.		Net		Cost		Accum. Amort.		Net
	Millions of dollars (U.S.)						Millions of dollars (U.S.)

Amortizable intangibles:
Customer relationships	$	172	$	25	$	147	$	171	$	20	$	151
Concession and land use rights		154		12		142		152		8		144
Power purchase agreements and contracts		58		49		9		64		43		21
Software costs		48		27		21		42		21		21
Other		7		4		3		4		4		—

Total amortizable intangibles	$	439	$	117		322	$	433	$	96		337

Nonamortizable intangibles:
Concession and land use rights						56						31
Promigas trademarks						26						25

Total nonamortizable intangibles						82						56

Total intangibles					$	404					$	393

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 held by several power generation businesses. The amortization of the power purchase agreements may result in income or expense due to the difference between contract rates and projected market rates that are subject to change over the contract’s life. At June 30, 2009 and December 31, 2008, the Company also had intangible liabilities of $52 million and $57 million, respectively, which represent unfavorable power purchase agreements held by three of the power generation businesses (see Note 16).

F-14


12.	OTHER ASSETS

Other assets consist of the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Long-term receivables from customers:
Corporation Dominicana de Empresas Electricias Estatales (“CDEEE”)	$	165	$	169
Promigas customers		143		128
Other		10		9

		318		306
Net investments in direct financing leases (see Note 8)		—		63
Regulatory assets		99		49
Deferred income taxes		257		265
Investments in debt securities		221		192
Restricted cash (see Note 6)		56		49
Deferred financing costs, net		20		22
Other miscellaneous investments		8		7
Other deferred charges		196		160
Other noncurrent assets		84		86

Total	$	1,259	$	1,199

Investments in debt securities — The following table reflects activity related to investments in debt securities:


	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2009		2008			2009		2008
	Millions of dollars (U.S.)

Available-for-sale debt securities:
Matured debt securities included in debt restructuring agreements:
Fair value at beginning of period	$	169	$	218		$	168	$	282
Sale of existing securities		—		(38	)		—		(38	)
Unrealized net gain (loss) affecting other comprehensive income		28		(37	)		29		(101	)

Fair value at end of period		197		143			197		143

Total available-for-sale securities, end of period		197		143			197		143

Held-to-maturity debt securities:
Participation in commercial bank loan portfolio		22		22			22		22
Promissory notes		2		2			2		2

Total held-to-maturity securities, beginning and end of period		24		24			24		24

Total	$	221	$	167		$	221	$	167

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. No sales of available-for-sale securities or held-to-maturity securities occurred during the six months ended June 30, 2009. The Company’s available-for-sale securities as of June 30, 2009 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-15


13.	ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Employee-related liabilities	$	46	$	48
Income taxes payable		8		—
Deferred income taxes		21		10
Other taxes:
Value added taxes		50		40
Taxes on revenues		12		13
Withholding taxes		10		25
Governmental taxes		10		11
Other		38		31
Interest		63		42
Customer deposits		56		64
Dividends payable to noncontrolling interests		40		17
Regulatory liabilities		43		35
Tax and legal contingencies		4		19
Cost Increase Protocol payable — Trakya		37		37
Deferred revenues		53		32
Other accrued expenses		38		47
Other		123		123

Total	$	652	$	594


14.	LONG TERM DEBT

Long-term debt consists of the following:


	Variable or	Interest	Final	June 30,			December 31,
	Fixed Rate	Rate (%)	Maturity	2009			2008
	Millions of dollars (U.S.), except interest rates

Debt held by Parent Company:
Senior credit facility, U.S. dollar	Variable	3.6	2014	$	914		$	936
Revolving credit facility, U.S. dollar	Variable	3.3	2012		53			390
Synthetic revolving credit facility, U.S. dollar	Variable	3.3	2012		105			105
PIK note, U.S. dollar	Fixed	10.0	2018		246			352
Debt held by consolidated subsidiaries:
Cálidda, U.S. dollar	Variable	5.1 – 7.9	2009 – 2015		43			87
Cuiabá, U.S. dollar notes	Fixed	5.9	2015 – 2016		97			97
DCL, Pakistan Rupee	Variable	12.0 – 16.8	2009 – 2019		79			77
Delsur, U.S. dollar	Variable	6.8	2015		69			73
EDEN, U.S. dollar	Variable	4.0	2013		25			37
Elektra, U.S. dollar senior notes	Fixed	7.6	2021		99			99
Elektra, U.S. dollar debentures	Variable	3.5	2018		20			20
Elektra, U.S. dollar revolving credit facility	Variable	4.3 – 5.5	2009		—			25
Elektro, Brazilian real debentures	Variable	10.8 – 13.5	2011		277			238
Elektro, Brazilian real note	Variable	5.0 – 12.3	2009 – 2020		230			132
ENS, Polish Zloty loans	Variable	5.4	2009 – 2018		55			67
Luoyang, Chinese Renminbi	Variable	5.8 – 9.9	2009 – 2016		116			133
PQP, U.S. dollar notes	Variable	2.3 – 3.7	2012 – 2015		80			88
Promigas, Colombian peso debentures	Variable	11.5 – 11.6	2011 – 2012		120			116
Promigas, Colombian peso notes	Variable	7.75 – 11.5	2009 – 2014		715			534
Promigas, U.S. dollar notes	Variable	3.6 – 9.9	2011 – 2012		152			291
Others, U.S. dollar notes and Chinese Renminbi	Fixed and Variable	5.4 – 10.2	2009 – 2014		54			65

					3,549			3,962
Less current maturities					(634	)		(547	)

Total				$	2,915		$	3,415

Interest rates reflected in the above table are as of June 30, 2009. The three-month U.S. dollar London Interbank Offered Rate (“LIBOR”) as of June 30, 2009 was 0.6%.

Long-term debt includes related party amounts of $477 million and $603 million as of June 30, 2009 and December 31, 2008, respectively, from shareholders associated with both the Company’s senior credit facility and

F-16

PIK notes. Long-term debt also includes related party amounts of $97 million at both June 30, 2009 and December 31, 2008, from loans provided to Cuiabá by other shareholders in the project.

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 21). 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 and DCL (see Note 21), were in compliance with their respective debt covenants as of June 30, 2009.

Revolving Credit Facility — In June 2009, the Company made repayments of $337 million of revolving loans that were drawn under its Revolving Credit Facility.

Payment in Kind (PIK) Notes — On March 11, 2009 the Company, upon amendment of the PIK Note Purchase Agreement, issued an option to the PIK note holders to exchange their PIK notes for ordinary shares of AEI. The option period is for up to one year. The initial exchange rate is 63 ordinary shares per $1,000 for each principal amount of notes exchanged and adjusts downward on a daily basis in relation to the interest accrued on the principal balance of the notes to a rate of 57.08 shares per $1,000 as of the expiration of the option on March 10, 2010. Additionally, the amendment allows the Company to purchase, upon the Holders election, the PIK notes in the open market for cash, subject to certain conditions. On March 12, 2009, various funds that are managed by Ashmore Investment Management Limited (“Ashmore”), agreed to exchange PIK notes and related interest receivable in the amount of $118 million for 7,412,142 shares of common stock. Funds that are managed by Ashmore also own a majority of AEI’s shares. As a result of this exchange transaction, based on the fair value of the company common stock, the Company recorded an equity transaction for the issuance of such shares and the early retirement of the related debt. As the PIK Notes exchanged were held by funds having the same investment advisor as our majority shareholders, the Company recorded a $21 million increase in paid-in-capital representing the difference between the carrying value of the acquired PIK notes and the estimated fair value paid.

Cálidda — In March 2009, Cálidda repaid its subordinated loan of $47 million with funds provided through an intercompany loan with its shareholders, AEI and Promigas. Interest on this loan accrues at LIBOR plus 6.5% and is payable quarterly. Principal is due at maturity in 2014. The letter of credit, associated with the previous subordinated loan, was allowed to expire at repayment, which released $29 million of cash collateral.

Elektra — In January and February 2009, Elektra made repayments of $25 million representing all of its outstanding revolving loans drawn under its Revolving Credit Facility.

EDEN — On May 22, 2009, AEI purchased from a third party $10 million of outstanding debt held by its consolidated subsidiary EDEN. A gain of $3 million was recognized and is included in “Gain on early retirement of debt” in the unaudited condensed consolidated statements of operations.

Elektro — On April 24, 2009, Elektro issued unsecured commercial paper totaling 120 million Brazilian reais (approximately U.S. $61 million) that mature in October 2009 and accrue interest at the Brazil Interbank interest rate (CDI) plus 2%. On July 1, 2009, Elektro issued non-convertible debentures in the amount of 300 million Brazilian reais (approximately U.S. $152 million) which will mature on September 18, 2011. The debentures will pay an annual interest rate of 1.4 percentage points over the local interbank rate. A portion of the proceeds from the issuance were used to repay the unsecured commercial paper issued in April.

Promigas — During the second quarter of 2009, Promigas reduced its U.S. dollar denominated notes by $142 million primarily through refinancings in Colombian peso denominated notes. These notes have an average annual interest rate of 9.8% and maturity between 2011 and 2014. The notes are primarily unsecured.


15.	INCOME TAXES

F-17

provided based upon the tax laws and rates of the countries in which operations are conducted and income is earned. Variations arise when income earned and taxed in a particular country or countries fluctuates from year to year.

The Company is subject to changes in tax laws, treaties, and regulations in and between the countries in which it operates. A change in these tax laws, treaties, or regulations could result in a higher or lower effective tax rate on the Company’s worldwide earnings.

The effective income tax rate for the six months ended June 30, 2009 and 2008 was 36.5% and 34.1%, respectively, and both were higher than the Cayman Islands statutory rate of 0% 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 certain of its Brazilian subsidiaries for which no tax benefit has been provided and which increased the effective tax rate for the quarter.

The Company recognizes interest accrued related to unrecognized tax benefits and penalties as income tax expense.


16.	OTHER LIABILITIES

Other liabilities consist of the following:


	June 30,		December 31,
	2009		2008
	Millions of dollars (U.S.)

Deferred revenue	$	479	$	437
Special obligations		224		192
Uncertain tax positions		153		156
Notes payable to unconsolidated affiliates		106		109
Tax and legal contingencies (see Note 21)		35		68
Unfavorable power purchase agreements (see Note 11)		52		57
Taxes payable — San Felipe (see Note 21)		67		66
Capital lease obligations		43		48
Cost Increase Protocol payable — Trakya		6		25
Interest		23		22
Pension and other postretirement benefits (see Note 20)		14		14
Regulatory liabilities		73		25
Other		94		112

Total	$	1,369	$	1,331


17.	FAIR VALUE OF FINANCIAL INSTRUMENTS

The table below presents AEI’s assets and liabilities that are measured at fair value on a recurring basis, and are categorized based on the fair value hierarchy. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets. Level 2 refers to fair values estimated using significant other observable inputs, and Level 3 includes fair values estimated using significant non-observable inputs.


			Fair Value Measurement at Reporting Date Using
			Final Quoted Prices
			in Active Markets		Significant Other		Significant
			for Identical Assets		Observable Inputs		Unobservable
Assets	June 30, 2009		(Level 1)		(Level 2)		Inputs (Level 3)
	Millions of dollars (U.S.)

Available-for-sale securities	$	197	$	—	$	197	$	—
Derivatives		17		—		17		—

Total assets	$	214	$	—	$	214	$	—

Derivatives	$	55	$	—	$	55	$	—

Total liabilities	$	55	$	—	$	55	$	—

Available-for-sale securities — The Company’s available-for-sale securities currently 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 were convertible upon governmental approval into equity interests in the holding company pursuant to a debt restructuring agreement entered into in 2005. On January 8, 2009, the Company terminated the agreement by providing written notification of its desire to terminate

F-18

to the signators of the agreement pursuant to the terms of the restructuring agreement. These securities were originally contributed to the Company or acquired from March 2006 through January 2007. The aggregate cost of the CIESA debt securities from various contribution and acquisition dates totals $245 million. The securities represent approximately 92% of the total debt of CIESA and 100% of its matured securities.

The approximate current fair market value of the securities at June 30, 2009 and December 31, 2008 was $197 million and $168 million, respectively. The values consider the termination of the debt restructuring agreement and the underlying equity value of TGS, based on CIESA’s ownership of 55% of TGS. The valuation decreased below the original cost beginning in the fourth quarter of 2007 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 been impacted by the 2008 global financial crisis. The decline in the valuation from its cost through June 30, 2009 has resulted in $48 million of unrealized losses, or 20% less than original cost, in the Company’s other accumulated comprehensive loss account.

At each period end, including as of June 30, 2009 and December 31, 2008, in order to evaluate any impairment in its debt securities, the Company applies a systematic methodology considering its ability and intent to hold the security, its expected recovery of the amortized cost and any qualitative factors that may indicate the likelihood that such impairment is other-than-temporary. The Company also evaluated the near-term prospects of the successful receipt of the required governmental and regulatory approvals, considered the historical and current operating results of TGS, and considered collection of the value of the securities in a bankruptcy or a negotiated resolution. The debt securities, which represent a claim against the assets of CIESA (consisting primarily of the 55% interest in TGS), could still ultimately be exchanged for CIESA or TGS equity. The Company believes that the ultimate outcome of the debt will be conversion into an asset at least equal to the original cost of the securities, whether through bankruptcy or a negotiated resolution.

Considering the Company’s intent regarding the conversion to equity of CIESA through one of various alternatives to gain an indirect ownership interest in TGS, and the Company’s ability to hold these securities for a reasonable period of time sufficient for a forecasted recovery of cost, the Company does not consider those investments to be other-than-temporarily impaired as of June 30, 2009. For further information regarding CIESA debt securities, see Note 21.

Derivatives and Fair Value of Financial Instruments

Objectives for Using Derivatives — The Company is exposed to certain risk relating to its ongoing business operations. The primary risks managed by using derivative instruments are interest rate risk, foreign currency risk and commodity price risk. These risks are managed through the use of derivative instruments including interest rate swaps, foreign currency contracts and commodity contracts.

Accounting for Derivatives Impact on Financial Statements — The Company reflects all derivatives as either assets or liabilities on the consolidated balance sheet at their fair value. The fair value of AEI’s derivative portfolio is determined using observable inputs including LIBOR rate curves and forward foreign exchange curves. All changes in the fair value of the derivatives are recognized in income unless specific hedge criteria are met. Changes in the fair value of derivatives that are highly effective and qualify as cash flow hedges are reflected in accumulated other comprehensive income (loss) and recognized in income when the hedged transaction occurs or no longer is probable of occurring. Any ineffectiveness is recognized in income. Changes in the fair value of hedges of a net investment in a foreign operation are reflected as cumulative translation adjustments in accumulated other comprehensive income.

Interest Rate Swaps — The Parent and certain operating companies have entered into various interest rates swap agreements to limit their interest rate risk exposures to variable-rate debt. The Company has designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the swaps are deferred in other comprehensive income until interest expense on the related debt is recognized in earnings. Maturities on these interest rate swaps range from 2010 to 2018. The total notional value of interest rate swaps that have been designated and qualify for the Company’s cash flow hedging program as of June 30, 2009 was approximately $1,028 million.

Foreign currency contracts — The Company uses hedge transactions classified as net investment hedges to protect its net investment in Elektro, Promigas, ENS and Chilquinta against adverse changes in the exchange rate

F-19

between the U.S. dollar and the local currency. Since the derivative’s underlying exchange rate is expected to move in tandem with the exchange rate between the functional currency (the local currency) of the hedged investment and AEI’s functional currency (U.S. dollar), no material ineffectiveness is anticipated. The Company also entered into certain derivative contracts with a notional amount of $22 million as of June 30, 2009 which were not designated as hedging instruments. These contracts were entered to economically hedge foreign exchange risk associated with the local currency-based dividends received from Elektro, Promigas, ENS and Chilquinta on a recurring basis. The total notional value of foreign currency contracts that have been designated and qualify for the Company’s net investment hedging program as of June 30, 2009 was approximately $122 million.

Commodity derivatives — While generally our contracts are structured to minimize our exposure to fluctuations in commodity fuel prices, some of our operating companies entered into various commodity derivative contracts for a period ranging from 6 months to 31 months to protect margins for a portion of future revenues and cost of sales. The Company has designated the commodity derivatives as cash flow hedges. The total notional amount of those commodity derivatives that have been designated and qualify for the Company’s cash flow hedging program as of June 30, 2009 was approximately 240,000 barrels of fuel oil and 388,600 MMBTU of natural gas.

The balance sheet classification of the assets and liabilities related to derivative financial instruments is summarized below as of June 30, 2009 and December 31, 2008 (in millions of dollars (U.S.)):


	Derivative Assets			Derivative Liabilities
As of June 30, 2009	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value

Derivatives designated as hedging instruments
Interest rate swaps	Prepaids and other current assets	$	—	Accrued and other current liabilities	$	1
Foreign currency contracts	Prepaids and other current assets		—	Accrued and other current liabilities		7
Commodity hedge	Prepaids and other current assets		1	Other liabilities		2
Interest rate swaps	Other assets		16	Other liabilities		44

Total Derivatives designated as hedging instruments		$	17		$	54

Derivatives not designated as hedging instruments
Foreign currency contracts	Prepaids and other current assets	$	—	Accrued and other current liabilities	$	1

Total Derivatives not designated as hedging instruments		$	—		$	1

Total Derivatives		$	17		$	55


	Derivative Assets			Derivative Liabilities
As of December 31, 2008	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value

Derivatives designated as hedging instruments
Interest rate swaps	Prepaids and other current assets	$	—	Accrued and other current liabilities	$	1
Foreign currency contracts	Prepaids and other current assets		1	Accrued and other current liabilities		—
Interest rate swaps	Other assets		—	Other liabilities		63

Total Derivatives designated as hedging instruments		$	1		$	64

The following table summarizes the effect of all cash flow hedges on the unaudited condensed consolidated statements of operations (in millions of dollars (U.S.)):


				Gain (Loss) Reclassified
				from AOCI into Interest			Gain (Loss) Recognized in
	Gain (Loss) Recognized			Expense (Effective			Other Income (Expense)
	in OCI			Portion)			(Ineffective Portion)

Interest Rate Swaps:
For the Three Months Ended June 30:
2009	$	24		$	(8	)	$	—
2008		19			(3	)		—
For the Six Months Ended June 30:
2009		21			(13	)		—
2008		(4	)		(4	)		—

F-20

The following table summarizes the effect of all net investment hedges on the unaudited condensed consolidated statements of operations (in millions of dollars (U.S.)):


				Gain (Loss) Reclassified
				from AOCI into Foreign
				Currency Transaction		Gain (Loss) Recognized in
	Gain (Loss) Recognized			Gain (Loss) (Effective		Other Income (Expense)
	in OCI			Portion)		(Ineffective Portion)

Foreign Currency Contracts:
For the Three Months Ended June 30:
2009	$	(9	)	$	—	$	—
2008		—			—		—
For the Six Months Ended June 30:
2009		(8	)		—		—
2008		(4	)		—		—

The following table summarizes the effect of other derivative instruments the Company entered into that do not qualify for hedging treatment (in millions of dollars (U.S.)):


	Gain (Loss)
	Recognized in
	Foreign Currency
	Transaction
	Gain (Loss)

Foreign Currency Contracts:
For the Three Months Ended June 30:
2009	$	(3	)
2008		—
For the Six Months Ended June 30:
2009		(2	)
2008		—

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:


	June 30, 2009
	Carrying Value		Fair Value
	Millions of dollars (U.S.)

Assets:
Notes receivable from unconsolidated subsidiaries	$	121	$	129
Investment in debt securities, including available-for-sale securities		221		221
Derivatives		17		17
Liabilities:
Derivatives		55		55
Long-term debt, including current maturities		3,549		3,390

F-21


18.	PER SHARE DATA

Basic and diluted earnings per share attributable to AEI were as follows:


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008

Basic earnings per share attributable to AEI:
Net income attributable to AEI (millions of U.S. dollars)	$	125		$	51		$	168		$	106
Average number of common shares outstanding (millions)		232			218			229			214
Basic earnings per share attributable to AEI	$	0	.54	$	0	.23	$	0	.73	$	0	.50
Effect of dilutive securities:
Stock options (millions of options)		—			—			—			—
Restricted shares (millions of shares)		—			—			—			—
Convertible PIK notes (millions of shares) (see Note 14)		15			—			15			—
Dilutive earnings per share attributable to AEI	$	0	.53	$	0	.23	$	0	.72	$	0	.50

The Company issues restricted stock grants to directors and employees which are included in the calculation of basic earnings per share. For the three months ended June 30, 2009 and 2008, 4,832,836 and 2,789,320 stock options and restricted shares issued to employees, respectively, were excluded from the calculation of diluted earnings per share because either the exercise price of those options exceeded the average fair value of the Company’s stock during the related period or the future compensation expense of those restricted shares exceed the implied cost of the company issuing those shares. For the six months ended June 30, 2009 and 2008, 5,012,612 and 2,789,320 stock options and restricted shares issued to employees, respectively, were excluded from the calculation of diluted earnings per share because either the exercise price of those options exceeded the average fair value of the Company’s stock during the related period or the future compensation expense of those restricted shares exceed the implied cost of the company issuing those shares.


19.	COMPREHENSIVE INCOME AND CHANGES IN EQUITY

The components of total comprehensive income between AEI and noncontrolling interests were as follows:


	For the Three Months Ended June 30,
	2009								2008
				Noncontrolling								Noncontrolling
	AEI			Interests		Total			AEI			Interests		Total
	Millions of dollars (U.S.)

Net income	$	125		$	56	$	181		$	51		$	18	$	69
Other comprehensive income (loss):
Foreign currency translation gain (loss) (net of income tax of $0)		252			13		265			(22	)		32		10
Amortization of actuarial and investment gains (net of income tax of $0)		(1	)		—		(1	)		—			—		—
Net unrealized gain on qualifying derivatives (net of income tax of $(1) million and $0, respectively)		31			—		31			22			—		22
Net change in fair value of available-for-sale securities (net of income tax of $0)		28			—		28			(23	)		—		(23	)

Total other comprehensive income (loss)		310			13		323			(23	)		32		9

Total comprehensive income	$	435		$	69	$	504		$	28		$	50	$	78

F-22


	For the Six Months Ended June 30,
	2009						2008
			Noncontrolling							Noncontrolling
	AEI		Interests		Total		AEI			Interests		Total
	Millions of dollars (U.S.)

Net income	$	168	$	53	$	221	$	106		$	124	$	230
Other comprehensive income:
Foreign currency translation gain (net of income tax of $0)		231		15		246		110			32		142
Net unrealized gain on qualifying derivatives (net of income tax of $0)		34		—		34		—			—		—
Net change in fair value of available-for-sale securities (net of income tax of $0)		29		—		29		(87	)		—		(87	)

Total other comprehensive income		294		15		309		23			32		55

Total comprehensive income	$	462	$	68	$	530	$	129		$	156	$	285

The following tables provide a reconciliation of the beginning and ending balances of total equity, equity attributable to AEI and equity attributable to noncontrolling interests as of June 30, 2009 and 2008:


	AEI
								Accumulated
			Additional					Other
	Common		Paid-In			Retained		Comprehensive			Noncontrolling			Total
	Stock		Capital			Earnings		Income (Loss)			Interests			Equity
	(Millions of dollars (U.S.))

Balance, January 1, 2009	$	—	$	1,754		$	280	$	(204	)	$	435		$	2,265
Net income		—		—			168		—			53			221
Issuance of new shares		—		125			—		—			—			125
Compensation under stock incentive plan		—		3			—		—			—			3
Foreign currency translation		—		—			—		231			15			246
Net unrealized gain on qualifying derivatives (net of income tax of $0)		—		—			—		34			—			34
Change in fair value of available-for-sale- securities (net of income tax of $0)		—		—			—		29			—			29
Dividends		—		—			—		—			(61	)		(61	)
Changes in ownership		—		(4	)		—		—			17			13
PIK note exchange		—		21			—		—			—			21
Other		—		—			—		—			4			4

Balance, June 30, 2009	$	—	$	1,899		$	448	$	90		$	463		$	2,900


	AEI
							Accumulated
			Additional				Other
	Common		Paid In		Retained		Comprehensive			Noncontrolling			Total
	Stock		Capital		Earnings		Income (Loss)			Interests			Equity
	(Millions of dollars (U.S.))

Balance, January 1, 2008	$	—	$	1,521	$	122	$	215		$	288		$	2,146
Net income		—		—		106		—			124			230
Issuance of new shares		—		200		—		—			—			200
Compensation under stock incentive plan		—		4		—		—			—			4
Foreign currency translation		—		—		—		110			32			142
Change in fair value of available for sale securities (net of income tax of $0)		—		—		—		(87	)		—			(87	)
Dividends		—		—		—		—			(55	)		(55	)
Changes in ownership		—		—		—		—			256			256
Other		—		2		—		—			(2	)		—

Balance, June 30, 2008	$	—	$	1,727	$	228	$	238		$	643		$	2,836

F-23

Accumulated other comprehensive income (loss) attributable to AEI consists of the following:


	June 30,			December 31,
	2009			2008
	Millions of dollars (U.S.)

Cumulative foreign currency translation	$	100		$	(131	)
Unrealized derivative losses		(34	)		(68	)
Unamortized actuarial and investment gains		54			54
Unrealized loss on available for sale securities		(30	)		(59	)

Total	$	90		$	(204	)


20.	PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic pension benefit are as follows:


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	Millions of dollars (U.S.)

Service cost	$	1		$	1		$	2		$	2
Interest cost		7			8			14			16
Amortization of actuarial gain		(1	)		—			(2	)		—
Expected employee contribution		(1	)		—			(1	)		(1	)
Expected return on plan assets for the period		(10	)		(10	)		(20	)		(19	)

Total net periodic pension benefit	$	(4	)	$	(1	)	$	(7	)	$	(2	)

The total amounts of employer contributions paid for the six months ended June 30, 2009 and 2008 were less than $1 million in each period. The expected remaining scheduled annual employer contributions for 2009 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 June 30, 2009, AEI and certain of its subsidiaries had entered into letters of credit, bank guarantees, and performance bonds with balances of $183 million issued and $119 million in unused letter of credit, bank guarantee and performance bond availability, of which $20 million of the total facility balances were fully cash collateralized. Additionally, as of June 30, 2009, lines of credit of $1,295 million were outstanding, with an additional $606 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. (“PDVSA”). In February 2006, AEI’s board of directors approved the execution of a reimbursement agreement with a bank to issue four letters of credit totaling approximately $21 million, which is also included in amounts above. Accroven is required to reimburse AEI for any payment made in connection with the letters of credit, subject to the consent of Accroven’s lender and approval by the Accroven shareholders.

Political Matters:

Turkey — 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. 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.

F-24

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. The compensation system consists of stranded costs compensation which is based upon the capital expenditures incurred before May 1, 2004, which could not be recovered from future sales in the free market and additional fuel gas costs compensation. Both will be paid in quarterly installments of varying amounts. The payments started in August 2008. ENS received $18 million in 2008 and $14.6 million for the six months ended June 30, 2009 in stranded costs compensation and fuel gas compensation. The maximum remaining compensation, for stranded costs and fuel gas costs, attributable to ENS is 1.03 billion Polish zloty (approximately US $320 million based on the exchange rate as of June 30, 2009).

Venezuela — Accroven — Venezuela has nationalized a significant part of its hydrocarbon and electricity industries and changed its operation agreements to joint ventures with the state-owned oil company PDVSA (the only client of Accroven). PDVSA has recently indicated that it would like to own and operate Accroven. Accroven is currently in discussions with PDVSA to negotiate the terms of this transaction. It is possible that despite discussions between PDVSA and Accroven, we may not receive adequate compensation for our investment in Accroven, however, the Company does not believe that this will have a material adverse effect on its financial condition, results of operations or liquidity.

Litigation/Arbitration:

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. CIESA subsequently amended its complaint to also include an allegation that AEI’s termination of its restructuring agreement with CIESA was in breach of this agreement. AEI does not believe that there is any merit to the suit and is vigorously defending the claim. In July 2009, the New York court dismissed CIESA’s complaint. CIESA has appealed this dismissal. Separately, in February 2009, AEI filed a petition in Argentina for the involuntary bankruptcy liquidation of CIESA. The Argentine court granted our petition and, in April 2009, the Company initiated bankruptcy proceedings against CIESA. In July 2009, the Argentine court ruled that if CIESA does not cure its insolvency status within 20 days of AEI serving this decision on CIESA, CIESA would be put into bankruptcy. We served this decision on CIESA on July 31, 2009. If CIESA does go into bankruptcy, AEI will request the enforcement of the debt before the bankruptcy court at the proof of claims stage.

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 June 30, 2009, the Company has accrued liabilities totaling approximately $106 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 in a manner that the Company could be required to pay damages or to make expenditures in amounts materially in excess of that recorded, but cannot be estimated at June 30, 2009.

F-25

issues, hazardous work and severance payments. As of June 30, 2009, the Company has accrued approximately $17 million 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 to or under the control of the State Highway Department and such concessionaries. 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 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 $242 million (based on the exchange rate as of June 30, 2009) is due related to the tax periods involved. In June 2008, Elektro was notified that an administrative ruling was rendered on these matters that would fully cancel both tax assessments. The 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 $30 million (based on the exchange rate as of June 30, 2009) for the assessment period from 1998 to 2006. Based upon a Brazilian Federal Supreme Court precedent issued during the second quarter of 2008 regarding the statute of limitations for this type of claim, Elektro believes that a portion of the amount claimed is now time-barred by the statute of limitations. Elektro is in the initial stage of presenting its administrative defense and 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 accrued approximately $49 million as of June 30, 2009 and made a judicial deposit of approximately $21 million (based on the exchange rate as of June 30, 2009) related to this issue. In May 2009, a newly enacted Brazilian law revoked a previous law which resulted in a change to the method by which such contributions should be calculated. Due to the revocation and pursuant to a technical notice issued by IBRACON (the local accounting standards board), Elektro has reversed the reserve previously allocated for this contingency. However, the $21 million judicial deposit made by Elektro will not be released until the final decision by the supreme court on their appeal is made.

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 purchase agreement and initiated an arbitration proceeding in accordance with the power purchase agreement. EPE amended its initial pleadings and requested the termination of the PPA based on Furnas default to make capacity payments. The tribunal accepted the amendment of EPE’s pleadings in the first quarter of 2009. We expect a decision in this arbitration in 2009. If EPE is unable to satisfactorily resolve the dispute with Furnas, the operations of Cuiabá will

F-26

be materially adversely effected with a corresponding negative impact on the Company’s financial performance and cash flows.

San Felipe Limited Partnership — 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 June 30, 2009, neither CDEEE nor the executive branch has obtained this legislative exemption. In February 2002, the local tax authorities notified San Felipe of a request for tax payment for a total of DOP 716 million (equivalent to approximately $20 million at the exchange rates as of June 30, 2009) of unpaid taxes from January 1998 through June 2001. San Felipe filed an appeal against the request which was rejected by the local tax authorities. In July 2002, San Felipe filed a second appeal before the corresponding administrative body which was rejected in June 2008. In July 2008, San Felipe appealed this ruling before the Tax and Administrative Court. The Company has accrued approximately $67 million as of June 30, 2009 with respect to the period from January 1998 through June 30, 2009 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.

DCL — DCL entered commercial operations on April 17, 2008. However, 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. Due to the shutdown, DCL has not generated revenues and cash inflows to pay vendors, which has delayed the repairs. On January 24, 2009, DCL received notice of default from one of its senior lenders. Shortly thereafter, two of DCL’s senior lenders filed claims against DCL and Sacoden, which holds AEI’s interest in DCL, in the courts of Sindh Province, Pakistan seeking repayment by DCL of loans totaling PKR 3,704 million (equivalent to approximately $45 million at the exchange rates as of June 30, 2009). The lenders petitioned the courts to force a sale of all DCL’s assets and all of Sacoden’s shares in DCL and to replace DCL’s directors and officers with a court appointed administrator. DCL and Sacoden filed responses to these claims. In June 2009, DCL entered into loan agreements with its senior lenders and Sacoden pursuant to which the senior lenders and Sacoden made loans to DCL to fund its rehabilitation efforts. In connection with these loan agreements, DCL and Sacoden entered into a Standstill Agreement with the senior lenders pursuant to which the parties agreed to refrain from taking legal actions against each other for a specified period. Repairs to the plant are currently in progress.

DCL was party to a PPA with Karachi Electric Supply Corporation, or KESC, for the sale of all of the plant’s full output of power, which was terminated by KESC in April 2009. DCL has started discussions with KESC with respect to a new power purchase agreement and once the plant begins operating again, expects to sell power to KESC on an interim basis while a new power purchase agreement is being negotiated.

If DCL is unable to satisfactorily resolve the dispute with its lenders or enter into an acceptable power purchase agreement, the operations of DCL will be materially adversely effected or the lenders may exercise their right to take ownership of the plant, in either event with a corresponding negative impact on the Company’s financial performance and cash flows.


22.	SEGMENT AND GEOGRAPHIC INFORMATION

The Company manages, operates and owns interests in energy infrastructure businesses through a diversified portfolio of companies worldwide. It conducts operations through global businesses, which are aggregated into reportable segments based primarily on the nature of its service and customers, the operation and production processes, cost structure, channels of distribution and regulatory environment. The operating segments reported below are the segments of the Company for which separate financial data is available and for which operating results are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The Company uses both revenue and operating income as key measures to evaluate the performance of its segments. Segment revenue includes inter-segment sales. Operating income is defined as total revenue less cost of sales and operating expenses (including depreciation and amortization, taxes other than income, and (gains) losses on disposition of assets). Operating income also includes equity income from unconsolidated affiliates due to the nature of operations in these affiliates.

F-27

The tables below present summarized financial data about AEI’s reportable segments:


As of and For the Three Months Ended	Power		Power		Nat. Gas.		Nat. Gas.		Retail		Headquarters
June 30, 2009	Dist.		Gen.		Trans.		Dist.		Fuel		and Other			Eliminations			Total
	Millions of dollars (U.S.)

Revenues	$	455	$	237	$	51	$	154	$	982	$	7		$	(30	)	$	1,856
Equity income from unconsolidated affiliates		18		—		4		3		—		—			(2	)		23
Operating income (loss)		80		40		29		27		33		(15	)		(4	)		190
Depreciation and amortization		32		11		5		5		14		2			—			69
Capital expenditures		42		2		3		28		14		3			—			92
Long lived assets as of June 30, 2009		2,998		1,267		680		898		916		3,019			(2,819	)		6,959
Total assets as of June 30, 2009		3,891		2,140		833		1,171		1,400		3,182			(3,308	)		9,309


As of December 31, 2008 and For the	Power		Power		Nat. Gas.		Nat. Gas.		Retail		Headquarters
Three Months Ended June 30, 2008	Dist.		Gen.		Trans.		Dist.		Fuel		and Other			Eliminations			Total
	Millions of dollars (U.S.)

Revenues	$	538	$	283	$	48	$	145	$	1,441	$	6		$	(27	)	$	2,434
Equity income from unconsolidated affiliates		20		2		8		3		—		—			—			33
Operating income (loss)		102		19		29		33		56		(34	)		—			205
Depreciation and amortization		37		5		6		5		25		2			—			80
Capital expenditures		37		1		7		18		11		—			—			74
Long lived assets as of December 31, 2008		2,598		1,300		701		832		841		2,491			(2,392	)		6,371
Total assets as of December 31, 2008		3,304		1,897		924		1,110		1,323		3,865			(3,470	)		8,953


	Power		Power		Nat. Gas.		Nat. Gas.		Retail		Headquarters
For the Six Months Ended June 30, 2009	Dist.		Gen.		Trans.		Dist.		Fuel		and Other			Eliminations			Total
	Millions of dollars (U.S.)

Revenues	$	917	$	507	$	99	$	302	$	1,925	$	14		$	(61	)	$	3,703
Equity income from unconsolidated affiliates		33		2		11		6		—		—			(2	)		50
Operating income (loss)		184		76		61		65		67		(33	)		(7	)		413
Depreciation and amortization		61		22		10		11		22		3			—			129
Capital expenditures		77		6		5		44		29		5			—			166


	Power		Power		Nat. Gas.		Nat. Gas.		Retail		Headquarters
For the Six Months Ended June 30, 2008	Dist.		Gen.		Trans.		Dist.		Fuel		and Other			Eliminations			Total
	Millions of dollars (U.S.)

Revenues	$	1,055	$	557	$	102	$	271	$	2,663	$	12		$	(56	)	$	4,604
Equity income from unconsolidated affiliates		38		5		17		8		1		—			(1	)		68
Operating income (loss)		200		40		67		61		166		(44	)		(14	)		476
Depreciation and amortization		72		11		11		9		26		3			—			132
Capital expenditures		68		2		9		37		20		4			—			140

The tables below present revenues and operating income of the Company’s consolidated subsidiaries by significant geographical location for the three and six months ended June 30, 2009 and 2008. Revenues are reported in the country in which they are earned.


	For the Three Months Ended June 30,
	Revenues				Operating Income
	2009		2008		2009		2008
	Millions of dollars (U.S.)

Colombia	$	826	$	1,037	$	64	$	90
Brazil		287		368		28		69
Chile		206		369		19		24
Panama		146		258		12		14
Turkey		76		51		13		(19	)
El Salvador		57		43		4		4
Guatemala		50		62		8		13
China		34		28		4		(1	)
Dominican Republic		38		77		22		12
Argentina		28		28		9		2
Other		108		113		7		(3	)

Total	$	1,856	$	2,434	$	190	$	205

F-28

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

AEI

c/o AEI Services, LLC

Houston, Texas

We have audited the accompanying consolidated balance sheets of AEI and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEI and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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 discussed in Note 2 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51.

/s/ Deloitte & Touche LLP

Houston, Texas

March 31, 2009

(June 18, 2009 as to the effects of the adoption of Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, and the related disclosures in Note 2)

F-30

AEI AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007
	(Millions of dollars (U.S.), except
	share and par value data)

ASSETS
Current assets:
Cash and cash equivalents	$	736		$	516
Restricted cash		83			95
Accounts and notes receivable:
Trade (net of allowance of $69 and $46, respectively)		863			650
Unconsolidated affiliates		11			75
Inventories		239			117
Prepaids and other current assets		384			263

Total current assets		2,316			1,716
Property, plant and equipment, net		3,524			3,035
Investments in and notes receivable from unconsolidated affiliates		907			1,028
Goodwill		614			402
Intangibles, net		393			237
Other assets		1,199			1,435

Total assets	$	8,953		$	7,853


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	572		$	380
Unconsolidated affiliates		30			94
Current portion of long-term debt, including related party		547			749
Accrued and other liabilities		594			525

Total current liabilities		1,743			1,748
Long-term debt, including related party		3,415			2,515
Deferred income taxes		199			168
Other liabilities		1,331			1,276
Commitments and contingencies
Equity:
Common stock, $0.002 par value, 5,000,000,000 shares authorized; 224,624,481 and 210,403,374 shares issued and outstanding		—			—
Additional paid-in capital		1,754			1,521
Retained earnings		280			122
Accumulated other comprehensive income (loss)		(204	)		215

Total shareholders’ equity attributable to AEI		1,830			1,858
Equity attributable to noncontrolling interests		435			288

Total equity		2,265			2,146

Total liabilities and equity	$	8,953		$	7,853

See notes to consolidated financial statements.

F-31

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Years Ended December 31,
	2008			2007			2006
	(Millions of dollars (U.S.),
	except share and per share data)

Revenues	$	9,211		$	3,216		$	946

Costs of sales		7,347			1,796			566

Operating expenses:
Operations, maintenance, and general and administrative expenses		894			630			193
Depreciation and amortization		268			217			59
Taxes other than income		43			43			7
Other charges		56			50			—
(Gain) loss on disposition of assets		(93	)		(21	)		7

Total operating expenses		1,168			919			266

Equity income from unconsolidated affiliates		117			76			37

Operating income		813			577			151

Other income (expense):
Interest income		88			110			71
Interest expense		(378	)		(306	)		(138	)
Foreign currency transaction gain (loss), net		(56	)		19			(5	)
Loss on early retirement of debt		—			(33	)		—
Other income (expense), net		9			(22	)		7

Total other expense		(337	)		(232	)		(65	)

Income before income taxes		476			345			86
Provision for income taxes		194			193			84

Income from continuing operations		282			152			2
Income from discontinued operations		—			3			7
Gain from disposal of discontinued operations		—			41			—

Net income		282			196			9
Less: Net income — noncontrolling interests		124			65			20

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

Basic and diluted earnings per share:
Income (loss) from continuing operations attributable to AEI	$	0.73		$	0.42		$	(0.09	)
Discontinued operations attributable to AEI		—			0.21			0.04

Net income (loss) attributable to AEI	$	0.73			0.63		$	(0.05	)

Amounts attributable to AEI:
Income (loss) from continuing operations	$	158			87		$	(18	)

Discontinued operations		—			44			7

Net income (loss)	$	158			131		$	(11	)

See notes to consolidated financial statements.

F-32

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Years Ended December 31,
	2008			2007			2006
	(Millions of dollars (U.S.))

Cash flows from operating activities:
Net income	$	282		$	196		$	9
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		268			217			59
Other charges		56			50			—
Increase in deferred revenue		55			120			28
Deferred income taxes		11			106			25
Equity earnings from unconsolidated affiliates		(117	)		(76	)		(37	)
Distributions from unconsolidated affiliates		67			28			11
Foreign currency transaction (gain) loss, net		56			(19	)		5
(Gain) loss on disposition of assets		(93	)		(21	)		7
Gain from disposal of discontinued operations		—			(41	)		—
Loss on early retirement of debt		—			33			—
Changes in operating assets and liabilities, net of translation, acquisitions, dispositions and non-cash items:
Trade receivables		(85	)		(59	)		(34	)
Accounts payable, trade		24			77			27
Accrued income taxes		(24	)		(26	)		9
Accrued interest		16			14			(8	)
Inventories		(15	)		(7	)		(15	)
Prepaids and other current assets		4			(5	)		13
Regulatory assets		(8			112			31
Regulatory liabilities		(24	)		(10	)		8
Other		35			(3	)		17

Net cash provided by operating activities		508			686			155

Cash flows from investing activities:
Proceeds from sale of investments		99			162			24
Capital expenditures		(372	)		(249	)		(76	)
Cash paid for acquisitions, exclusive of cash and cash equivalents acquired		(253	)		(1,111	)		(2,280	)
Cash and cash equivalents acquired		60			21			516
Net decrease in restricted cash		78			61			27
Other		(26	)		(35	)		60

Net cash used in investing activities		(414	)		(1,151	)		(1,729	)

Cash flows from financing activities:
Issuance of long-term debt		478			1,531			1,788
Repayment of long-term debt		(213	)		(1,777	)		(172	)
Payment of debt issuance costs		—			(18	)		(33	)
Increase (decrease) in short-term borrowings		(124	)		459			(19	)
Dividends paid to noncontrolling interests		(167	)		(101	)		(64	)
Proceeds from issuance of common shares		200			—			920
Other		(1	)		(6	)		(25	)

Net cash provided by financing activities		173			88			2,395

Effect of exchange rate changes on cash		(47	)		63			3

Increase (decrease) in cash and cash equivalents		220			(314	)		824
Cash and cash equivalents, beginning of period		516			830			6

Cash and cash equivalents, end of period	$	736		$	516		$	830

Cash payments for income taxes, net of refunds	$	173		$	172		$	50

Cash payments for interest, net of amounts capitalized	$	264		$	246		$	66

See notes to consolidated financial statements.

F-33

AEI AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY


	AEI
									Accumulated
									Other
			Additional			Retained			Comprehensive
	Common		Paid-In			Earnings			Income			Noncontrolling
	Stock		Capital			(Deficit)			(Loss)			Interests			Total
	(Millions of dollars (U.S.))

Balance, January 1, 2006	$	—	$	350		$	2		$	(25	)	$	61		$	388
Comprehensive income
Net income (loss)		—		—			(11	)		—			20			9
Foreign currency translation		—		—			—			2			—			2
Change in fair value of available-for-sale securities		—		—			—			34			—			34

Total comprehensive income							(11	)		36			20			45
Contribution of invested capital		—		1,088			—			—			—			1,088
Compensation under stock incentive plan		—		(1	)		—			—			—			(1	)
Stock issuance costs		—		(4	)		—			—			—			(4	)
Transition adjustment for pension and other post retirement benefits, net of income tax of $3 million		—		—			—			6			—			6
Dividends		—		—			—			—			(36	)		(36	)
Changes in ownership		—		—			—			—			312			312

Balance, December 31, 2006	$	—	$	1,433		$	(9	)	$	17		$	357		$	1,798

Comprehensive income
Net income		—		—			131			—			65			196
Foreign currency translation		—		—			—			210			2			212
Minimum pension liability adjustments, net of income tax of $8 million		—		—			—			16			—			16
Net unrealized loss on qualifying derivatives		—		—			—			(25	)		(2	)		(27	)
Change in fair value of available-for-sale securities		—		—			—			(3	)		—			(3	)

Total comprehensive income							131			198			65			394
Contribution of invested capital		—		79			—			—			—			79
Compensation under stock incentive plan		—		9			—			—			—			9
Dividends		—		—			—			—			(91	)		(91	)
Changes in ownership		—		—			—			—			(40	)		(40	)
Other		—		—			—			—			(3	)		(3	)

Balance, December 31, 2007	$	—	$	1,521		$	122		$	215		$	288		$	2,146

Comprehensive income
Net income		—		—			158			—			124			282
Foreign currency translation		—		—			—			(343	)		(43	)		(386	)
Minimum pension liability adjustments, net of income tax of $16 million		—		—			—			32			—			32
Net unrealized loss on qualifying derivatives, net of income tax of $2 million		—		—			—			(43	)		—			(43	)
Change in fair value of available-for-sale securities		—		—			—			(62	)		—			(62	)
Other		—		—			—			(3	)		—			(3	)

Total comprehensive income							158			(419	)		81			(180	)
Issuance of new shares		—		223			—			—			—			223
Compensation under stock incentive plan		—		7			—			—			—			7
Dividends		—		—			—			—			(161	)		(161	)
Changes in ownership		—		—			—			—			229			229
Other		—		3			—			—			(2	)		1

Balance, December 31, 2008	$	—	$	1,754		$	280		$	(204	)	$	435		$	2,265

See notes to consolidated financial statements.

F-34

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 (collectively, “Holding Companies”), and operating companies (collectively, “AEI” or the “Company”). AEI, through its investments, is involved principally in power distribution, power generation, natural gas transportation and services, natural gas distribution, and retail fuel sales entirely outside of the United States of America. 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, 2008, 51% of Elektra’s common stock is indirectly owned by the Parent Company. On October 12, 2005, Ashmore Energy International Limited (“AEIL”) 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.

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. In June 2007, the debt interest in one of the holding companies, which held controlling interests in Empresa Distribuidora de Energía Norte, S.A. (“EDEN”), an Argentine electrical distribution company, was exchanged for equity interests in EDEN. The debt interests in a separate holding company, which holds controlling interests in an Argentine gas distribution company, are expected to be exchanged for equity interests in such holding or operating company (see Note 19). The debt interest of a third Argentine holding company was sold in 2008 (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 the remaining 51% 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.

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.

F-35

The operating companies of AEI as of December 31, 2008 include direct and indirect investments in the international businesses described below and are collectively referred to as the “Operating Companies”:


	2008
	Ownership	2008 Accounting	Location of
Company Name	Interest (%)	Method	Operations	Segment

Accroven SRL (“Accroven”)^(a)	49.25	Equity Method	Venezuela	Natural gas transportation and services
Beijing Macro Gas Link Co. Ltd (“BMG”)^(b)(c)	70.00	Consolidated	China	Natural gas distribution
Gas Natural de Lima y Callao S.A. (“Calidda”)^(b)	80.85	Consolidated	Peru	Natural gas distribution
Chilquinta Energia S.A. (“Chilquinta”)^(b)(d)	50.00	Equity Method	Chile	Power distribution
DHA Cogen Limited (“DCL”)^(c)	59.94	Consolidated	Pakistan	Power generation
Distribuidora de Electricidad Del Sur, S.A. de C.V. (“Delsur”)^(b)	86.41	Consolidated	El Salvador	Power distribution
Empresa Distribuidora de Energia Norte, S.A. (“EDEN”)^(b)	90.00	Consolidated	Argentina	Power distribution
Elektra Noreste S.A. (“Elektra”)	51.00	Consolidated	Panama	Power distribution
Elektrocieplownia Sp. z.o.o. (“ENS”)^(a)	100.00	Consolidated	Poland	Power generation
Elektro — Eletricidade e Serviços S.A. (“Elektro”)^(a)	99.68	Consolidated	Brazil	Power distribution
Emgasud S.A. (“Emgasud”)(c)	31.89	Equity Method	Argentina	Power generation
Empresa Energetica Corinto Ltd. (“Corinto”)^(a)(b)(e)	50.00	Consolidated	Nicaragua	Power generation
EPE — Empresa Produtora de Energia Ltda. (“EPE”)^(a)(f)	50.00	Consolidated	Brazil	Power generation
Empresa Electrica de Generacion de Chilca S.A. (“Fenix”)^(c)	85.00	Consolidated	Peru	Power generation
Gas Transboliviano S.A. (“GTB”)^(a)(g)	17.65	Cost Method	Bolivia	Natural gas transportation and services
GasOcidente do Mato Grosso Ltda. (“GOM”)^(a)(f)	50.00	Consolidated	Brazil	Natural gas transportation and services
GasOriente Boliviano Ltda. (“GOB”)^(a)(f)	50.00	Consolidated	Bolivia	Natural gas transportation and services
Generadora San Felipe Limited Partnership (“Generadora San Felipe”)^(a)(b)(h)	100.00	Consolidated	Dominican Republic	Power generation
Jaguar Energy Guatemala LLC (“Jaguar”)^(c)	100.00	Consolidated	Guatemala	Power generation
Jamaica Private Power Corporation (“JPPC”)^(b)	84.42	Consolidated	Jamaica	Power generation
Luoyang Yuneng Sunshine Cogeneration Company Limited (“Luoyang”)^(c)	50.00	Consolidated	China	Power generation
Operadora San Felipe Limited Partnership (“Operadora San Felipe”)^(a)(b)(h)	100.00	Consolidated	Dominican Republic	Power generation
Peruvian Opportunity Company SAC (“POC”)^(b)(d)	50.00	Equity Method	Peru	Power distribution
Promigas S.A. E.S.P. (“Promigas”)^(a)(c)	52.13	Consolidated	Colombia	Natural gas transportation and services, Natural gas distribution and Retail fuel
Puerto Quetzal Power LLC (“PQP”)^(a)(b)	100.00	Consolidated	Guatemala	Power generation
Subic Power Corp. (“Subic”)^(a)	50.00	Equity Method	Philippines	Power generation
Tipitapa Power Company Ltd (“Tipitapa”)^(c)	100.00	Consolidated	Nicaragua	Power generation
Tongda Energy Private Limited (“Tongda”)^(b)	100.00	Consolidated	China	Natural gas distribution
Trakya Elektrik Uretim ve Ticaret A.S. (“Trakya”)^(a)	59.00	Consolidated	Turkey	Power generation
Transborder Gas Services Ltd. (“TBS”)^(a)(f)	50.00	Consolidated	Brazil, Bolivia	Natural gas transportation and services
Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. TBG (“TBG”)^(a)(i)	4.00	Cost Method	Brazil	Natural gas transportation and services
Transredes-Trasporte de Hidrocarburos S.A. (“Transredes”)^(a)(g)	1.28	Cost Method	Bolivia	Natural gas transportation and services


(a)		Acquired in 2006 as part of the step acquisition of PEI.
(b)		The Company’s initial or additional interest was purchased during 2007 (see Note 3).
(c)		The Company’s initial or additional interest was purchased during 2008 (see Note 3).

F-36


(d)		The Company’s initial interest was acquired 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”).
(e)		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).
(f)		These four companies comprise the integrated project “Cuiabá”.
(g)		As explained further in Note 3, the Company’s ownership in Transredes, through a 50.00% ownership in the holding company TR Holdings Ltda. (“TR Holdings”), decreased from 25% to 0% and the Company’s indirect ownership in GTB through Transredes decreased from 12.75% to 0%. The company also maintains a 1.28% direct ownership interest in Transredes. Total direct and indirect ownership in GTB is 17.65% as of December 31, 2008. Due to the decrease in ownership, the Company’s investments in Transredes and GTB are now accounted for using the cost method.
(h)		The Company comprises an integrated part of the operation referred to collectively as “San Felipe”.
(i)		Ownership interest based on direct ownership. Total ownership, including indirect interests held through TR Holdings, is 4.21%.

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.	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 generally accepted accounting principles in the United States of America (“U.S. GAAP”).

Acquisition Accounting — Assets acquired and liabilities assumed in business combinations are recorded on the Company’s consolidated balance sheet in accordance with the purchase method of accounting which requires that the cost of the acquisition be allocated to assets acquired and liabilities assumed based on their estimated fair value at the date of acquisition. The Company consolidates assets and liabilities from acquisitions as of the purchase date and includes earnings from acquisitions in the consolidated statement of operations from the purchase date. For certain acquisitions completed in 2008, the Company is still finalizing its purchase price allocation primarily related to the valuation of property, plant and equipment and intangibles (see Note 3). 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 a maturity of three months or less at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.

Restricted Cash — Restricted cash includes cash and cash equivalents that are restricted as to withdrawal or usage. Restrictions primarily consist of restrictions imposed by the financing agreements, such as security deposits kept as collateral, debt service reserves, maintenance reserves, and restrictions imposed by long-term power purchase agreements. Restrictions on cash and cash equivalents extending for a period greater than one year have been classified as non-current in other assets.

F-37

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 (Elektro, Elektra and certain subsidiaries of Promigas) that are subject to the provisions of 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 it is a probable that future revenue at least equal to the costs incurred will be billed and collected through approved rates. If future recovery of costs is not considered probable, the incurred cost is recognized as an expense. Regulatory liabilities are recorded for amounts expected to be passed to the customer as refunds or reductions on future billings.

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		3-50 years
Pipelines		25-50 years
Power generation equipment		18-40 years
Buildings		5-50 years
Vehicles		3-15 years
Furniture and fixtures		4-10 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 component of accumulated other comprehensive income (loss) in shareholders’ equity until realized. At each period end, in order to evaluate the impairment, for securities whose market value is less than its costs, the Company applies a systematic methodology which considers the severity and duration of any impairment as well as any qualitative factors that may indicate the likelihood that such impairment is other-than-temporary. Held-to-maturity securities are those investments that the Company has the ability and intent to hold until maturity. Held-to-maturity securities are recorded at cost, adjusted for the amortization of premiums and discounts, which approximates market value.

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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 and land use rights, continuing customer relationships and trademarks. The power purchase agreements have a definite 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 9 years. Customer relationships, trademarks and amortizable concession and land use rights are amortized over the life of the contracts.

Asset Retirement Obligations — The Company records liabilities for the fair value of the retirement and removal costs of long-lived assets in the period in which it is incurred adjusted for the passage of time and revisions to previous estimates, if the fair value of the liability can be reasonably estimated. The Company’s asset retirement obligations were not material at either December 31, 2008 or 2007.

Deferred Financing Costs — Financing costs are deferred and amortized over the financing period using the effective interest rate method.

Revenue Recognition — The Company’s consolidated revenues are attributable to sales and other revenues associated with the transmission and distribution of power; sales from the generation of power; and the wholesale and retail sale of gasoline and compressed natural gas (“CNG”). Power distribution sales to final customers are recognized when power is provided. Revenues that have been earned but not yet billed are accrued based upon the estimated amount of energy delivered during the unbilled period and the approved or contractual billing rates for each category of customer. Unbilled revenues were $130 million and $134 million as of December 31, 2008 and 2007, respectively. Revenues received from other power distribution companies for use of the Company’s basic transmission and distribution network are recognized in the month that the network services are provided. 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. Revenues from sales of gasoline and CNG are recognized when gases are delivered.

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 related to gas sales agreements are received from new customers in advance and are recognized over the shorter of the estimated life of the customer relationship or the life of the concession agreement, as applicable. The cumulative difference between the up-front connection fees received and the amount recognized in revenue is reflected as deferred revenue on the consolidated balance sheet.

Earnings Per Share — Basic earnings per share are calculated by dividing net earnings attributable to AEI 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 from calculating diluted earnings per share if their inclusion is anti-dilutive.

Income Taxes — Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The Company establishes a valuation allowance when it is more likely than not that all or

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a portion of a deferred tax asset will not be realized. The Company adopted Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), on January 1, 2007, and recorded a reduction to beginning retained earnings of less than $1 million. See Note 16.

Derivatives — The Company may enter into various derivative transactions in order to hedge its exposure to commodity, foreign currency, and interest rate risk. The Company reflects all derivatives as either assets or liabilities on the consolidated balance sheet at their fair value. All changes in the fair value of the derivatives are recognized in income unless specific hedge criteria are met. Changes in the fair value of derivatives that are highly effective and qualify as cash flow hedges are reflected in accumulated other comprehensive income (loss) and recognized in income when the hedged transaction occurs or no longer is probable of occurring. 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.

Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on a quarterly basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period. Hedge accounting is discontinued prospectively when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in accumulated other comprehensive income (loss) related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.

Pension Benefits — Employees in the United States and in some of the foreign locations are covered by various retirement plans provided by AEI or the respective Operating Companies. The types of plans include defined contribution and savings plans, and defined benefit plans. Expenses attributable to the defined contribution and savings plans are recognized as incurred. Expenses related to the defined benefit plans are determined based on a number of factors, including benefits earned, salaries, actuarial assumptions, the passage of time, and expected returns on plan assets. In certain countries, including Panama, El Salvador and Colombia, local labor laws require the Company to pay severance indemnities to employees when their employment is terminated. In Argentina, EDEN is required to pay certain benefits to employees upon retirement. The Company accrues these benefits based on historical experience and third party evaluations.

Stock-Based Compensation — The Company has a long-term equity incentive compensation plan. The fair value of awards granted under the Company’s long-term equity incentive compensation plan is determined as of the date of the share grant, and compensation expense is recognized over the required vesting period.

Environmental Matters — The Company is subject to a broad range of environmental, health, and safety laws and regulations. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law. Established accruals are adjusted periodically due to new assessments and remediation efforts, or as additional technical and legal information become available.

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

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The Company has determined that the functional currency for some subsidiaries is the U.S. dollar due to their operating, financing, and other contractual arrangements. For the periods presented, the Operating Companies that are considered to have their local currency as the functional currency are EDEN and Emgasud in Argentina; Tongda, BMG and Luoyang in China; Elektro in Brazil; DCL in Pakistan; ENS in Poland; Chilquinta in Chile; Luz del Sur in Peru; 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 eliminate upon consolidation.

Use of Estimates — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting 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, assumptions used to test goodwill, intangible assets and equity and cost method investments for impairment, 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 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 became 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 was 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 statements of operations. The Company adopted the remaining requirements of SFAS No. 157 on January 1, 2009 and the adoption will impact on the recognition of nonfinancial assets and liabilities in future business combinations and the future determinations of impairment for nonfinancial assets and liabilities.

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 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. 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 nature and financial effects of the business combination. The Company adopted SFAS No. 141R on January 1, 2009 and will apply the provisions to any future business combinations.

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 adopted SFAS No. 160 on January 1, 2009 and has incorporated the changes in its financial statement presentation for all periods presented. The retrospective application of this

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standard reclassifies minority interest expense of $124 million, $65 million and $20 million for the years ended December 31, 2008, 2007 and 2006, respectively, as net income attributable to noncontrolling interests below net income in the presentation of net income attributable to AEI and reclassifies minority interest of $435 million, $288 million and $357 million as of December 31, 2008, 2007 and 2006, respectively, previously included in total liabilities as noncontrolling interests in total equity. It also separately reflects changes in noncontrolling interests in changes in equity and comprehensive income.

In November 2008, the FASB issued EITF Issue No. 08-6, Equity Method Investment Accounting Considerations. EITF Issue No. 08-6 establishes that the accounting application of the equity method is affected by the accounting for business combinations and the accounting for consolidated subsidiaries, which were affected by the issuance of SFAS No. 141R and SFAS No. 160. EITF Issue No. 08-6 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years, consistent with the effective dates of SFAS No. 141R and SFAS No. 160. The Company adopted EITF Issue No. 08-6 on January 1, 2009 and will apply the provisions to any future equity method investments.

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. The Company adopted SFAS No. 161 on January 1, 2009 and will include the required disclosures in its 2009 consolidated financial statements.


3.	ACQUISITIONS AND DISPOSALS

Acquisitions

2008 Acquisitions

Sociedad de Inversiones en Energía (“ 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 noncontrolling shareholders of SIE. Net income of noncontrolling interests of $55 million was also recognized as a result of the gain on sale. Incremental goodwill was recorded in the amount of $188 million related to this transaction. SIE’s balances and results of operations have been consolidated with those of the Company prospectively from January 2, 2008.

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A summary of the fair values of assets acquired and liabilities assumed as of the date of acquisition is as follows:


	SIE
	Millions of
	dollars (U.S.)

Current assets	$	86
Property, plant, and equipment, net		51
Goodwill		188
Intangibles		78
Other noncurrent assets		11

Assets acquired		414

Current liabilities		87
Long-term debt		66
Other long-term liabilities		17

Liabilities assumed		170

Noncontrolling interests		114

Net assets acquired	$	130

The $78 million of acquired intangible assets has been allocated to continuing customer relationships, trademarks and land use rights. The continuing customer relationships and the land use rights are being amortized based on the benefits expected to be realized considering the related expected cash flows. Trademarks have an indefinite life and will not be amortized, but will be evaluated annually for any impairment. The weighted average amortization period is estimated as 26 years for continuing customer relationships and 11 years for land use rights.

Unaudited Pro Forma Results of Operations

The following table reflects the consolidated pro forma results of operations of the Company as if the SIE acquisition and all 2007 acquisitions and disposals had occurred as of January 1, 2007.


	For the Year
	Ended
	December 31,
	2007
	Millions of
	dollars (U.S.)

Revenues	$	7,475
Cost of sales		5,676
Operations, maintenance, and general and administrative expenses		1,110
Operating income		821
Income before income taxes		462
Net income — noncontrolling interests		145
Income from continuing operations attributable to AEI		90
Basic earnings per share attributable to AEI	$	0.43

BMG — On January 30, 2008, the Company completed its acquisition of a 70.00% 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.

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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. 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 on September 11, 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 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 $10 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. Through December 31, 2008, the Company executed additional share subscription agreements for approximately $6 million that have resulted in an increase in the Company’s ownership to 59.94%. Subsequently, the Company increased its ownership to 60.22% through additional share subscriptions for less than $1 million. For further information regarding DCL, see Note 25.

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 natural gas-fired generating facility 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. The power generation plant construction is expected to be initiated in 2009 and completed in 2011.

A summary of the estimated fair values of the consolidated assets acquired and liabilities assumed during 2008 as of the date of acquisitions is as follows:


	BMG		Luoyang		Tipitapa		DCL		Fenix
	Millions of dollars (U.S.)

Current assets	$	56	$	15	$	22	$	30	$	1
Property, plant, and equipment, net		29		149		12		35		125
Goodwill		6		11		—		10		—
Intangibles, net		32		8		—		—		—
Other assets		6		—		3		67		1

Assets acquired		129		183		37		142		127

Current liabilities		35		76		8		47		5
Long-term debt		8		85		6		61		—
Other liabilities		8		2		5		—		8

Liabilities assumed		51		163		19		108		13

Noncontrolling interests		20		1		—		11		14

Net assets acquired	$	58	$	19	$	18	$	23	$	100

Of the $40 million of acquired intangible assets, $26 million was allocated to concession rights in BMG and $14 million to land use rights in BMG and Luoyang. The concessions rights will be amortized on a straight-line basis over the remaining life of the concessions. The land use rights will be amortized on a straight-line basis over the remaining life of the land use rights. The weighted average amortization period is 27 years for concession rights and 45 years for the land use rights.

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2008 Acquisition of equity investments

Emgasud — On November 28, 2008, AEI, through its wholly owned affiliates acquired a 28% equity interest in 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 noncontrolling 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 and increased its equity in Emgasud to 31.89%. The Company accounts for this investment under the equity method. The agreement with Emgasud provides for the acquisition by AEI or its affiliates of a total interest in Emgasud of up to 63.1%. The primary business of Emgasud is the ownership, operation and development of several gas power plants with a nominal generation capacity totaling 512 MW. The Company is in the process of finalizing its purchase price allocation.

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-fired 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 expected to be initiated in 2009 and 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 year ended December 31, 2008, Promigas acquired additional ownership interests in consolidated subsidiaries for $36 million in cash and recorded $14 million of goodwill as a result of the purchases. The Company is in the process of finalizing the purchase price allocations.

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, 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.

Cálidda — On June 28, 2007, AEI and Promigas acquired 100% of the equity ownership of Cálidda for $56 million in cash. AEI and Promigas own Cálidda through a 60/40 equity ownership split. Cálidda is a Peruvian natural gas distribution company that owns the concession to operate in the Lima and Callao provinces.

Tongda — On August 14, 2007, AEI acquired 100% of the equity of Tongda for $45 million in cash and recorded $9 million of non-deductible goodwill. Tongda is incorporated in Singapore and constructs urban gas pipelines, sells and distributes gas, and operates auto-filling stations in mainland China. As of December 31, 2008, Tongda held controlling interests in thirteen urban gas companies.

Corinto — In August and September 2007, AEI acquired 100% of Globeleq Holdings (Corinto) Limited, which held a 30% direct interest in Corinto, for $14 million in cash by exercising its right of first refusal under an existing agreement. Subsequently, AEI sold 50% of Globeleq Holdings (Corinto) Limited along with 15% (half of the interest acquired through the right of first refusal exercise) of the newly acquired indirect interest in Corinto for $7 million and began consolidating the accounts of Corinto based on the voting power controlled by AEI. Upon

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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, 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.

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% interest in Generadora San Felipe and an additional 50% interest in Operadora San Felipe for $14 million in cash and recorded $5 million of goodwill as a result of the purchases. The plant is located on the Dominican Republic’s north coast in the city of Puerto Plata.

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.

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 $1,768 million.

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 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 non-deductible goodwill and $20 million of recognized intangible assets comprised primarily of joint-operating agreements in its retail business.

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Dispositions

Transredes

On May 1, 2008, the Bolivian government issued Supreme decree No. 29541 (“Expropriation Decree”) pursuant to which it stated that the state-run oil and gas company, Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), would acquire 263,429 shares of Transredes from TR Holdings at a price of $48 per share. On June 2, 2008, the Bolivian government issued Supreme Decree No. 29586 pursuant to which it stated that it would nationalize 100% of the shares held by TR Holdings in Transredes at the price per share set forth in the May 1, 2008 Supreme Decree, subject to deductions for categories of contingencies specified in the decree. In October 2008, the Company reached a settlement with YPFB, recognized by the Bolivian government, pursuant to which YPFB agreed to pay to the Company $120 million in two installments. The first and second payments of $60 million each were made in October 2008 and March 2009, respectively. The Company accounted for its investment in Transredes under the equity method and recognized a gain of $57 million for the year ended 2008. The gain is presented in the (Gain) loss on disposition of assets line of the Consolidated Statement of Operations.

BLM

On March 14, 2007, the Company sold its indirect interest, which included the Company’s interest in all outstanding legal claims, in BLM. The Company recognized a gain of $21 million in the first quarter of 2007 as a result of the sale of BLM. 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 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.

Summarized financial information related to Vengas’ operations is as follows:


	For the Years 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		41		—

Unaudited Pro Forma Results of Operations

The following table reflects the comparative consolidated pro forma results of operations of the Company as if the 2007 and 2006 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
Income from continuing operations attributable to AEI		85		49
Basic earnings per share attributable to AEI	$	0.41	$	0.25

F-47


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. EPE and Furnas are currently engaged in an arbitration on this issue. 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 applied, it was 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 Consolidated Statement of Operations. 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 of December 31, 2008, the Company determined, based on the continuing lack of gas supply and status of the arbitration, as described in Note 25, that the power supply agreement should no longer be accounted for as an in-substance financing lease. As a result, the lease receivable balance was removed from the Company’s accounts and property, plant and equipment was recorded at the net carrying amount, which is less than fair value. As a result of terminating lease accounting, no net adjustment was required to be charged to income. The fair value of the property, plant and equipment 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.

As a result of the above, 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.

Synthesis Energy Systems, Inc. (“SES”) — The Company has a 3.65% interest in SES, an energy and technology company that builds, owns and operates coal gasification plants in China and the U.S. Due to a severe decline in the publicly-traded equity value of SES, the Company recorded a $12 million impairment of its $16 million cost method investment during the fourth quarter of 2008.


5.	(GAIN) LOSS ON DISPOSITION OF ASSETS

(Gain) loss on disposition of assets consists of the following:


	For the Years Ended December 31,
	2008			2007			2006
	Millions of dollars (U.S.)

Gain on exchange for additional shares of SIE (see Note 3)	$	(68	)	$	—		$	—
Gain on nationalization of Transredes (see Note 3)		(57	)		—			—
Loss on sale of operating equipment		18			10			7
Loss on sale of debt securities (see Note 13)		14			—			—
Gain on sale of BLM (see Note 3)		—			(21	)		—
Gain on sale of shares of Promigas		—			(10	)		—

	$	(93	)	$	(21	)	$	7

F-48

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.

During 2008, $5 million of cumulative translation adjustments was recognized in (gain) loss on disposition of assets as a result of the nationalization of Transredes and the exchange for additional shares of SIE noted above.


6.	OTHER INCOME (EXPENSE), NET

Other income (expense), net, consists of the following:


	For the Year Ended December 31,
	2008			2007			2006
	Millions of dollars (U.S.)

Dividend income	$	3		$	3		$	—
Gain (loss) on derivatives		(2	)		(13	)		2
Other		8			(12	)		5

	$	9		$	(22	)	$	7

The Company recognized $(2) million, $1 million and $2 million gain (loss) in 2008, 2007 and 2006, respectively, for the ineffective portion of interest rate swaps that qualified for hedge accounting treatment (see Note 19). The Company also recognized $14 million loss related to foreign currency derivative transactions in 2007.


7.	CASH AND CASH EQUIVALENTS

Cash and cash equivalents include the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Parent Company	$	284	$	31
Consolidated Holding and Service Companies		35		157
Consolidated Operating Companies		417		328

Total cash and cash equivalents	$	736	$	516


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Brazilian Real	$	111	$	133
Colombian Peso		96		50
Chinese Renminbi		15		—
Chilean Peso		14		—
Polish Zloty		8		4
Argentinean Peso		7		6
Peruvian Nuevo Sol		2		8
Jamaican Dollar		2		—
Other		5		4

Total foreign currency cash and cash equivalents	$	260	$	205

F-49

Restricted cash consists of the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Current restricted cash:
Restricted due to power purchase agreements	$	4	$	5
Collateral and debt reserves for financing agreements		63		78
Other		16		12

Total current restricted cash		83		95
Noncurrent restricted cash (included in other assets, see Note 13):
Restricted due to long-term power purchase agreements		5		56
Amounts in escrow accounts related to taxes		24		25
Collateral and debt reserves for financing agreements		8		47
Other		12		—

Total non-current restricted cash		49		128

Total restricted cash	$	132	$	223


8.	INVENTORIES

Inventories consist of the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Materials and spare parts	$	141	$	78
Fuel		98		39

Total inventories	$	239	$	117


9.	PREPAIDS AND OTHER CURRENT ASSETS

Prepaids and other current assets consist of the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Prepayments	$	29	$	30
Regulatory assets		25		30
Deferred income taxes		71		88
Receivable from YPFB (see Note 3)		60		—
Taxes other than income		36		31
Government subsidy — Delsur		20		7
Net investments in direct financing leases (see Notes 3 and 13)		10		—
Current marketable securities		7		2
Other		126		75

Total	$	384	$	263


10.	PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant, and equipment, net consist of the following:


	December 31,
	2008			2007
	Millions of dollars (U.S.)

Machinery and equipment	$	1,888		$	1,924
Pipelines		777			745
Power generation equipment		862			432
Land and buildings		378			117
Vehicles		29			20
Furniture and fixtures		31			13
Other		106			108
Construction-in-process		209			143

Total		4,280			3,502
Less accumulated depreciation and amortization		(756	)		(467	)

Total property, plant and equipment, net	$	3,524		$	3,035

F-50

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 $1,082 million and $1,389 million at December 31, 2008 and 2007, 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 $132 million and $143 million at December 31, 2008 and 2007, respectively.

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 equipment balance, net, was $849 million and $614 million at December 31, 2008 and 2007, respectively.

Property, plant, and equipment of several Operating Companies is pledged as collateral for their respective long-term financings (see Note 15).

Depreciation and amortization expense is summarized as follows:


	For the Years Ended December 31,
	2008		2007		2006
	Millions of dollars (U.S.)

Depreciation and amortization of property, plant and equipment, including those recorded under capital leases	$	223	$	184	$	55
Amortization of intangible assets, net		45		33		4

Total	$	268	$	217	$	59

The Company capitalized interest of $12 million, $5 million and $6 million for each of the years ended December 31, 2008, 2007 and 2006, respectively.


11.	INVESTMENTS IN AND NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES

The Company’s investments in and notes receivable from unconsolidated affiliates consist of the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Equity method:
Accroven	$	24	$	14
BMG’s equity method investments		1		—
Chilquinta		266		330
EEC Holdings		7		7
GTB		—		14
Emgasud (see Note 3)		49		—
POC		341		344
Promigas’ equity method investments		41		84
Subic		9		7
Tecnored		21		24
TR Holdings (see Note 3)		—		58

Total investments — equity method		759		882
Total investments — cost method		28		27

Total investments in unconsolidated affiliates		787		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	$	907	$	1,028

F-51

The Company’s share of the underlying net assets of its investments at fair value in POC, Chilquinta, Tecnored and Emgasud was less than the carrying amount of the investments. The basis differential of $205 million represents primarily indefinite-lived intangible concession rights and goodwill which are tested annually for impairment.

Except for the $205 million of goodwill and intangibles noted above, the Company’s share of the underlying net assets of its remaining equity investments exceeded the purchase price of those investments. The credit excess of $36 million as of December 31, 2008 is being amortized into income on the straight-line basis over the estimated useful lives of the underlying assets.

The Company’s equity method investment in Chilquinta decreased by $64 million to $266 million as of December 31, 2008 primarily due to the depreciation of the Chilean Peso relative to the U.S. dollar during 2008, partially offset by equity earnings.

Promigas’ equity method investments decreased by $43 million to $41 million as of December 31, 2008 primarily due to the consolidation of SIE in 2008, which in 2007 was an equity method investment. (see Note 3).

Equity income (loss) from unconsolidated affiliates is as follows:


	For the Years Ended December 31,
	2008			2007		2006
	Millions of dollars (U.S.)

Accroven	$	16		$	12	$	—
BMG’s equity (loss) from investments in unconsolidated affiliates		(1	)		—		—
Chilquinta		32			1		—
GTB		1			5		2
PEI (see Note 1)		—			—		30
POC		32			1		—
Promigas		—			—		3
Promigas’ equity income from investments in unconsolidated affiliates		14			29		—
Subic		12			10		4
Tecnored		4			—		—
TR Holdings		7			18		(2	)

Total	$	117		$	76	$	37

Dividends received from unconsolidated affiliates amounted to $67 million, $32 million and $9 million for the years ended December 31, 2008, 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 as of December 31, 2008 are as follows:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Combined Balance Sheet data
Current assets	$	662	$	1,265
Noncurrent assets		2,126		3,864
Current liabilities		470		930
Noncurrent liabilities		968		2,070

F-52


	For the Years Ended December 31,
	2008		2007		2006
	Millions of dollars (U.S.)

Combined Income Statement data
Revenues	$	1,616	$	4,486	$	429
Cost of sales		940		3,522		42
Net income		227		266		43

As a result of the nationalization of Transredes (see Note 3), the Company’s accounting for its investment in Transredes and GTB changed from the equity method to the cost method in 2008. The remaining investments accounted for by the Company using the cost method are SES (see Note 4) and TBG.


12.	GOODWILL AND INTANGIBLES

The Company’s changes in the carrying amount of goodwill are as follows:


	December 31,
	2008			2007
	Millions of dollars (U.S.)

Balance at January 1	$	402		$	290
Acquisitions:
New acquisitions (see Note 3)		225			103
Acquired goodwill from consolidation of new acquisitions		35			—
Translation adjustments and other		(48	)		9

Balance at December 31	$	614		$	402

The Company’s carrying amounts of intangibles are as follows:


	December 31, 2008						December 31, 2007
	Cost		Accum. Amort.		Net		Cost		Accum. Amort.		Net
	Millions of dollars (U.S.)						Millions of dollars (U.S.)

Amortizable intangibles:
Customer relationships	$	171	$	20	$	151	$	81	$	7	$	74
Concession and land use rights		152		8		144		88		2		86
Power purchase agreements and contracts		64		43		21		58		19		39
Software costs		42		21		21		12		6		6
Other		4		4		—		4		2		2

Total amortizable intangibles	$	433	$	96		337	$	243	$	36		207
Nonamortizable intangibles:
Elektra concession rights						31						30
Promigas trademarks						25						—

Total nonamortizable intangibles						56						30

Total intangibles					$	393					$	237

Goodwill — AEI evaluates goodwill for impairment each year as of August 31 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 2008 and 2007, reporting units were generally acquired in separate transactions. In 2006, the acquisition of PEI and Promigas resulted in the acquisitions of several businesses with multiple reporting units. Promigas reporting units are primary segments at the Promigas level. The Company also tests for impairment if certain events occur that more likely than not reduce the fair value of the reporting unit below its carrying value. There was no goodwill impairment recognized in the three years ended December 31, 2008.

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 held by several power generation businesses. The amortization of the power purchase agreements may result in income or expense due to the difference between contract rates and projected market rates that are subject to change over the contract’s life. At December 31, 2008 and 2007, the Company also has intangible liabilities of $57 million and $65 million, respectively, which represent unfavorable power purchase agreements held by three of the power generation businesses (see Note 17).

F-53

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 25). An intangible asset in the amount of $6 million associated with the long-term power purchase agreement was written off and included in amortization expense in 2007.

The following table summarize the estimated amortization expense for the next five years and thereafter for intangible assets as of December 31, 2008:


	Millions of dollars (U.S.)

2009	$	31
2010		26
2011		23
2012		21
2013		18
Thereafter		218

Total	$	337


13.	OTHER ASSETS

Other assets consist of the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Long-term receivables from customers:
Corporation Dominicana de Empresas Electricias Estatales (“CDEEE”)	$	169	$	161
Promigas customers		128		113
Elektro customers		8		12
Furnas		—		11
Other		1		1

		306		298
Net investments in direct financing leases (see Notes 3 and 4)		63		174
Regulatory assets		49		10
Deferred income taxes		265		334
Investments in debt securities		192		306
Restricted cash (Note 7)		49		128
Deferred financing costs, net		22		22
Other miscellaneous investments		7		10
Other deferred charges		160		94
Other noncurrent assets		86		59

Total	$	1,199	$	1,435

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 $169 million ($161 million in 2007) 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.

Promigas, through its subsidiaries in the local natural gas distribution sector, has unsecured long-term receivables with customers for installation services and other notes receivables, with interest rates at an average of 31.5% annually, collected in Colombian pesos through monthly installments payable over a period of one to six years. The interest rate applied each year is the maximum legal rate allowed by the Superintendent of Finance, the Colombian regulatory body.

Net investment in direct financing lease — 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. As of December 31, 2008, the Company determined, based on the continuing lack of gas supply and status of the arbitration, that the power supply agreement should no longer be

F-54

accounted for as an in-substance financing lease. As a result, the lease receivable balance was reclassified to property, plant and equipment. In addition, the Company acquired DCL in July 2008 and determined that the power purchase agreement of DCL should be accounted for as a direct financing lease.

The components of the net investments in direct financing leases for DCL as of December 31, 2008 and EPE as of December 31, 2007 are as follows:


	December 31,
	2008			2007
	Millions of dollars (U.S.)

Total minimum lease payments to be received	$	440		$	484
Less amounts representing executory costs		(180	)		(208	)

Total minimum lease receivables		260			276
Less allowance for uncollectibles		(9	)		(40	)
Less unearned income		(178	)		(82	)
Less estimated residual value of leased properties		—			20

Net investments in direct financing leases		73			174
Current portion		10			—

Long-term portion	$	63		$	174

As of December 31, 2008, the current portion of net investment in the DCL direct financing lease is classified in prepaids and other current assets. As of December 31, 2008, the EPE direct financing lease was constructively terminated (see Note 4) and, therefore, no balances are included above. As of December 31, 2007, as a result of the allowance established in connection with the arbitration, there was no current balance for EPE direct financing lease. The entire lease investment in EPE direct financing lease is considered noncurrent as of December 31, 2007.

Investments in debt securities — The following table reflects activity related to investments in debt securities:


	For the Years Ended December 31,
	2008			2007			2006
	Millions of dollars (U.S.)

Available-for-sale debt securities:
Matured debt securities included in debt restructuring agreements:
Fair value at beginning of period	$	282		$	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		(38	)		—			(12	)
Conversion to equity securities		—			(74	)		—
Realized loss on sale of securities		(14	)		—			—
Unrealized net gain (loss) affecting other comprehensive income		(62	)		1			34

Fair value at end of period		168			282			268

Corporate debt securities:
Fair value at beginning of period		—			24			24
Unrealized net loss affecting other comprehensive income		—			(24	)		—

Fair value at end of period		—			—			24

Total available-for-sale securities, end of period		168			282			292

Held-to-maturity debt securities:
Participation in commercial bank loan portfolio		22			22			—
Promissory notes		2			2			2

Total held-to-maturity securities, beginning and end of period		24			24			2

Total	$	192		$	306		$	294

The Company’s available-for-sale securities as of December 31, 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 19.

F-55


14.	ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Employee liabilities	$	48	$	45
Deferred income taxes		10		56
Other taxes:
Value added taxes		40		42
Taxes on revenues		13		18
Withholding taxes		25		19
Governmental taxes		11		11
Other		31		14
Interest		42		30
Customer deposits		64		14
Dividends payable to noncontrolling interests		17		15
Regulatory liabilities		35		89
Tax and legal contingencies		19		15
Cost Increase Protocol payable — Trakya (see Note 17)		37		—
Deferred revenues		32		22
Other accrued expenses		47		55
Other		123		80

Total	$	594	$	525


15.	LONG TERM DEBT

Long-term debt consists of the following:


	Variable or	Interest	Final	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	4.5	2014	$	936		$	979
Revolving credit facility, U.S. dollar	Variable	3.8	2012		390			345
Synthetic revolving credit facility, U.S. dollar	Variable	3.5	2012		105			105
PIK note, U.S. dollar	Fixed	10.0	2018		352			319
Debt held by consolidated subsidiaries:
Cálidda, U.S. dollar	Variable	2.1 - 5.3	2009 - 2015		87			82
Cuiabá, U.S. dollar notes	Fixed	5.9	2015 - 2016		97			99
Delsur, U.S. dollar	Variable	6.5 - 7.0	2015		73			100
DCL, Pakistan Rupee	Variable	14 - 18.6	2009 - 2019		77			—
EDEN, U.S. dollar	Variable	4.2	2013		37			44
Elektra, U.S. dollar senior notes	Fixed	7.6	2021		99			99
Elektra, U.S. dollar debentures	Variable	6.9	2018		20			—
Elektra, U.S. dollar revolving credit facility	Variable	4.3 - 5.5	2009		25			—
Elektro, Brazilian real debentures	Variable	15.5 - 22.8	2011		238			287
Elektro, Brazilian real note	Variable	5.0 - 12.3	2010 - 2020		132			127
ENS, Polish Zloty loans	Variable	7.5 - 8.0	2009 - 2018		67			77
Luoyang, Chinese Renminbi	Variable	6.1 - 13.0	2009 - 2016		133			—
PQP, U.S. dollar notes	Variable	4.2 - 4.9	2015		88			90
Promigas, Colombian peso debentures	Variable	15.1 - 15.9	2011 - 2012		116			129
Promigas, Colombian peso notes	Variable	12.0 - 14.0	2009 - 2011		534			253
Promigas, U.S. dollar notes	Variable	4.2 - 5.9	2012		291			26
Trakya, U.S. dollar notes	Fixed	—	2008		—			26
Trakya, U.S. dollar notes	Variable	—	2008		—			21
Others, U.S. dollar notes and Chinese Renminbi	Fixed and Variable	6.1 - 10.5	2009 -2014		65			56

					3,962			3,264
Less current maturities					(547	)		(749	)

Total				$	3,415		$	2,515

Interest rates reflected in the above table are as of December 31, 2008. The three-month U.S. dollar London Interbank Offered Rate (“LIBOR”) as of December 31, 2008 was 1.4%.

F-56

Long-term debt includes related party amounts of $603 million and $721 million as of December 31, 2008 and 2007, respectively, from shareholders associated with both the Company’s senior credit facility and PIK notes. Long-term debt also includes related party amounts of $97 million and $99 million as of December 31, 2008 and 2007, respectively, from loans provided to Cuiabá by other shareholders in the project.

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.)

2009	$	547
2010		500
2011		578
2012		784
2013		119
Thereafter		1,434

Total	$	3,962

The long-term debt held by the Operating Companies is nonrecourse and is not a direct obligation of the Parent Company. However, certain Holding Companies provide payment guarantees and other credit support for the long-term debt of some of the Operating Companies (see Note 25). Many of the financings are secured by the assets and a pledge of ownership of shares of the respective Operating Companies. The terms of the long-term debt include certain financial and nonfinancial covenants that are limited to each of the individual Operating Companies. These covenants include, but are not limited to, achievement of certain financial ratios, limitations on the payment of dividends unless certain ratios are met, minimum working capital requirements, and maintenance of reserves for debt service and for major maintenance. All consolidated subsidiaries, except for EDEN and DCL as mentioned below, were in compliance with their respective debt covenants as of December 31, 2008.

Senior Credit Facility — As of March 30, 2007, AEI refinanced its $1 billion credit facility originally dated May 23, 2006 with various financial institutions, raising funds under a new $1.5 billion credit facility, which consists of a $1 billion term loan, a $105 million synthetic revolver, and a $395 million revolver. The refinancing was treated as an early extinguishment of debt and the difference between the reacquisition price and the net carrying amount plus any previously capitalized costs and reacquisition costs was recognized as a loss on early retirement of debt in the amount of $26 million. The refinanced term loan amortizes 30% of the principal over seven years in equal quarterly principal payments, and the remaining outstanding principal 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 of 3% from the synthetic revolver and 0.5% for the revolver. At AEI’s election, the term loan accrues interest at LIBOR plus 3% or the rate most recently established by the designated administrative agent under the loan agreement as its base rate for dollars loaned in the United States plus 1.75%. The 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 covenants which restrict the activities of the Company. The more significant financial covenants include certain interest coverage ratios on a stand-alone basis and leverage ratios (net debt to earnings before interest, taxes, depreciation and amortization, as defined “EBITDA”) on a consolidated basis. The Company was in compliance with these debt covenants as of December 31, 2008. The senior credit facility does not require reserves for debt service. For further information regarding hedging activity related to this debt instrument, see Note 19.

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 $7 million was recorded. The cash proceeds from the original PIK notes issued were used to pay a portion of the purchase price in the PEI acquisition and for general corporate purposes. The existing Subordinated PIK Notes bear interest at 10%, and

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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 as follows: May 24, 2009-104%, May 24, 2010-106%, May 24, 2011 and thereafter-108%.

On March 11, 2009 the Company, upon amendment of the PIK Note Purchase Agreement, issued an option to all of our PIK note holders to exchange their PIK notes for ordinary shares of AEI. The option period is for up to one year. The initial exchange rate is 63 ordinary shares per $1,000 for each principal amount of notes exchanged. Additionally, the amendment allows the Company to purchase the PIK notes in the open market, subject to certain conditions. In March 2009, various Ashmore Funds, which holds PIK notes, agreed to exchange PIK notes and related interest receivable in the amount of $118 million for 7,412,142 shares of common stock.

Cálidda — The $27 million senior loan bears interest at LIBOR plus 3.9%. Principal is due in quarterly installments beginning April 2007 through April 2015. The loan is guaranteed with a mortgage on Cálidda’s fixed assets related to its gas distribution concession, which had a net book value at December 31, 2008 of $106 million. Cálidda and its external lenders signed a trust contract that established the transfer to the lenders of the rights to the collection and flow of funds received by Cálidda related to its gas distribution concession. This mortgage and trust contract established a first and preferred mortgage on Cálidda’s gas distribution concession and related assets, in favor of the lenders.

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 to March 2009 and the interest rate was increased to LIBOR plus 0.7%. The loan is collateralized with a $48 million letter of credit with a maximum facility of $47 million. The letter of credit is cash collateralized with $29 million.

Cuiaba — The debt consists of a group of unsecured promissory notes with the other shareholder bearing weighted average fixed interest rates of 5.9%. Principal and interest payments are due annually, with final maturities in 2015 and 2016. The notes contain certain prepayment and rollover provisions.

Delsur — Delsur entered into a $75 million senior secured term loan in August 2008 in order to refinance the $100 million bridge loan used to finance the Delsur acquisition. The additional bridge loan principal balance was primarily repaid with cash received from capital contributions made by the Company. The loan bears interest at LIBOR (with a 3% floor) plus a variable margin of 3.5% to 4%. The loan matures in 2015 and is secured by a debt service reserve account and the fixed assets of Delsur, with interest and principal payable quarterly. The fixed assets of Delsur had a net book value at December 31, 2008 of $76 million. Financial covenants include maintenance of certain leverage ratios, debt service coverage ratios and interest service coverage ratios.

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 are due quarterly with maturity in 2019. The outstanding balance of this facility as of December 31, 2008 is 4.686 billion Rupees ($59 million). The loan is secured by DCL’s fixed and current assets.

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DCL also has short-term bank loans of 1.638 billion Rupees ($18 million) for general working capital purposes and a proposed Phase II expansion. The loans bear interest at the KIBOR base interest rate on lending plus 3% to 4%. Interest is payable quarterly and the loans are secured by current assets.

For further information regarding notification of default from DCL’s lenders, see Note 25.

EDEN — The financing consists of an unsecured loan agreement maturing in 2013. Principal and interest are payable on a quarterly basis. The loan bears interest at LIBOR plus 2.8% in 2009 and LIBOR plus 3.3% for the remaining four years.

In order to complete the acquisition of AESEBA, which owned 90% of the equity of EDEN (see Note 3), a waiver from third party lenders of the debt mentioned above was required due to the following covenants: change in control, change in the operator and cross default. The transfer of shares from the previous owner to the Company was completed 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 $37 million is classified as current at December 31, 2008.

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, 2008. 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.

On October 20, 2008, in a public offering, Elektra issued a $20 million aggregate principal amount of unsecured and unsubordinated corporate bonds due October 20, 2018. The bonds rank pari passu amongst equal in right of payment with all other unsecured and unsubordinated obligations. The bonds bear interest at LIBOR plus 2.4% per annum, payable on a quarterly basis. Principal is due upon maturity. The proceeds from the offering of the bonds will be used to fund current and future capital expenditures and for general corporate purposes. The bonds are subject to additional terms and conditions which are customary for this transaction. Loan covenants include maintenance of debt coverage ratios and other provisions.

Elektra maintains revolving credit lines for an aggregate amount of $50 million to finance working capital and energy purchases from suppliers. The line of credit is unsecured and has a variable interest rate of LIBOR plus 1.5% to 2.5%, payable on a monthly basis. Floor rates of 5.5% and 5.8% exist for two of the revolving agreements. These facilities mature within one year from the date of issuance. In addition, certain of Elektra’s credit facilities require that it meet and maintain certain financial covenants, including debt coverage ratios and interest coverage ratios.

Elektro — The debt consists of public debentures issued in the amount of approximately 750 million Brazilian reais which were issued in three series that mature in equal installments 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 1.7% per year for the second and third series. Interest is payable annually for the first series and semiannually for the second and third series. The principal of the debentures are unsecured. Interest payments are secured through a pledge of funds held in a reserve account, which had a balance of $2 million and $5 million at December 31, 2008 and 2007, respectively. A balance of 550 million Brazilian reais ($238 million) remains outstanding for these public debentures as of December 31, 2008, 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 reais ($163 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 2020 and accrue interest based on the Global Reversion Reserve fund rate (“RGR”) plus 5% per year or on the Brazil long-term interest rate, Taxa de Juros de Longo Prazo (“TJLP”), plus spreads from 0.9% to 6%. As of

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December 31, 2008, the total principal balances of these financings were 306 million Brazilian reais ($132 million). These financings are secured either by a pledge of collections flow or by bank letter of guarantee.

A summary of the relevant interest rates and indices for Brazil is as follows:


	December 31,
	2008

CDI		12.3	%
IGP-M		9.8	%
RGR		0.0	%
TJLP		6.2	%

ENS — On April 1, 2008, ENS amended and converted its $77 million U.S. dollar denominated loan into an equivalent Polish zloty (“PLN”) loan concurrent with the change from its U.S. dollar-linked 20-year 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. In addition, ENS has amended its existing credit facility to extend the tenor by 3.5 years (including a 15-month grace period) and reduce the margin on interest rate to 1.1% — 1.4%. The loan is secured by all of ENS’s assets, which had a net book value at December 31, 2008 of $96 million, and a pledge of shares. The loan balance as of December 31, 2008 was 173 million Polish zloty ($58 million). Principal and interest payments are due quarterly. The loan requires reserves for debt service and maintenance. Together with the refinancing, a new 40 million Polish zloty ($14 million), three-year revolving working capital facility was also established. For further information regarding hedging activity related to this debt instrument, see Note 19. Given that the future revenues and credit facilities of ENS will be in Polish zloty, ENS changed its functional currency from U.S. dollars to Polish zloty as of April 1, 2008.

Luoyang — Luoyang obtained a 751 million 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 December 31, 2008 is 660 million Renminbi ($97 million). The loan is secured by an assignment of rights to the collection of the electricity and steam revenue of Luoyang. The loan agreement contains covenants which include certain restrictions on the disposal of fixed assets, changes in shareholding structure and providing guarantees to a third party. In November 2008, Luoyang signed a supplementary agreement with the China Development Bank to restructure the loan. Under this supplementary agreement, the timing of the principal payments remains unchanged but the payment amounts have been restructured. At the same time, all shareholders of Luoyang have signed a share pledge agreement with the China Development Bank. This share pledge agreement contains covenants which require pre-approval by the China Development Bank for dividend distributions.

Luoyang also has short-term bank loans of 248 million Renminbi ($36 million) for general working capital purposes. The loans bear interest at 1.1 to 1.5 times the PBOC rate and 6.1% to 13.0% per annum. Interest is payable monthly or quarterly and principal payments are due in 2009. The loans are secured by fixed assets and the land use rights of Luoyang, which have a net book value of $161 million at December 31, 2008.

PQP — The financing for PQP includes notes payable and a revolving line of credit with a syndicate of commercial banks. The notes have variable interest rates of LIBOR plus 2.8%, with principal payable semiannually and interest payable quarterly and mature in 2015. The notes have reserve requirements for debt service, which are revised quarterly on the debt service dates. For further information regarding hedging activity related to this debt instrument, see Note 19. The revolving line of credit is part of the same credit agreement as the notes, bearing a rate of 0.5% for unused portions, 1.7% for letters of credit issuance, and LIBOR plus 2.0% for outstanding amounts. The revolving credit line matures in 2012 and is renewable for one year periods through 2015. Both credit facilities are secured by all of PQP’s assets, which had a net book value as of December 31, 2008 of $100 million, including major power purchase and fuel supply contracts and PQP’s power barges.

Promigas — Promigas’s long-term debt financing consists of Colombian peso debentures, Colombian peso notes, and U.S. dollar notes with local and international commercial banks.

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The debentures were issued from 2001 to 2004 and accrue interest at the Colombian Consumer Price Index (“CCPI”) plus 7.4% to 7.5%. Interest is payable quarterly, semi-annually and annually. The debentures mature in 2011 (160 billion Colombian pesos or $71 million) and 2012 (100 billion Colombian pesos or $45 million).

The peso notes bear interest at rates ranging from 12% to 14%. The maturities of these notes vary from one to three years, with some principal payments due semiannually, while other loans were contracted under a bullet payment structure. Interest payments are due either monthly or quarterly. No assets are pledged as collateral under these loan facilities.

Promigas U.S. dollar notes have interest rates ranging from LIBOR to LIBOR plus 2.5%, maturities in 2012, interest payments due either quarterly or semiannually, and no collateral requirements.

SIE financing consists of various promissory notes with local commercial banks and a term loan with other financial institutions. The promissory notes are both denominated in Colombian peso, approximately $239 million, and U.S. dollar, approximately $8 million. Of the Colombian peso notes, $231 million bear various interest rates between 13.9% and 15.5%, while $8 million has a fixed interest rates ranging from 14.4% to 15.5%. Of the U.S. dollar notes, the note bears a variable interest rate of LIBOR plus 4.75%. Principal payments are due semiannually, with final maturities ranging from 2009 to 2011. Interest payments are due either quarterly or semiannually.

The term loan was created by a credit agreement entered into in December 2007 for an amount of up to $250 million. The first draw in December 2007 for an amount of $189 million and the second draw in January 2008 for the remaining $61 million contained terms of a maturity of 5 years and with payments delayed for the first 30 months of the term. The term loan bears interest at LIBOR plus 4.5% and is subject to leverage ratios. This is subordinated debt and is guaranteed by Gazel and other related affiliates.


16.	INCOME TAXES

Income Tax Provision — The provision for income taxes on income from continuing operations are comprised of the following:


	For the Years Ended December 31,
	2008			2007		2006
	Millions of dollars (U.S.)

Current :
Cayman Islands	$	—		$	—	$	—
Foreign		205			106		64

Total current		205			106		64

Deferred :
Cayman Islands		—			—		—
Foreign		(11	)		87		20

Total deferred		(11	)		87		20

Provision for income taxes	$	194		$	193	$	84

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Effective Tax Rate Reconciliation — A reconciliation of the Company’s income tax rate to its effective tax rate as a percentage of income before noncontrolling interest and taxes, is as follows:


	December 31,
	2008			2007			2006

Statutory tax rate — Cayman Island		0.0	%		0.0	%		0.0	%
Foreign tax rate differential		36.4	%		42.0	%		64.7	%
Tax credits		0.0	%		0.0	%		(1.1)	%
Change in valuation allowance		4.4	%		14.0	%		31.0	%

Effective tax rate		40.8	%		56.0	%		97.6	%

The effective tax rate reconciliation for the “Statutory Tax Rate — Cayman Islands” takes into account net losses of $200 million, $218 million and $88 million in 2008, 2007 and 2006, respectively, which do not generate a tax benefit by virtue of the 0% statutory tax rate in the Cayman Islands.

The Company provides for uncertain tax positions pursuant to FIN 48. Uncertain tax positions have been classified as non-current income tax liabilities unless expected to be paid in one year. The Company recognizes interest and penalties related to unrecognized tax benefits within the income tax expense line in the accompanying consolidated statement of operations. Accrued interest and penalties are included within the related tax liability line in the consolidated balance sheet.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits for the following years:


	For the Years Ended December 31,
	2008			2007
	Millions of dollars (U.S.)

Unrecognized tax benefit, January 1	$	50		$	51
Gross increases, tax positions in prior period		4			5
Gross decreases, tax positions in prior period		—			(12	)
Gross increases, tax positions in current period		12			16
Settlements		—			(1	)
Lapse of statute of limitations		(5	)		(9	)

Unrecognized tax benefit, December 31	$	61		$	50

Included in the balance of unrecognized tax benefits at December 31, 2008, are $50 million of tax benefits that, if recognized, would affect the effective tax rate.

Related to the unrecognized tax benefits noted above, the Company accrued penalties of $15 million and interest of $6 million during 2008 and in total, as of December 31, 2008, has recognized a liability for penalties of $61 million and interest of $35 million.

The Company does not believe it is reasonably possible that the total amount of the unrecognized tax benefits will significantly change within the next 12 months.

The Company is subject to taxation in various countries around the world. Certain income tax returns of the Company’s non-U.S. subsidiaries remain open to examination by the respective taxing authorities as follows:


Jurisdiction		Years

Argentina		2004-present
Bolivia		2005-present
Brazil		2004-present
Colombia		2006-present
Dominican Republic		1998-June 2001 and 2004-present
Panama		2006-present
Philippines		2005-present
Poland		2004-present
Turkey		2004-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

F-62

applicable tax law and intends to defend its positions through appropriate administrative and judicial processes. The Company believes it has adequately provided for any probable outcome 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,
	2008			2007
	Millions of dollars (U.S.)

Deferred tax assets:
Inventory	$	7		$	—
Goodwill		23			71
Accrued expenses		133			244
Operating losses and tax credit carryforwards		216			236
Reserves		101			—
Foreign currency and other		5			39
Valuation allowance		(193	)		(168	)

Total deferred tax assets		292			422
Deferred tax liabilities:
Fixed assets	$	(158	)	$	(201	)
Foreign currency and other		(7	)		(25	)

Total deferred tax liabilities		(165	)		(226	)

Total deferred tax assets (liabilities)	$	127		$	196

The Company has net operating loss carryforwards in several jurisdictions that expire between 2009 and 2018. The tax effected amount of these net operating loss carryforwards was $85 million at December 31, 2008 and $48 million at December 31, 2007. 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 $125 million at December 31, 2008 and $164 million at December 31, 2007.

The Company also had tax credits in jurisdictions in which the credit will never expire. The amounts of these credits were $0 million at December 31, 2008 and $1 million at December 31, 2007. 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.)

2009	$	4	$	—
2010		9		—
2011		5		—
2012		26		—
2013		14		1
Thereafter		27		5
Unlimited		125		—

Total	$	210	$	6

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 $193 million at December 31, 2008 and $168 million at December 31, 2007.

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17.	OTHER LIABILITIES

Other liabilities consist of the following:


	December 31,
	2008		2007
	Millions of dollars (U.S.)

Deferred revenue	$	437	$	414
Special obligations		192		241
Uncertain tax positions (see Note 16)		156		125
Notes payable to unconsolidated affiliates		109		120
Tax and legal contingencies (see Note 25)		68		81
Unfavorable power purchase agreements (see Note 12)		57		65
Taxes payable — San Felipe (see Note 25)		66		59
Capital lease obligations (see Note 13)		48		30
Cost Increase Protocol payable — Trakya		25		12
Interest		22		22
Pension and other postretirement benefits (see Note 24)		14		10
Regulatory liabilities		25		34
Other		112		63

Total	$	1,331	$	1,276

Special obligations — These obligations represent consumers’ contributions to the cost of expanding Elektro’s electric power supply system. The assets acquired using the funds provided by consumers or the assets provided to the Company by consumers under the regulations of special obligations, are currently depreciated based on the average assets’ useful lives as established by ANEEL — Agência Nacional de Energia Elétrica (“ANEEL”), the regulator of the Brazilian electricity sector. The special obligation balance began being amortized in August 2007 using the average depreciation rates of property, plant, and equipment.

Capital lease obligations — Summarized below are the future obligations relating to capital leases for certain pipelines and equipment in which Promigas and Elektro are the lessees. The related capital leases are recorded as obligations in the amount of $57 million ($37 million in 2007), with rates from 14% to 16%. At December 31, 2008 and 2007, the gross assets under capital leases were $57 million and $31 million and accumulated amortization amounted to $15 million and $5 million, respectively. The leases are all nonrecourse to AEI.

Aggregate maturities of the principal amounts of all capital lease obligations of AEI and its consolidated subsidiaries, for the next five years and in total thereafter, are as follows.


	Millions of
	dollars (U.S.)

2009	$	12
2010		18
2011		11
2012		16
2013		6
Thereafter		8

Future minimum lease payments		71
Less amount representing interest		14

Total	$	57

Cost Increase Protocol payable — During the third quarter of 2008, Trakya reached a settlement with the Turkish government with respect to a tariff adjustment under Trakya’s Cost Increase Protocol (“CIP”) and agreed to pay approximately $63 million over a two-year period commencing in September 2008, with such payments to be made by reduction of invoices to 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%.


18.	LEASE COMMITMENTS

The Company determined that the power purchase agreements entered into by Trakya, San Felipe, JPPC and Tipitapa and certain arrangements of Promigas subsidiaries are operating leases.

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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.)

2009	$	10	$	174
2010		1		71
2011		1		72
2012		1		68
2013		1		68
Thereafter		59		151

Total	$	73	$	604

For the years ended December 31, 2008, 2007 and 2006, contingent rental income from the above mentioned operating leases was $10 million, $10 million and $2 million, respectively.

The company also entered into various operating leases for land, offices, office equipment and vehicles as lessee. Future minimum lease payments associated with all operating leases to be paid for the next five years and in total thereafter are as follows:


	Millions of
	dollars (U.S.)

2009	$	16
2010		13
2011		11
2012		10
2013		10
Thereafter		31

Total	$	91


19.	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 deferred 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.

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The following table represents AEI’s assets and liabilities that are measured at fair value on a recurring basis:


			Fair Value Measurement at Reporting Date Using
			Final Quoted Prices
			in Active Markets		Significant Other		Significant
			for Identical Assets		Observable Inputs		Unobservable
	December 31, 2008		(Level 1)		(Level 2)		Inputs (Level 3)
			Millions of dollars (U.S.)

Available-for-sale securities	$	168	$	—	$	168	$	—
Derivatives		1		—		1		—

Total assets	$	169	$	—	$	169	$	—

Derivatives	$	64	$	—	$	64	$	—

Total liabilities	$	64	$	—	$	64	$	—

Available - for-sale securities — The Company’s available-for-sale securities currently 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 were convertible upon governmental approval into equity interests in the holding company pursuant to a debt restructuring agreement, entered into in 2005. On January 8, 2009, the Company terminated the agreement by providing written notification of its desire to terminate to the signators of the agreement pursuant to the terms of the restructuring agreement. These securities were originally contributed to the Company or acquired from March 2006 through January 2007. The aggregate cost of the CIESA debt securities from various contribution and acquisition dates totals $245 million. The securities represent approximately 92% of the total debt of CIESA and 100% of its matured securities.

The approximate current fair market value of the securities at December 31, 2008 and December 31, 2007 was $168 million and $233 million, respectively. The value as of December 31, 2008 considers the termination of the debt restructuring agreement and the underlying equity value of TGS, based on CIESA’s ownership of 55% of TGS. The value at December 31, 2007 is based on 25.5% of TGS equity value considering the terms of the debt restructuring agreement at that time. 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 December 31, 2008 has resulted in $77 million of unrealized losses, or 31% less than cost, in the Company’s other accumulated comprehensive income account.

At each period end, including as of December 31, 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 collection of the value of the securities in a bankruptcy or a negotiated resolution. The debt securities, which represent a claim against the assets of CIESA (consisting primarily of the 55% interest in TGS), could still ultimately be exchanged for CIESA or TGS equity. At December 31, 2008, the approximate fair value of the TGS stock that would be expected to be received was $168 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 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 December 31, 2008.

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agreement. AEI does not believe that there is any merit to the suit and is vigorously defending the claim. Separately, in February 2009, AEI, as the sole shareholder of CIESA’s outstanding notes, filed a petition in Argentina for the involuntary bankruptcy liquidation of CIESA. The Argentine court granted our petition, and, in April 2009, the Company initiated bankruptcy proceedings against CIESA. The Company will request the enforcement of our debt before the bankruptcy court at the proof of claims stage.

Derivative Instruments — Most of the Company’s derivative instruments are designated and qualify as hedges. Net unrealized losses of $43 million and $25 million were recorded in accumulated other comprehensive income during 2008 and 2007, respectively. Less than $1 million loss for 2008 and no gain or loss for both 2007 and 2006 were reclassified from accumulated other comprehensive income into interest expenses. As of December 31, 2008, deferred net losses of $1 million on interest rate swaps recorded in accumulated other comprehensive income are expected to be reclassified into interest expenses during the next twelve months.

Interest Rate Swaps — The Parent and operating companies entered into various interest rates swap agreements to limit their interest rate risk exposures to variable-rate debt. As of December 31, 2008, 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 15). 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. The weighted average interest rate on the swaps is currently 4.9%. 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. During January 2009, the Company, through a series of interest rate swaps, hedged the remaining unhedged portions of its term loan through its maturity in March 2014. The total notional amount of the hedges range from $325 million to $765 million through maturity. The weighted average interest rate on the swaps is currently 2.5%.

PQP entered into an interest rate swap agreement in November 2007, designated as cash flow hedge, to hedge 50% of the outstanding balance of its LIBOR-based U.S. dollar denominated loan facility to fix its interest rate at 5.03%. As of December 31, 2008 and 2007, the notional amount of this interest rate swap, which matches with 50% the outstanding loan balance, was $41 million and $45 million, respectively.

In April 2008, ENS, as a result of debt refinancing (see Note 15), terminated its original interest rate swap agreement which was used to hedge the entire balance of its floating interest rate exposure on a commercial bank syndicated loan and entered into new interest rate swap agreements to hedge 85% of its Polish zloty denominated senior loan to fix its interest rate at 5.8% (the remaining 15% will be hedged upon expiration of the 15-month grace period).

Net Investment Hedges — The Company uses hedge transactions, designated as fair value hedges, to protect its net investment in Elektro and Promigas against adverse changes in the exchange rate between the U.S. dollar and the Brazilian real and between the U.S. dollar and the Columbia Peso . Since the derivative’s underlying exchange rate is expected to move in tandem with the exchange rate between the functional currency (Brazilian real and Columbia Peso) of the hedged investment and AEI’s functional currency (U.S. dollar), no material ineffectiveness is anticipated.

The Company recorded $3 million of gain and $1 million of loss as currency translation adjustments related to these hedges in 2008 and 2007, respectively.

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 and Colombia Peso -based dividends received from Promigas on a recurring basis. The Company recognized $7 million, $(14) million and less than $1 million foreign currency transaction gain (loss), net, in 2008, 2007 and 2006, respectively, related to these derivatives.

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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 following table summarizes the estimated fair values of the Company’s long-term investments, debt, and derivative financial instruments:


	December 31,
	2008				2007
	Carrying				Carrying
	Value		Fair Value		Value		Fair Value
	Millions of dollars (U.S.)

Assets:
Notes receivable from unconsolidated subsidiaries	$	120	$	123	$	122	$	120
Investment in debt securities, including available-for-sale securities		192		192		306		306
Foreign currency forwards and swaps		1		1		2		2
Liabilities:
Interest rate swaps		64		64		25		25
Long-term debt, including current maturities		3,962		3,753		3,264		3,292

The Operating Companies that rely upon one or a limited number of customers are subjected to concentrations of credit risk with respect to accounts receivable. In several instances, the obligations of the sole customers are supported by guarantees and other forms of financial support by the respective foreign governments, or government-owned or controlled agencies or companies. As of December 31, 2008 and 2007, one customer accounted for 18% and 14% of accounts receivable, respectively.


20.	PER SHARE DATA

Basic and diluted earnings (loss) per share attributable to AEI were as follows:


	For the Years Ended December 31,
	2008		2007		2006

Basic earnings (loss) per share attributable to AEI:
Income (loss) from continuing operations attributable to AEI (millions of U.S. dollars)	$	158	$	87	$	(18	)
Average number of common shares outstanding (millions)		218		209		202
Income (loss) from continuing operations per share attributable to AEI	$	0.73	$	0.42	$	(0.09	)
Effect of dilutive securities:
Stock options (millions of options)		—		—		—
Restricted stock (millions of shares)		—		1		—
Dilutive earnings (loss) per share attributable to AEI	$	0.73	$	0.42	$	(0.09	)

The Company issues restricted stock grants to directors and employees which are included in the calculation of basic earnings per share. The Company incurred a net loss from continuing operations for the year ended December 31, 2006 and therefore excluded the 1,920,997 of non-vested restricted shares from the computation of the 2006 diluted income (loss) per share, as the effect would be anti-dilutive. At December 31, 2008 and 2007, 3,187,830 and 2,373,729 stock options and restricted shares issued to employees, respectively, were excluded from the calculation of diluted earnings per share because either the exercise price of those options exceeded the average fair value of the Company’s stock during the related period or the future compensation expense of those restricted shares exceed the implied cost of the company issuing those shares.

On April 1, 2008, the Company entered into a subscription agreement with Buckland Investment Pte Ltd., or Buckland, an investment holding vehicle managed by GIC Special Investments Pte Ltd (“GIC”). GIC is the private equity investment arm of Government of Singapore Investment Corporation (Ventures) Pte Ltd., a global investment management company established in 1981 to manage Singapore’s foreign reserves. On May 9, 2008, the Company sold GIC 12.5 million of its ordinary shares at a subscription price of $16 per share. The gross proceeds that the Company received from this issuance were $200 million. The Company used a portion of these proceeds to

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repay a portion of its revolving credit facility and to make dividend payments to noncontrolling interest holders of the operating companies. Upon closing, a nominee of Buckland was appointed to the Company’s board of directors.


21.	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Accumulated other comprehensive income (loss) attributable to AEI consists of the following:


	December 31,
	2008			2007
	Millions of dollars (U.S.)

Cumulative foreign currency translation	$	(131	)	$	212
Unrealized derivative losses		(68	)		(25	)
Unamortized actuarial and investment gains		54			22
Unrealized gain (loss) on available-for-sale securities		(59	)		6

Total	$	(204	)	$	215


22.	RELATED-PARTY TRANSACTIONS

Ashmore provides certain management services to the Company through a Management Service Agreement (“MSA”) effective May 20, 2006. The initial term of the MSA was for one year and renews for successive one-year periods from May to May each year unless terminated by either party. Charges include (1) actual costs of employees performing the services (including salary, bonus, benefits, and long-term incentive grants) and (2) reimbursement of reasonable and documented expenses. The maximum annual amount of fees that may be billed under the MSA during each one-year term is approximately $5 million (excluding expenses). The Company recorded expenses of $4 million, $5 million and $2 million during 2008, 2007 and 2006, respectively, for these services. 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 $52 million, $63 million and $20 million during 2008, 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 each of 2008, 2007 and 2006.

One of the Company’s subsidiaries, PQP, had a long-term receivable with one of its noncontrolling 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.


23.	COMPENSATION PLANS

Annual Incentive Plans — The Company has a discretionary annual incentive plan for the U.S. and certain foreign-based employees that is designed to recognize, motivate, and reward exceptional contribution toward the accomplishment of Company objectives. The plan is based on target bonus opportunities expressed as a percentage of annual base salary with threshold, target, and maximum award levels. Funding is calculated based on goal achievement and job-level weighting tied to financial, operational and individual performance. Many of the Operating Companies also provide annual incentive plans based on the performance of their individual businesses.

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

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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.

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 2008 and 2007, which resulted in compensation expense during 2008 and 2007 for these awards that was negligible.

The fair value of each grant has been estimated using the Black-Scholes-Merton model. Weighted average fair values and valuation assumptions used to value stock options issued under the 2007 Equity Incentive Plan are disclosed for the periods indicated as follows:


	2008			2007

Weighted Average Fair Value of Grants	$	5.39		$	4.61
Expected Volatility		25.37	%		25.00	%
Risk-Free Interest Rate		3.20	%		4.00	%
Dividend Yield		0.00	%		0.00	%
Expected Life		6.58 Years			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 vests to the employee on a graduated vesting schedule ranging from one to four years as defined in the individual grant agreements. Upon vesting, restricted stock is converted into common stock and released to the employee. Stock-based compensation expense related to restricted stock was $2 million and $1 million for 2008 and 2007, respectively.

Summarized restricted stock award activity under the 2007 Equity Incentive Plan for the periods indicated:


				Weighted- Average		Aggregate Intrinsic
Restricted Stock	Shares			Grant Price		Value
	(Thousands)					(Millions of dollars (U.S.))

Granted during 2007		500		$	12.63	$	6

Vested during 2007		—			—		—

Nonvested, January 1, 2008		494		$	12.65	$	6
Granted		238			16.03		4
Forfeited		(47	)		13.78		(1	)
Exercised		(5	)		11.54		—
Vested		(44	)		12.75		—

Nonvested, December 31, 2008		636		$	13.83	$	9

As of December 31, 2008, there was $7 million of total unrecognized compensation cost related to nonvested restricted stock under the 2007 Equity Incentive Plan. This cost is expected to be recognized over a weighted-average period of 2.71 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 $3 million and $1 million for 2008 and 2007, respectively.

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Summarized option award activity under the 2007 Equity Incentive Plan for the periods indicated is as follows:


				Weighted-Average		Weighted-Average		Aggregate
				Fair Value of		Exercise Price of		Intrinsic
Stock Options	Options			Grants		Grants		Value
	(Thousands)							(Millions of
								dollars (U.S.))

Exercised during 2007		(31	)	$	4.11	$	11.18	$	—

Vested during 2007		—			—		—		—

Outstanding, January 1, 2008		1,657		$	4.62	$	12.52	$	8
Granted		1,313			5.39		16.03		7
Forfeited		(241	)		4.87		13.86		(1	)
Exercised		—			—		—		—

Outstanding, December 31, 2008		2,729		$	4.97	$	14.09	$	14

Exercisable as of December 31, 2008		161		$	4.61	$	12.50	$	1

As of December 31, 2008, there was $10 million of total unrecognized compensation cost related to nonvested stock options under the 2007 Equity Incentive Plan. This cost is expected to be recognized over a weighted-average period of 2.77 years.

As a Cayman Islands entity, AEI does not realize any tax benefits from the granting or exercising of restricted stock and stock options.

2004 Stock Incentive Plans — In 2004, PEI adopted a long-term incentive compensation plan (“Stock Incentive Plan”) that provided awards to certain directors, officers, and key employees of PEI and its subsidiaries. Awards issued to non-employee directors are fully vested at the grant date in accordance with the grant agreement. 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.

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. All restricted shares outstanding at December 31, 2007, relating to the Stock Incentive Plan, were vested as of such date.

Summarized time-based share unit award and performance-based share unit award activity, including the effects of the amalgamation of PEI and AEI in December 2006, is as follows:


			Weighted-		Aggregate
			Average		Intrinsic
	Units/Shares		Grant Price		Value
	(Thousands)				(Millions of
					dollars (U.S.))

Total Time-Based restricted shares vested during 2007		586	$	7.99	$	5
Total Performance-Based restricted shares vested during 2007		2,179	$	7.99	$	17

As a Cayman Islands entity, AEI 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”). Cash Awards vested 50% upon the effectiveness of a change of control (September 6, 2006) and 50% on September 6, 2007. All vested Cash Awards have been settled and paid. Compensation expense recognized for the Sales Incentive Plan was $3 million, $17 million and $21 million for 2008, 2007 and 2006, respectively.

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Fifty percent of the Cash Awards, 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. The Company recorded this remaining 50% ratably over the 12-month period following the change in control.

Summarized activity of restricted stock of the amalgamated company issued in lieu of the second Sales Incentive Plan payment, as was provided as an option for Sales Incentive Plan participants, is shown below for the periods indicated. 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.


				Average		Aggregate
				Weighted-		Intrinsic
Restricted Stock Issued in Lieu of Second Sales Incentive Plan Payment	Shares			Grant Price		Value
	(Thousands)					(Millions of
						dollars (U.S.))

Vested during 2007		(312	)	$	7.99	$	(2	)

Nonvested, January 1, 2008		320		$	7.99	$	3
Exercised		(103	)		7.99		(1	)
Forfeited		(16	)		7.99		—
Vested		(201	)		7.99		(2	)

Nonvested, December 31, 2008		—		$	—	$	—


24.	PENSION AND OTHER POSTRETIREMENT BENEFITS

The Company maintains a defined contribution plan for substantial portions of its employees. All of its U.S.-based and expatriate employees are covered by a defined contribution plan. The Company matches 100% for the first 3% of eligible compensation contributed by the employee and 50% for the next 2% contributed. The Company also has defined contribution plans for 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 2008, 2007 and 2006, respectively. The Company’s U.S.-based and expatriate employees participate in AEI employee benefit programs, including health insurance and savings plans. The expense for these benefits was $1 million, $1 million and $2 million in 2008, 2007 and 2006, respectively.

In certain countries, including Panama, El Salvador and Colombia, 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 Accrued severance indemnities included in other liabilities was $4 million as of both December 31, 2008 and 2007. In Argentina, EDEN is required to pay certain benefits to employees upon retirement. EDEN is not required to deposit funds into a trust, but has accrued benefit obligations in its records of $7 million and $4 million as of December 31, 2008 and 2007, respectively, and recorded a decrease in other comprehensive income of $1 million and less than $1 million, respectively. The Company accrues these benefits based on historical experience and third party evaluations.

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.

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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,
	2008		2007
	Millions of dollars (U.S.)

Projected benefit obligation	$	224	$	307
Accumulated benefit obligation		213		285
Fair value of plan assets		292		325
Prepaid pension asset		68		18

The Company uses a year-end measurement date for its plans. Elektro recorded other comprehensive income of $33 million and $16 million, net of tax of $17 million and $8 million, as of December 31, 2008 and 2007, respectively.

The changes in projected benefit obligation, changes in the fair value of plan assets, and the funded status of the plans are as follows:


	December 31,
	2008			2007
	Millions in dollars (U.S.)

Change in projected benefit obligation :
Benefit obligation, beginning of period	$	307		$	229
Service cost		4			3
Interest cost		32			31
Actuarial gains and losses		32			9
Benefits paid		(15	)		(12	)
Effect of foreign exchange rate change		(69	)		47
Change in assumptions		(67	)		—

Benefit obligation — end of period	$	224		$	307

Change in plan assets :
Fair value of plan assets, beginning of period	$	325		$	222
Actual return on plan assets		72			65
Contributions by employer		1			2
Contributions by plan participants		1			2
Benefits paid		(15	)		(12	)
Effect of foreign exchange rate change		(92	)		46

Fair value of plan assets — end of period	$	292		$	325

Funded status at end of year	$	68		$	18

Amounts recognized on the balance sheet — prepaid pension asset	$	68		$	18

Net amount recognized at end of year	$	68		$	18

The components of net periodic (benefit) cost are as follows:


	For the Years Ended December 31,
	2008			2007			2006
	Millions of dollars (U.S.)

Service cost	$	4		$	3		$	1
Interest cost		32			31			6
Expected employee contribution		(2	)		(2	)		—
Expected return on plan assets for the period		(38	)		(33	)		(7	)

Total net periodic pension (benefit) cost	$	(4	)	$	(1	)		—

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Projected benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The actuarial assumptions as of December 31, 2008, 2007 and 2006, are as follows:


	2008						2007
				Periodic			Periodic			Periodic			2006
	Benefit			Pension			Benefit			Pension			Benefit			Pension
	Obligation			Cost			Obligation			Cost			Obligation			Cost

Weighted-average of discount rates		12.37	%		12.37	%		10.24	%		10.24	%		11.30	%		11.30	%
Weighted-average rates of compensation increase		7.63	%		7.63	%		7.12	%		7.12	%		8.15	%		8.15	%
Weighted-average expected long-term rate of return on plan assets					13.29	%					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,
	2008			2007

Fixed income		75.7	%		70.7	%
Equities		17.3	%		21.7	%
Real estate		3.6	%		4.0	%
Loans to participants		3.4	%		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 2009	$	1
Expected benefit payments:
2009		12
2010		13
2011		14
2012		16
2013		18
2014 — 2018		126


25.	COMMITMENTS AND CONTINGENCIES

The Company’s future minimum commitments as of December 31, 2008, are as follows:


	2009		2010		2011		2012		2013		Thereafter		Total
					Millions of dollars (U.S.)

Power commitments⁽¹⁾	$	790	$	865	$	876	$	879	$	755	$	7,736	$	11,901
Fuel commitments⁽²⁾		474		462		427		388		446		2,503		4,700
Equipment commitments⁽³⁾		22		10		4		3		34		83		156
Transportation commitments⁽⁴⁾		55		56		59		50		35		244		499
FIN 48 obligations, including interest and penalties		11		5		—		—		—		101		117
Other commitments		7		2		1		1		—		—		11

Total	$	1,359	$	1,400	$	1,367	$	1,321	$	41,270	$	10,667	$	17,384


(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, 2008, 2007 and 2006 totaled $716 million, $917 million and $232 million, respectively.

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(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, 2008, 2007 and 2006 totaled $541 million, $425 million and $107 million, respectively.
(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.

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 December 31, 2008, AEI and its subsidiaries had entered into letters of credit, bank guarantees, and performance bonds with balances of $323 million issued and $15 million in unused letter of credit availability, of which $39 million of the total facility balances were fully cash collateralized. Additionally, as of December 31, 2008, lines of credit of $1,275 million were outstanding, with an additional $319 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, which is also included in amounts above. Accroven is required to reimburse AEI for any payment made in connection with the letters of credit, subject to the consent of Accroven’s lender and approval by the Accroven shareholders.

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, 2008. The net assets of unconsolidated subsidiaries affected by such restrictions amount to approximately $261 million as of December 31, 2008.

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 MENR to renegotiate their current contracts. The primary aim of MENR 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 MENR in April 2006. MENR 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 proposed restructuring will have a material adverse effect on its financial condition, results of operations, or liquidity.

Poland — The Polish government has been working on restructuring the Polish electric energy market since the beginning of 2000 in an effort to introduce a competitive market in compliance with European Union legislation. In 2007, legislation was passed in Poland that allowed for power generators producing under long term contracts to voluntarily terminate their contracts 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 payments, beginning in August 2008, received in 2008 were $18 million. The maximum remaining compensation attributable to ENS is 1.12 billion Polish zloty (approximately US $385 million).

Bolivia/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

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Elétrica, the regulator of the Brazilian electricity sector) are on hold (but resume sporadically). 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:

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. CIESA subsequently amended its complaint to also include an allegation that AEI’s termination of its restructuring agreement with CIESA was in breach of this agreement. AEI does not believe that there is any merit to the suit and is vigorously defending the claim. Separately, 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.

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 December 31, 2008, the Company has accrued liabilities totaling approximately $153 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 in a manner that the Company could be required to pay damages or to make expenditures in amounts materially in excess of that recorded, but cannot be estimated at December 31, 2008.

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, the Company has accrued approximately $13 million 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 concessionaries. 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.

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(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.

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 $25 million (based on the exchange rate as of December 31, 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 $40 million 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.

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 purchase agreement and initiated an arbitration proceeding in accordance with the power purchase agreement. EPE amended its initial pleadings and requested, as an alternative to its original claim, that the arbitrators declare the PPA terminated due to Furnas’ default caused by its failure to make capacity payments. The tribunal accepted the amendment of EPE’s pleadings in the first quarter of 2009. We expect a decision in this arbitration in mid 2009. 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. San Felipe appealed the ruling to the Dominican Republic Supreme Court and the Supreme Court issued its final ruling upholding the appeal court ruling. The Company had accrued $11 million for this claim. In April 2009, San Felipe reached a settlement with the plaintiff for an amount not materially in excess of this accrual and the settlement was paid in May 2009.

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 $20 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. The Company has accrued approximately $66 million as of December 31, 2008 with respect to the period from January 1998 through December 31, 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.

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vibrations. Siemens identified the root cause of the problem to be a defect in the gas turbine that was not disclosed to us at the time we acquired our interest in DCL. Due to the shutdown, DCL has not generated revenues and cash inflows to pay vendors which has delayed the repairs. DCL is seeking a loan to pay Siemens that, if obtained, may allow the plant to resume commercial operations within three to four months of obtaining such loan.

On January 24, 2009, DCL received notice of default from one of its senior lenders. Shortly thereafter, two of DCL’s senior lenders filed claims against DCL and Sacoden, which holds AEI’s interest in DCL, in the courts of Sindh Province, Pakistan seeking repayment by DCL of $46 million. The allegations included that DCL had issued shares to AEI following the initial acquisition of DCL in violation of the loan covenants. 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 filed 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 and a non-binding memorandum of understanding setting out a proposed restructuring plan, was executed but documentation relating to this loan has not yet been finalized.

If DCL is unable to satisfactorily resolve the dispute with its lenders or secure a new offtaker for the power from DCL’s plant, the operations of DCL will be materially adversely effected or the lenders may exercise their right to take ownership of the plant, in either event with a corresponding negative impact on the Company’s financial performance and cash flows.


26.	SEGMENT AND GEOGRAPHIC INFORMATION

The Company manages, operates and owns interests in energy infrastructure businesses through a diversified portfolio of companies worldwide. It conducts operations through global businesses, which are aggregated into reportable segments based primarily on the nature of its service and customers, the operation and production processes, cost structure, channels of distribution and regulatory environment. The operating segments reported below are the segments of the Company for which separate financial data is available and for which operating results are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The Company uses both revenue and operating income as key measures to evaluate the performance of its segments. Segment revenue includes inter-segment sales. Operating income is defined as total revenue less cost of sales 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.

Generation — This segment generates and sells wholesale power primarily to large off-takers, such as distribution companies. Each of the businesses in this segment sells substantially all of its generating capacity under long-term contracts primarily to state-owned entities. These businesses use different types of fuel (hydro, natural gas, and liquid fuel) and different technologies (turbines and internal combustion engines) to convert the fuel to electricity. Generally, off-take agreements are structured to minimize business exposure to commodity fuel price volatility.

Natural Gas Transportation and Services — This segment provides transportation and related services for upstream oil and gas producers and downstream utilities and other large users who contract for capacity. Each of these businesses owns and operates pipeline, compression and/or liquids removal and processing equipment associated with the transportation or handling of large quantities of gas. The rates charged by these businesses are typically regulated or controlled by a government entity.

Natural Gas Distribution — This segment is involved in the distribution and sale of natural gas to retail customers. Each of these businesses operates a network of gas pipelines, delivers gas directly to a large number of

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residential, industrial and commercial customers, and directly bills these customers for connections and volumes of gas provided. These businesses are regulated and typically operate on long-term concessions giving them an exclusive right to deliver gas in a designated service area.

Retail Fuel — This segment distributes and sells gasoline, LPG and compressed natural gas (“CNG”). These businesses service both owned and affiliated retail outlets.

Headquarters and Other — Expenses include corporate interest, general and administrative expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources, information systems and incentive compensation, and certain businesses which are immaterial for the purposes of separate segment disclosure.

Eliminations — The eliminating transactions between segments include certain generation facilities, on one side, and distributors and gas services on the other, and intercompany interest and management fee arrangements between the operating segments and the Parent Company.

The tables below present summarized financial data about AEI’s reportable segments. For 2006, there are no Natural Gas Distribution segment revenues as this segment relates primarily to Promigas, which was acquired effective December 31, 2006.


As of and for the Year Ended					Nat. Gas.		Nat. Gas.				Headquarters
December 31, 2008	Power Dist.		Power Gen.		Trans.		Dist.		Retail Fuel		and Other			Eliminations			Total
							Millions of dollars (U.S.)

Revenues	$	2,217	$	1,175	$	202	$	584	$	5,137	$	22		$	(126	)	$	9,211
Equity income from unconsolidated affiliates		68		12		27		11		1		—			(2	)		117
Operating income		427		15		128		104		218		(36	)		(43	)		813
Interest income		54		14		6		2		9		3			—			88
Interest expense		134		45		44		19		53		136			(53	)		378
Depreciation and amortization		138		24		21		18		61		6			—			268
Capital expenditures		183		16		12		61		86		14			—			372
Equity method investments in unconsolidated affiliates		628		65		35		23		8		—			—			759
Goodwill		53		54		26		144		323		14			—			614
Total assets as of December 31, 2008		3,304		1,897		924		1,110		1,323		3,865			(3,470	)		8,953


As of and for the Year Ended					Nat. Gas.		Nat. Gas.				Headquarters
December 31, 2007	Power Dist.		Power Gen.		Trans.		Dist.		Retail Fuel		and Other		Eliminations			Total
							Millions of dollars (U.S.)

Revenues	$	1,746	$	874	$	199	$	352	$	160	$	19	$	(134	)	$	3,216
Equity income from unconsolidated affiliates		2		11		39		13		11		—		—			76
Operating income		373		77		128		85		49		286		(421	)		577
Interest income		58		27		7		2		2		14		—			110
Interest expense		90		41		42		14		12		143		(36	)		306
Depreciation and amortization		139		42		20		8		3		5		—			217
Capital expenditures		168		3		9		24		37		8		—			249
Equity method investments in unconsolidated affiliates		698		14		106		26		38		—		—			882
Goodwill		53		33		27		117		158		14		—			402
Total assets as of December 31, 2007		3,732		1,433		1,138		913		384		4,170		(3,917	)		7,853


For the Year Ended					Nat. Gas.		Nat. Gas.				Headquarters
December 31, 2006	Power Dist.		Power Gen.		Trans.		Dist.		Retail Fuel		and Other			Eliminations			Total
							Millions of dollars (U.S.)

Revenues	$	685	$	278	$	24	$	—	$	—	$	1		$	(42	)	$	946
Equity income from unconsolidated affiliates		26		21		10		—		4		(24	)		—			37
Operating income		151		60		21		—		3		(7	)		(77	)		151
Interest income		20		11		—		—		—		40			—			71
Interest expense		27		18		5		—		2		97			(11			138
Depreciation and amortization		47		9		2		—		1		—			—			59
Capital expenditures		71		1		—		—		4		—			—			76

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The tables below present revenues and operating income of the Company’s consolidated subsidiaries by significant geographical location for the year ended December 31, 2008, 2007 and 2006 and property, plant and equipment, net as of December 31, 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.


	Revenues
	For the Years							Operating Income For the Years
	Ended December 31,							Ended December 31,
	2008		2007		2006			2008			2007			2006
					Millions of dollars (U.S.)

Colombia	$	3,926	$	563	$	—		$	371		$	198		$	3
Brazil		1,503		1,406		390			185			220			120
Chile		1,311		—		—			68			—			—
Panama		808		389		371			44			57			37
Turkey		416		337		116			24			46			38
Guatemala		206		168		48			23			42			12
Dominican Republic		211		139		145			11			19			22
Ecuador		126		—		—			2			—			—
Argentina		122		52		—			14			8			—
China		104		8		—			(19	)		(6	)		—
Other		478		154		(124	)		90			(7	)		(81	)

Total	$	9,211	$	3,216	$	946		$	813		$	577		$	151


	Property, Plant & Equipment, Net
	December 31,
	2008		2007
	Millions of dollars (U.S.)

Colombia	$	714	$	614
Brazil		1,281		1,482
Chile		88		—
Panama		272		242
Turkey		132		143
Guatemala		48		37
Dominican Republic		24		23
Ecuador		14		—
Argentina		88		89
China		256		36
Other		607		369

Total	$	3,524	$	3,035


27.	SUBSEQUENT EVENTS

Nicaragua Energy Holdings — On January 1, 2009, AEI contributed its 50% interest in its subsidiary Corinto and its 100% interest in its subsidiary Tipitapa to Nicaraguan Energy Holdings (“NEH”). Centrans Energy Services Inc. (“Centrans”) also contributed its 50% interest in Corinto and 49% of its 45% interest in Consorcio Eolico Amayo, S.A. (“Amayo”) to NEH. Amayo is a 39.9 MW wind generation greenfield project development located in Rivas province, Nicaragua. As a result, AEI owns 57.7% and Centrans owns 42.3% of NEH. AEI will consolidate NEH as a result of this transaction.

Subic — On February 22, 2009, the 15 year build-to-operate-transfer agreement (“BOT”) between Subic and the National Power Corporation of the Philippines (“NPC”) expired on schedule. The Company owns a 50% interest in Subic. On February 23, 2009, the plant was turned over to the NPC without additional compensation. The Company’s remaining investment balance in Subic will be recognized from expected dividends and shareholder loan repayments in 2009.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

AEI

c/o AEI Services LLC

Houston, TX

We have audited the accompanying consolidated statement of income of Prisma Energy International, Inc. and subsidiaries (“the Company”), a predecessor entity of AEI, and the related consolidated statements of shareholders’ 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 audit.

We conducted our audit 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 for its internal control over financial reporting. An audit includes 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 audit provides 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, and as discussed in Note 2 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for the application of SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the 249 day period ended September 6, 2006, in conformity with accounting principles generally accepted in the United States of America.

Houston, Texas

October 19, 2007

(August 17, 2009 as to the effects of the application of SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, and the related disclosures in Note 2)

F-82

PRISMA ENERGY INTERNATIONAL INC. AND SUBSIDIARIES
(PREDECESSOR)

CONSOLIDATED STATEMENT OF CASH FLOWS


	249 Day
	Period Ended
	September 6, 2006
	(In millions)

Cash flows from operating activities:
Net income	$	185
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
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 noncontrolling 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-85

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).

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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.


2.	BASIS OF PRESENTATION

These financial statements have been recast to reflect the impact of Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51 (“SFAS No. 160”) which was issued in December 2007. The application of this standard reclassifies minority interest expense of $21 million for the 249 day period ended September 6, 2006 as net income attributable to noncontrolling interests below net income in the presentation of net income attributable to PEI. It also separately reflects changes in noncontrolling interests in changes in equity and comprehensive income.

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”).

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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 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

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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.

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 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.

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Basic and diluted earnings per share were as follows:


	249 Day
	Period Ended
	September 6, 2006

Basic earnings per share computation
Numerator
Net income attributable to PEI (in millions)	$	164
Denominator
Average number of common shares outstanding (in millions)		1

Net income attributable to PEI per share	$	159.39

Diluted earnings per share computation
Numerator
Net income attributable to PEI (in millions)	$	164
Denominator
Average number of common shares outstanding (in millions)		2

Net income attributable to PEI 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 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

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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
	September 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.

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

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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 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.

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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
	September 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 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
	September 6, 2006
	(U.S. dollars in millions)

Statement of Income
Revenues	$	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

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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.

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

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secured by PQP’s power plant barges and moveable assets and the shares of PQP. The loan facilities 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

The long-term receivables from Furnas accrue interest based on the Selic rate. Additionally, under the terms of the power purchase 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 be adjusted. Income recognized for monetary index adjustments included in interest income was $13 million for the 249 day period ended September 6, 2006.

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10.	OTHER INCOME (EXPENSE) — NET


	249 Day
	Period Ended
	September 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
	September 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 taxes was $394 million for the 249 day period ended September 6, 2006.

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
	September 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.

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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.


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

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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 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

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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.

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

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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 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:


			Aggregate
		Weighted-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 September 6, 2006	300,286	$ 28.90	$ 9
Exercisable at September 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
Performance-Based Restated Units	Units	Grant Price

Nonvested, Dec. 31, 2005	503,752	$	25.62
Granted	601,733		31.28
Exercised	—		—
Forfeited	—		—
Vested at September 6, 2006	—	$	—
Nonvested at September 6, 2006	1,105,485	$	28.70

A summary of additional information about share units that are outstanding and exercisable at September 6, 2006, is as follows:


					Weighted-Average
			Weighted-Average		Remaining
Share Units Outstanding	Units		Grant Price		Contractual Life
					(In Years)

Performance based		1,105,485	$	28.70		.47
Time based		300,286		28.90		.93

Total values at September 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.

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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.

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

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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 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.

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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.

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.

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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 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

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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 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

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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.

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.

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 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.


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

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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.

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.

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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
	September 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:


	Power			Power			Nat. Gas.			Nat. Gas.		Retail			Headquarters
249 Days Ended September 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.


	Revenues
	249 Days Ended
	September 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.

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directors and certain officers, including the Chief Executive Officer. During that period, PEI remained controlled by Enron and its affiliates.

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.

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

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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).

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%.

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ANNEX I
Proportional Financial Metrics⁽¹⁾Unaudited


															Add		Proportional
			AEI			AEI			Deduct			Deduct			Proportional		Share of						Proportional
			Ownership			Consolidated			Noncontrolling			Equity			EBITDA -		Adjusted			Net Debt			Share of
			% at			Adjusted			Interest			(Income)			Equity/Cost		EBITDA			as of			Net Debt
Business	Operating Segment		12/31/08			EBITDA⁽²⁾			Share⁽³⁾			Loss⁽⁴⁾			Investments⁽⁴⁾		2008			12-31-2008⁽⁵⁾			12-31-2008⁽⁵⁾
	(In millions of $, except for ownership percentages)


As of and for the year ended December 31, 2008

Delsur		Power Distribution		86.41	%	$	23		$	(3	)	$	—		$	—	$	20		$	67		$	58

EDEN		Power Distribution		90.00	%		18			(2	)		—			—		16			24			22

Elektra		Power Distribution		51.00	%		49			(24	)		—			—		25			119			60

Elektro		Power Distribution		99.68	%		427			(2	)		—			—		425			241			240

Chilquinta		Power Distribution		50.00	%		36			—			(36	)		57		57			160			80

Luz del Sur		Power Distribution		37.97	%		31			—			(31	)		67		67			211			80

Cuiabá — EPE		Power Generation		50.00	%		(46	)		23			—			—		(23	)		24			12

ENS		Power Generation		100.00	%		32			—			—			—		32			56			56

PQP		Power Generation		100.00	%		29			—			—			—		29			70			70

Subic		Power Generation		50.00	%		12			—			(12	)		14		14			(10	)		(5	)

Trakya		Power Generation		59.00	%		40			(16	)		—			—		24			(59	)		(35	)

Accroven		Natural Gas Transportation and Services		49.25	%		17			—			(17	)		40		40			138			68

GTB		Natural Gas Transportation and Services		17.65	%		1			—			(1	)		13		13			323			57

TBG		Natural Gas Transportation and Services		4.21	%		—			—			—			10		10			777			33

Cuiabá — GOB		Natural Gas Transportation and Services		50.00	%		16			(8	)		—			—		8			28			14

Cuiabá — GOM		Natural Gas Transportation and Services		50.00	%		20			(10	)		—			—		10			7			4

Promigas Pipeline		Natural Gas Transportation and Services		52.13	%		65			(31	)		—			—		34			177			93

Promigas — Gases de Occidente		Natural Gas Distribution		46.87	%		48			(26	)		—			—		22			61			29

Promigas — Gases del Caribe		Natural Gas Distribution		16.16	%		10			—			(10	)		13		13			117			19

Cálidda		Natural Gas Distribution		80.85	%		19			(4	)		—			—		15			47			38

Promigas — Surtigas		Natural Gas Distribution		52.08	%		38			(18	)		—			—		20			66			35

Promigas — SIE		Retail Fuel		28.13	%		162			(116	)		—			—		46			440			124

Promigas — GNC		Retail Fuel		24.96	%		48			(36	)		—			—		12			68			17

Other		Various Segments					39			(14	)		(9	)		7		23			298			115


SUBTOTAL (Excluding Headquarters and Other)						$	1,134		$	(287	)	$	(116	)	$	221	$	952					$	1,284

Headquarters and Other		Headquarters		100.00	%		(90	)		—			—			—		(90	)		1,474			1,474


TOTAL						$	1,044		$	(287	)	$	(116	)	$	221	$	862					$	2,758


For the year ended December 31, 2007

TOTAL						$	823		$	(131	)	$	(77	)	$	247	$	862


For the six months ended June 30, 2009

TOTAL						$	552		$	(148	)	$	(50	)	$	106	$	460


(1)		The following table sets forth unaudited proportional metrics by business for AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

(2)		See “Non-GAAP Financial Measures” for definition of Adjusted EBITDA. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA.

(3)		Represents the noncontrolling interests share of consolidated Adjusted EBITDA calculated as 100% less the AEI ownership percentage as of December 31, 2008 multiplied by the 2008 Adjusted EBITDA for the business. See Annex II for detailed reconciliation of the business’ net income to Adjusted EBITDA.

(4)		Represents the subtraction of equity income (loss) included in the consolidated Adjusted EBITDA for the business and the addition of the AEI’s share of the business’ Adjusted EBITDA. See Annex II for detailed reconciliation of the business’ net income to Adjusted EBITDA.

(5)		See “Non-GAAP Financial Measures” for definition of net debt. See “Selected Consolidated Financial Data” for a reconciliation of AEI debt to net debt. The net debt column represents 100% of net debt for the particular business. This column is multiplied by AEI’s ownership to calculate the proportional column.

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ANNEX II
Unaudited Reconciliation of Non-GAAP Measures⁽¹⁾As of and for the year ended December 31, 2008


																			CUIABA
	DELSUR			EDEN			ELEKTRA			ELEKTRO			CHILQUINTA			LUZ DEL SUR			EPE			ENS			PQP			SUBIC			TRAKYA			ACCROVEN			GTB			TBG
	(In millions of $, except for ownership percentages)


EBITDA CALCULATION:

Net Income (Loss) Attributable to AEI	$	1		$	6		$	10		$	166		$	53		$	63		$	(63	)	$	35		$	13		$	17		$	(12	)	$	27		$	19		$	235

Add back:

Depreciation and amortization		11			3			13			110			24			36			1			2			5			10			16			23			—			—

Noncontrolling interests		2			1			8			1			3			19			(47	)		—									2

Provision (benefit) for income taxes		3			1			9			90			(25	)		43			3			(12	)		5			2			25			16			29			125

Interest expense		7			4			9			72			22			17			5			6			7			—			3			16			31

Loss from disposal of discontinued operations		—			—			—			—			47			—			—			—			—			—			—			—			—			—


EBITDA		24			15			49			439			124			178			(101	)		31			30			29			34			82			79			360

Subtract:

Interest Income		—			(1	)		—			(45	)		(10	)		(1	)		(3	)		—			—			—			(2	)		(1	)		—			(111	)

Foreign currency transaction (gain) loss, net		—			3			—			2			1			1			17			1			—			—			7						(3	)

(Gain) loss on disposition of assets		—			—			—			18			—			—			—			—			—			—			—			—			—			—

Other charges		—			—			—			—			—			—			44			—			—			—			—			—			—			—

Other (income) expense, net		(1	)		1			—			13			(1	)		(2	)		(3	)		—			(1	)		(2	)		1			—			—			(2	)


ADJUSTED EBITDA	$	23		$	18		$	49		$	427		$	114		$	176		$	(46	)	$	32		$	29		$	27		$	40		$	81		$	76		$	247

AEI Ownership Percentage⁽²⁾		86.4	%		90.0	%		51.0	%		99.7	%		50.0	%		38.0	%		50.0	%		100.0	%		100.0	%		50.0	%		59.0	%		49.3	%		17.7	%		4.2	%

Proportional Share — Adjusted EBITDA	$	20		$	16		$	25		$	425		$	57		$	67		$	(23	)	$	32		$	29		$	14		$	24		$	40		$	13		$	10


NET DEBT CALCULATION:

Debt	$	73		$	37		$	144		$	370		$	220		$	218		$	42		$	67		$	87		$	1		$	1		$	167		$	344		$	918

Less: Cash		(3	)		(13	)		(25	)		(93	)		(4	)		(7	)		(13	)		(8	)		(13	)		(11	)		(60	)		(8	)		(21	)		(107	)

Restricted cash — current		—			—			—			(7	)		(56	)		—			—			(3	)		(4	)		—			—			(21	)		—			—

Restricted cash — non-current		(3	)		—			—			(29	)		—			—			(5	)		—			—			—			—			—			—			(34	)


NET DEBT⁽²⁾	$	67		$	24		$	119		$	241		$	160		$	211		$	24		$	56		$	70		$	(10	)	$	(59	)	$	138		$	323		$	777


Proportional Share — NET DEBT	$	58		$	22		$	61		$	240		$	80		$	80		$	12		$	56		$	70		$	(5	)	$	(35	)	$	68		$	57		$	33


(1)		The following table sets forth the reconciliation of net income to Adjusted EBITDA and debt to net debt, and calculation of the unaudited proportional metrics by business for certain of AEI’s consolidated and unconsolidated entities. Given that AEI consolidates for accounting purposes numerous businesses for which AEI does not own 100%, management uses these non-GAAP measures and proportional metrics, in addition to other GAAP metrics, for internal reporting and analysis purposes. The data herein is derived from information based in some instances on reconciliation of local GAAP to US GAAP and AEI’s books and records. There can be no assurance that the US GAAP reconciliation is accurate.

(2)		See “Non-GAAP Financial Measures” for definitions of Adjusted EBITDA and net debt. See “Selected Consolidated Financial Data” for a reconciliation of net income attributable to AEI to Adjusted EBITDA and debt to net debt.

A-2


	CUIABA			CUIABA			PROMIGAS			PROMIGAS			PROMIGAS						PROMIGAS			PROMIGAS			PROMIGAS
	GOB			GOM			PIPELINE			GDO			GDC			CALIDDA			SURTIGAS			SIE			GNC
	(In millions of $, except for ownership percentages)

EBITDA CALCULATION:
Net Income (Loss) Attributable to AEI	$	3		$	9		$	2		$	8		$	44		$	6		$	7		$	(1	)	$	18
Add back:
Depreciation and amortization		2			3			14			3			4			6			3			46			14
Noncontrolling interests		(1	)		8			5			14			—			1			11			32			62
Provision (benefit) for income taxes		8			(6	)		16			17			22			2			10			17			4
Interest expense		8			6			29			4			15			5			9			46			7
Loss from disposal of discontinued operations		—			—			—			—			—			—			—			—			—

EBITDA		20			20			66			46			85			20			40			140			105
Subtract:
Interest Income		—			(1	)		(2	)		1			(1	)		(2	)		(1	)		(7	)		(2	)
Foreign currency transaction (gain) loss, net		—			—			3			—			1			1			—			27			—
(Gain) loss on disposition of assets		—			—			—			—			—			—			—			—			(68	)
Other charges		—			—			—			—			—			—			—			—			—
Other (income) expense, net		(4	)		1			(2	)		1			(6	)		—			(1	)		2			13

ADJUSTED EBITDA	$	16		$	20		$	65		$	48		$	79		$	19		$	38		$	162		$	48
AEI Ownership Percentage⁽²⁾		50.0	%		50.0	%		52.1	%		48.9	%		16.2	%		80.9	%		52.1	%		28.1	%		25.0	%
Proportional Share — Adjusted EBITDA	$	8		$	10		$	34		$	22		$	13		$	15		$	20		$	46		$	12

NET DEBT CALCULATION:
Debt	$	31		$	23		$	212		$	64		$	130		$	86		$	71		$	505		$	78
Less: Cash		(3	)		(16	)		(34	)		(4	)		(13	)		(7	)		(5	)		(65	)		(10	)
Restricted cash — current		—			—			—			—			—			(32	)		—			—			—
Restricted cash — non-current		—			—			—			—			—			—			—			—			—

NET DEBT⁽²⁾	$	28		$	7		$	178		$	60		$	117		$	47		$	66		$	440		$	68

Proportional Share — NET DEBT	$	14		$	4		$	93		$	29		$	19		$	38		$	34		$	124		$	17

A-3

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


ITEM 6.	INDEMNIFICATION OF DIRECTORS AND OFFICERS

Cayman Islands law does not limit the extent to which a company may indemnify its directors, officers, employees and agents except to the extent that such provision may be held by the Cayman Islands courts to be contrary to public policy. For instance, a provision purporting to provide indemnification against civil fraud, the consequences of committing a crime may be deemed contrary to public policy. In addition, an officer or director may not be indemnified for his own willful neglect or willful default. Our Memorandum and Articles of Association make indemnification of directors and officers and advancement of expenses to defend claims against directors and officers mandatory on the part of the company to the fullest extent allowed by law. Under our Memorandum and Articles of Association, we will indemnify our directors, officers, our resident representative, any other person appointed to a committee of the board of directors and certain other persons (and their respective heirs, executors or administrators) to the full extent permitted by law against all actions, costs, charges, liabilities, loss, damage or expense incurred or suffered by such person by reason of any act done, concurred in or omitted in the conduct of our business or in the discharge of his/her duties; provided that such indemnification shall not extend to any matter involving any fraud or dishonesty on the part of such director, officer or other person. Under Cayman law, a corporation may indemnify a director or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if (1) the director or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and (2) with respect to any criminal action or proceeding, the director or officer had no reasonable cause to believe his or her conduct was unlawful. Under our Memorandum and Articles of Association, the company and each of our shareholders agree to waive any claim or right of action, other than those involving fraud or dishonesty, against us or any of our officers, directors or resident representative.

We have entered into indemnification agreements with our directors and executive officers, which shall be effective upon completion of this offering. With specified exceptions, consistent with our Memorandum and Articles of Association these agreements provide for indemnification for related expenses including, among other things, attorneys’ fees, judgments, fines and settlement amounts incurred by any of these individuals in any action or proceeding.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.


ITEM 7.	RECENT SALES OF UNREGISTERED SECURITIES

The following information relates to securities we have issued or sold within the past three years that were not registered under the Securities Act of 1933, as amended, or the Securities Act. Each of these transactions was completed without registration of the relevant security under the Securities Act in reliance upon exemptions provided under the Securities Act:

In October 2009, we issued 407,641 ordinary shares valued at $16.00 per share to D. E. Shaw Laminar Emerging Markets, L.L.C. (“DESLEM”) in exchange for a promissory note in the principal amount of approximately $6.5 million issued by one of our affiliates. The exchange was made in reliance on Section 4(2). DESLEM made customary private placement representations and appropriate notations regarding restrictions on transfer under applicable securities laws were made in our members register.

In September 2009, we issued 249,363 ordinary shares, valued at $16.00 per share, to GPU Argentina Holdings, Inc. (“GPU”) in exchange for a promissory note in the principal amount of approximately $4 million issued by one of our affiliates. The exchange was made in reliance on Section 4(2). GPU made customary private placement representations and appropriate notations regarding the restrictions on transfer under applicable securities laws were made in our members register.

In September 2009, we issued 653,890 ordinary shares, valued at $16.00 per share, to J.P. Morgan Overseas Capital Corporation (“JPMOCC”) in exchange for a promissory note in the principal amount of approximately $11 million issued by one of our affiliates. The exchange was made in reliance on Section 4(2). JPMOCC made

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customary private placement representations and appropriate notations regarding the restrictions on transfer under applicable securities laws were made in our members register.

In September 2009, we issued 1,976,099 ordinary shares to D. E. Shaw Laminar Portfolios, L.L.C. (“DESLP”), in exchange for 12,160,608 American Depositary Receipts representing 60,803,040 Class B Shares, par value AR$1 of TGS. In a contemporaneous transaction, AEI issued 731,166 ordinary shares to DESLP in exchange for approximately $16 million in aggregate principal amount of EDEN loans. The AEI shares issued in connection with both transactions were valued at $16.00 per share and were issued in reliance on Section 4(2). DESLP made customary private placement representations in the agreements relating to the transaction and the Company noted in its members register that such shares were subject to restrictions on transfer under applicable securities laws.

In September 2009, we issued an aggregate of 1,228,956 ordinary shares to Ponderosa Assets, L.P. valued at a price of $14.85 per share in exchange for certain assets valued at $26 million. The balance of the purchase price was paid in cash. The share issuance was made in reliance on Section 4(2). In the documents related to the transaction, Ponderosa represented that it was not acquiring the shares with a view to, or for resale in connection with, any distribution of any part thereof in violation of applicable laws. In addition, the Company reflected in the members register that such shares were subject to restrictions on transfer under applicable securities laws.

In August 2009, we issued an aggregate of 3,438,069 ordinary shares when various Ashmore Funds exercised their option to convert $57 million aggregate principal amount of our PIK notes and related interest receivable in reliance on Section 3(a)(9). No commissions were paid in connection with the conversion.

In May 2009, we issued an aggregate of 1,958,774 ordinary shares to certain funds advised by Black River Asset Management LLC valued at a price of $14.85 per share in exchange for approximately $10 million aggregate principal amount of EDEN loans and equity securities representing 19.91% of the outstanding shares of EMDERSA. The loans and equity securities were valued at $36 million in the aggregate. The balance of the purchase price was paid in cash. The issuance of the shares was made in reliance on Section 4(2). The Black River Funds made customary private placement representations in the agreements relating to the transaction and the Company noted in its members’ register that such shares were subject to restrictions on transfer under applicable securities laws.

In March 2009, we issued an aggregate of 7,412,142 ordinary shares when various Ashmore Funds exercised their option to convert $118 million aggregate principal amount of our PIK notes and related interest receivable in reliance on Section 3(a)(9). No commissions were paid in connection with the conversion.

In February 2009, we issued an aggregate of 261,749 restricted shares and options to acquire an aggregate of 1,690,365 of our ordinary shares to our employees and directors in reliance on Rule 701 under the Securities Act. The shares were valued at $13.10 per share and the exercise price of the options is $13.10 per share.

In September 2008, we issued an aggregate of 10,013 restricted shares and options to acquire an aggregate of 52,601 of our ordinary shares to our employees and directors in reliance on Rule 701 under the Securities Act. The shares were valued at $16.70 per share and the exercise price of the options is $16.70 per share.

In May 2008, we issued an aggregate of 227,825 restricted shares and options to acquire an aggregate of 153,848 of our ordinary shares to our employees and directors in reliance on Rule 701 under the Securities Act. The shares were valued at $16.00 per share and the exercise price of the options is $16.00 per share.

In May 2008, we issued an aggregate of 12,500,000 of our ordinary shares to Buckland Investment Pte Ltd for a cash purchase price of $16.00 per share in reliance on Section 4(2). In the transaction documents, Buckland Investment Pte Ltd represented that it was acquiring the shares for its own account without a view to a distribution thereof in violation of applicable securities laws. Appropriate transfer restriction notations for such shares were included in our register of members.

In October 2007, we issued an aggregate of 299,252 restricted shares and options to acquire an aggregate of 919,957 of our ordinary shares to our employees and directors in reliance on Rule 701 under the Securities Act. The shares were valued at $13.60 per share and the exercise price of the options is $13.60 per share.

In September 2007, we issued an aggregate of 1,093,630 of our ordinary shares in connection with the vesting of units under the 2004 Stock Incentive Plan in reliance on Rule 701 under the Securities Act.

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In May 2007, we issued an aggregate of $300 million of 10% PIK Notes, due 2018 to a limited number of institutional investors in reliance on Regulation D under the Securities Act. In the Note Purchase Agreement, each of the investors made customary representations for such a securities placement. In addition, the note certificates were printed with a legend reflecting appropriate restrictions on transfer under federal and state securities laws.

In June 2007, we issued 149,402 of our ordinary shares to a former officer (outside the United States) in connection with the vesting of units issued to such officer under our 2004 Stock Incentive Plan in reliance on Regulation S.

In February 2007, we issued an aggregate of 200,583 restricted shares and options to acquire an aggregate of 767,879 of our ordinary shares to our employees in reliance on Rule 701 under the Securities Act. The shares were valued at $11.18 per share and the exercise price of the options is $11.18 per share.

In January 2007, we issued 5,123,152 of our ordinary shares to Fintech Energy LLC, an accredited investor, in connection with our acquisition of certain debt securities valued at approximately $41 million in an Argentine distribution company in reliance on Section 4(2). In the transaction documents, Fintech Energy LLC represented that it was acquiring the shares for its own account without a view to a distribution thereof in violation of applicable securities laws. Appropriate transfer restriction notations for such shares were included in our register of members.

In January 2007, we issued 1,792,866 of our ordinary shares to Marathon Special Opportunities Fund Ltd. and Marathon Master Fund Ltd., each an accredited investor, in connection with our acquisition of debt securities having an agreed fair value of approximately $14 million in two Argentine utilities in reliance on Section 4(2). In the transaction documents, each of the Marathon funds represented that it was acquiring the shares for its own account without a view to a distribution thereof in violation of applicable securities laws. Appropriate transfer restriction notations for such shares were included in our register of members.

In December 2006, we issued an aggregate of 1,248,857 ordinary shares to our employees and directors in connection with the vesting of units under the 2004 Stock Incentive Plan in reliance on Rule 701 under the Securities Act.

In December 2006, we issued an aggregate of 639,605 restricted shares to certain employees and directors who purchased such shares with a portion of the cash payment received by them under the 2005 Sales Incentive Plan. These shares were issued in reliance on Regulation D and Regulation S under the Securities Act. Customary representations for such a placement were obtained from each purchaser and appropriate transfer restriction notations were made in our register of members.

In December 2006, we issued an aggregate of 200,000,021 ordinary shares to the shareholders of AEIL, all of which were accredited investors, in connection with the amalgamation of AEIL and PEI in reliance on Regulation S and Section 4(2). At the time of the amalgamation, PEI was a wholly-owned subsidiary of AEIL. The amalgamation was effected pursuant to a scheme of arrangement sanctioned by order of the Grand Court of the Cayman Islands. Pursuant to the scheme of arrangement, all shares of AEIL were exchanged for shares of PEI at a rate of 31.87158 PEI shares for each AEIL share. The exchange ratio was determined on the basis of the relative valuations of PEI and AEIL at the time.

In May 2006, we issued an aggregate of 434,620 ordinary shares to Enron Corp. and various of its subsidiaries in connection with the contribution by such entities of certain assets to PEI under the Enron bankruptcy plan. The relative value of the assets contributed in exchange for the shares was determined in accordance with the methodology established under the Enron bankruptcy plan. The shares issued in consideration of such assets were issued in reliance on Section 4(2). Under the Enron bankruptcy plan, subsequent transfers of such shares were restricted.


ITEM 8.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Exhibits


Exhibit No.			Description

	1	.1	Underwriting Agreement between AEI, the underwriters named therein and the selling shareholders named therein
	3	.1^**	Amended and Restated Memorandum and Articles of Association of AEI dated December 20, 2007
	4	.1	Form of Certificate of Ordinary Shares of AEI
	5	.1	Form of Opinion of Walkers regarding the legality of the shares being registered
	8	.1	Form of Opinion of Walkers regarding certain Cayman Islands tax matters (contained in Exhibit 5.1)

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Exhibit No.			Description

	8	.2	Form of Opinion of Clifford Chance US LLP regarding certain U.S. tax matters
	10	.1^***	Amended and Restated Credit Agreement, dated as of June 6, 2008, among AEI, AEI Finance Holding LLC, various financial institutions as lenders, Credit Suisse, Cayman Islands Branch, JP Morgan Chase Bank, N.A., Credit Suisse Securities (USA) LLC and J.P. Morgan Securities, Inc.
	10	.2^**	Amended and Restated Registration Rights Agreement by and among AEI and certain Investors dated December 29, 2006
	10	.3^**	AEI 2007 Incentive Plan
	10	.6^**	Concession Contract 187/98, dated August 27, 1998, between ANEEL and Elektro Eletricidade e Serviços S.A., as amended
	10	.7^****	Note Purchase Agreement, dated as of May 24, 2007, by and among AEI and the Purchasers named therein
	10	.8^****	First Amendment to the Note Purchase Agreement, dated as of March 11, 2009, by and among AEI and Holders named therein
	10	.9††	Option Agreement, dated as of February 25, 2009, by and among AEI and Holders
	10	.10††	Form of Indemnification Agreement by and between AEI the director or officer named therein
	10	.11	Management Services Agreement, dated October 19, 2006, between Ashmore Energy International Limited and Ashmore Investment Management Limited
	10	.12†††	Amendment No. 1 to Management Services Agreement, dated December 21, 2006
	10	.13†††	Board Observer Agreement between Ashmore Investment Management Limited and AEI
	21	.1^****	Subsidiaries of AEI
	23	.1	Consent of Deloitte & Touche LLP
	23	.2	Consent of Clifford Chance US LLP (contained in Exhibit 8.2)
	23	.3	Consent of Walkers (contained in Exhibit 5.1)
	24	.1^†	Power of Attorney
	24	.2††	Power of Attorney, dated September 17, 2009, of Wilfried E. Kaffenberger
	24	.3†††	Power of Attorney, dated October 1, 2009, of Julian Green


*		To be filed by amendment
**		Previously filed as an exhibit to the Company’s registration statement on Form 20-F (File No. 000-53606) filed with the SEC on March 27, 2009 and incorporated by reference herein.
***		Previously filed as an exhibit to the Company’s registration statement on Form 20-F/A (File No. 000-53606) filed with the SEC on June 17, 2009 and incorporated by reference herein.
****		Previously filed as an exhibit to the Company’s registration statement on Form 20-F/A (File No. 000-53606) filed with the SEC on August 17, 2009 and incorporated by reference herein.
†		Previously filed as an exhibit to the Company’s registration statement on Form F-1 (File No. 333-161420) filed with the SEC on August 18, 2009 and incorporated by reference herein.
††		Previously filed as an exhibit to the Company’s Amendment No. 1 to the registration statement on Form F-1 (File No. 333-161420) filed with the SEC on September 23, 2009 and incorporated by reference herein.


†††		Previously filed as an exhibit to the Company’s Amendment No. 2 to the registration statement on Form F-1 (File No. 333-161420) filed with the SEC on October 7, 2009 and incorporated by reference herein.


ITEM 9.	UNDERTAKINGS

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating

II-4

to the securities offered therein, and the offering of such securities at that time shall he deemed to be the initial bona fide offering thereof.

(3) For the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities: The undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-1 and has duly caused this Amendment No. 3 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Grand Cayman, Cayman Islands, on the 14th day of October, 2009.

AEI


	By:	/s/ James A. Hughes

Name: James A. Hughes


	Title:	Chief Executive Officer, Director

Pursuant to the requirements of the Securities Act of 1933 this Amendment No. 3 to the Registration Statement has been signed by the following persons in the capacities and on the dates indicated.


Signature	Title	Date


/s/ James A. Hughes James A. Hughes	Chief Executive Officer, Director (principal executive officer)	October 14, 2009

/s/ Eduardo Pawluszek Eduardo Pawluszek	Executive Vice President, Chief Financial Officer (principal financial officer)	October 14, 2009

* Laura C. Fulton	Executive Vice President, Accounting (principal accounting officer)	October 14, 2009

* Ronald W. Haddock	Non-Executive Chairman of the Board of Directors	October 14, 2009

* Robert Barnes	Director	October 14, 2009

* Philippe A. Bodson	Director	October 14, 2009

* Robert E. Wilhelm	Director	October 14, 2009

* Henri Philippe Reichstul	Director	October 14, 2009

* George P. Kay	Director	October 14, 2009

II-6


Conflict of Interest		Certain of the underwriters or their affiliates have provided, and may in the future provide, various advisory, banking and other financial services to us or our affiliates from time to time for which they have received or will receive customary fees and expenses. See “Underwriting.” An affiliate of UBS Securities LLC owns in excess of 10% of our issued and outstanding subordinated debt in the form of PIK notes, and consequently UBS Securities LLC has a “conflict of interest” with us within the meaning of NASD Conduct Rule 2720, or Rule 2720, of the Financial Industry Regulatory Authority, Inc. Therefore, this offering will be conducted in accordance with Rule 2720(a)(1).


Tipitapa		Tipitapa Power Company Ltd., our Nicaraguan Power Generation company

Tongda		Tongda Energy Private Limited, our Chinese Natural Gas Distribution business

Trakya		Trakya Elektrik Uretim ve Ticaret A.S.

Transmetano		Transmetano S.A. ESP, our Colombian Natural Gas Transportation and Services business

Transoccidente		Transoccidente S.A. ESP, our Colombian Natural Gas Transportation and Services business

Transoriente		Transoriente S.A. ESP, our Colombian Natural Gas Transportation and Services business

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

U.S. CPI		U.S. consumer price index

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

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


	Page
Unaudited Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008		F-2
Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008		F-3
Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008		F-4
Notes to Unaudited Condensed Consolidated Financial Statements		F-5


	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		F-30
Consolidated Balance Sheets as of December 31, 2008 and 2007		F-31
Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006		F-32
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		F-33
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2008, 2007 and 2006		F-34
Notes to Consolidated Financial Statements		F-35
Schedule II — Valuation and Qualifying Accounts		F-81


	Balance at		Additions
	Beginning		Charged to							Deductions			Balance at
	of the		Costs and		Translation			Acquisitions		Amounts			the End of
Million of Dollars (U.S.)	Period		Expenses		Adjustment			of Business		Written off			the Period

Allowance for lease receivables:
For the year ended December 31, 2006	$	—	$	—	$	—		$	—	$	—		$	—
For the year ended December 31, 2007		—		40		—			—		—			40
For the year ended December 31, 2008		40		44		(3	)		10		(82	)^(a)		9
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
For the year ended December 31, 2008		46		27		(8	)		31		(27	)		69


(a)		Due to termination of lease accounting, the lease receivable and associated allowance have been removed from the Company’s Consolidated Balance Sheet and the amounts were recorded at the net carrying amount in the property, plant and equipment account. See Note 4.


	PEI
											Accumulated
	Invested				Additional			Retain			Other
	Capital		Common		Paid-In			Earnings			Comprehensive			Noncontroling			Total			Comprehensive
	(Predecessor)		Stock		Capital			(Deficits)			Income (Loss)			Interest			Equity			Income
	(In millions)

BALANCE — January 1, 2006	$	—	$	—	$	3,017		$	512		$	(1,058	)	$	205		$	2,676
Net income									164						21			185		$	185
Distributions to shareholders						(740	)		(802	)					(13	)		(1,555	)
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																				$	263

BALANCE — September 6, 2006	$	—	$	—	$	2,235		$	(128	)	$	(977	)	$	213		$	1,343