AES 2006 FactBook

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Transparent disclosure is important to us at AES. This document aims to provide an easily accessible source ofinformation for our investors. Our first investor fact bookpublished in September 2003 was well received by theinvestment community. We hope that this update will alsobe a convenient and useful resource.

This fact book is meant to complement our other disclosures.Our objective is to provide comprehensive informationabout our businesses, capabilities, and prospects to helpyou better understand AES as a company and investmentopportunity. This new edition contains some expandedfinancial disclosures and aligns with the segment reportingthat we introduced in 2007.

Information in this document was current as of December 31,2006, unless otherwise indicated. EDC and Central Valley,businesses sold by AES in the first half of 2007, have beenclassified in discontinued operations and excluded fromthe business descriptions. AES assumes no obligation toupdate any statement or information provided in thisdocument. Reconciliations of non-GAAP financial measuresare included on page 21. Certain financial data presented in this fact book was previously restated. For an explanation

of the restatement see footnote 1 “–Restatement” to the consolidated financial statements included in AES’sannual report on Form 10-K/A for the fiscal year endedDecember 31, 2006, filed with the Securities and ExchangeCommission (SEC) on August 7, 2007.

Electronic copies of this document in Adobe Acrobat format are available on our website, www.aes.com, underInvestor Relations – Investor Resources. Selected tabularinformation is also available in Microsoft® Excel format to facilitate analysis, upon request to the Investor Relationsteam. Inquiries or comments about this fact book shouldbe directed to a member of the AES Investor Relations team listed below.

Ahmed PashaVice President(703)[email protected]

Hilary MaxsonDirector(703)[email protected]

CAUTIONARY INFORMATION

The 2006 AES Fact Book has been prepared to provideunaudited supplemental financial, operational and statisticalinformation about the AES Corporation and its subsidiaries.Its contents do not constitute a complete set of financialstatements prepared in accordance with generally acceptedaccounting principles. Therefore, it should only be used inconjunction with, and not instead of, the Company’sreports filed with the SEC. It is not intended for use andcannot be used in connection with any sale or purchase of,or any offer to buy, any securities of the AES Corporationor its subsidiaries.

The 2006 AES Fact Book contains both historical and forward-looking statements within the meaning of thePrivate Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to,those related to future earnings, growth and financial andoperating performance. Forward-looking statements arenot intended to be a guarantee of future results, but insteadconstitute AES’s current expectations based on reasonableassumptions. Forecasted financial information is based on

certain material assumptions. These assumptions include,but are not limited to, continued normal or better levels ofoperating performance and electricity demand at our distribution companies and operational performance at our contract generation businesses consistent with historicallevels, as well as achievements of planned productivityimprovements and incremental growth from investmentsat investment levels and rates of return consistent withprior experience. Actual results could differ materially fromthose projected in our forward-looking statements due torisks, uncertainties and other factors. These factors are discussed in AES’s filings with the SEC including, but notlimited to, the risks discussed under Item 1A “Risk Factors”in the Company’s Annual Report on Form 10-K/A for theyear ended December 31, 2006, as well as our other SEC filings. Readers are encouraged to read AES’s filings to learn more about the risk factors associated with AES’s business. Unless required by applicable law, AES under-takes no obligation to update or revise any forward-lookingstatement, whether as a result of new information, futureevents or otherwise.

TABLE OF CONTENTS

1: AES OVERVIEW 12: FINANCIAL OVERVIEW 93: BUSINESS DESCRIPTIONS 234: HOLDING COMPANY 1175: APPENDIX 135

ON THE COVER: A glass ball at a market in Chengdu, China

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AES is a global power and alternative energy company. Spanning 28 countries and five continents, we have over$11 billion in revenues and 30,000 employees. We arefocused on meeting today’s energy needs while looking tothe future. Aggressively pursuing growth, we are expandingin fast growing and high-demand markets for both corepower and in the vital area of alternative energy and climatechange. We do both responsibly and with sustainability inmind, to ensure safe, secure and reliable energy for our cus-tomers in a way that preserves our environment.

Today, AES powers growth in economies, areas and com-munities as diverse as Chile and India, Central America andEastern Europe, São Paulo and Indianapolis. We believe in, and

are committed to providing safe and reliable electricity – toimprove the quality of life, to spur growth, and to keep thewheels of commerce turning. But it doesn’t stop there.

As the world’s energy needs evolve, so do we. We continueto branch into new sources of energy, and renewables, suchas wind, hydro and biomass, which now compose 20% ofour generation capacity worldwide. To accelerate thegrowth of our company and create long-term value, we arelooking beyond our core business into new and adjacentmarkets. Our new initiatives range from climate change totransmission lines to broadband over power lines (BPL) to solar power.

EUROPE & AFRICA Total generation12,140 MWTotal distribution 11,056 GWh

ALTERNATIVE ENERGYTotal wind generation1,015 MW

ASIATotal generation 5,739 MW

• AES Operations, including:Distribution BusinessesGeneration FacilitiesPlants Under Construction

NORTH AMERICA Total generation13,491 MWTotal distribution: 16,278 GWh

LATIN AMERICA Total generation11,866 MWTotal distribution 49,684 GWh

Capacity as of June 30, 2007, GWh sold for year ended December 31, 2006

A E S 2 0 0 6 FA C T B O O K

A STRONG PLATFORM FOR GROWTH

AES is in markets where some of our greatest growthopportunities exist. Our broad global footprint combineswith strong local insight and working relationships. Ourpeople are able to draw on expertise from around our globalenterprise. Collectively, we are expert in diverse technologies

and fuel types and can deploy our global talent wherever it is needed. This allows us to act quickly and effectively,where opportunities arise, with the right people and mostappropriate technology and development solutions.

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REGIONAL FOCUS

Headquartered in Arlington, VA, AES is one of the few trulyglobal power companies. Our operations are organized into four regions: North America; Latin America; Europe,CIS and Africa; Asia and the Middle East. We also have anAlternative Energy Group to pursue strategic initiatives likewind generation, greenhouse gas emissions credits projectsand new technologies. This structure enables us to focusdevelopment efforts on targeted markets with the greatestpotential for value creation – benefiting from high-growth

emerging economies while enjoying stability from our presence in more mature markets.

Our global Business Excellence group is developing aninfrastructure to foster innovation, share knowledge and generate performance results across AES’s regional businesses. It provides support in areas such as safety, environment, engineering and construction, procurementand information technology.

INTO THE FUTURE

We are in the right business, both for today and tomorrow.Global demand for energy is expected to increase 50% by2020, and alternative energy is expected to play an ever-increasing role in that growth.

AES’s core business will continue to expand into highgrowth economies, where tomorrow’s energy markets arerapidly emerging. Within the next five years, we intend toadd 6,500 MW of new conventional generation capacity toour portfolio.* We currently have 25,000 MW of potentialnew greenfield power plants worldwide in our developmentpipeline in countries new to our portfolio such as Turkey,Indonesia, Vietnam and South Africa as well as in marketswhere we have a significant presence today, such as Chile,India, Cameroon, Kazakhstan, the UK and the US. In addi-tion to greenfield expansions, we are also pursuing platformexpansions, selective acquisitions and other new projects.

As demand for more sustainable and secure sources ofenergy expands, so will AES’s capabilities to provide alter-native energy solutions. We plan to invest $2.5 billion overthe next four years to further grow our alternative energybusiness. Most of our projected activity in this area is inwind generation and greenhouse gas emissions credits.

We expect to triple our wind power capacity by 2011,adding 2,100 MW to our global portfolio. Around theworld, we currently have more than 4,000 MW of windprojects in various stages of development in fast-growingareas such as California, Texas, Scotland, France andBulgaria. And we are pursuing opportunities in many othercountries where AES already has a presence such as China,where the government has set a goal to develop 30,000 MWof wind power by 2020.

AES has staked out a leading role in the emerging businessof climate change, helping to develop the global market –an estimated $10 billion a year market – for greenhouse gasoffset credits. AES is at the forefront of multinational corporations in developing solutions for combating globalwarming, and for establishing the precedents that willenable others to become more easily involved.

AES will continue to seize new opportunities – includingthose beyond power – where we can leverage our corestrengths to succeed. As we look to the future, our commitment remains: to serve all of our stakeholdersthrough disciplined, sustained, responsible growth.

* Some of this additional generation capacity will still be under construction in 2011.

For 26 years, our people have developed successful projectsin complex environments all over the world. This wellspringof development and operational experience is readilyapplied to new opportunities. The AES business cultureenables entrepreneurial thinking and the sharing of our

best ideas from business to business and person to person.This sharing of knowledge helps us to continually improveoperations and enhance business development acrossthe globe.

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WIND

The global wind market is expected to more than triple insize – from 73 to over 230 gigawatts – by 2015. We are committed to rapidly expanding our wind generation businessworldwide and expect to triple our wind power capacity by

2011. Our global wind pipeline exceeds 4,000 MW inactive development and includes wind projects in theUnited States, Scotland, France, Bulgaria and China.

CLIMATE CHANGE

We believe the market for greenhouse gas emissions offsetcredits will grow significantly as a result of increasinglystringent environmental regulations and a growing politicalconsensus on the problems of global warming. The firstphase of the Kyoto Protocol goes into effect at the beginningof 2008 and is expected to create a need for at least500 million carbon credits annually. There is also a growinginterest in the voluntary market for carbon credits in the

United States, with the potential for mandatory emissionslimits in the future. We see climate change as a significantbusiness opportunity and are aggressively pursuing thedevelopment of projects that create credits. Given ourglobal footprint and experience and expertise in projectdevelopment, particularly in emerging markets, we areuniquely positioned for a leadership role in this market.

LNG

Demand for clean-burning natural gas in the United Statesis expected to increase by 13% over the next five years,while domestic supply is expected to decline. The best wayto meet increasing demand for natural gas is to ship it fromoverseas in liquefied form and then convert it back at LNG

regasification facilities. LNG imports are expected to grow from 3% of the U.S. supply today to 24% by 2024. Inresponse, AES is developing LNG regasification terminalsto supply high demand markets in the U.S.

The world’s energy needs are changing and so is AES. We are expanding our capabilities to

seize new opportunities, including those beyond power, to meet the demand for a more

secure and sustainable energy future. In 2006 we launched our Alternative Energy business

to expand high growth areas such as wind generation, liquefied natural gas (LNG) facilities

and climate change. Over the next decade, we see an opportunity to invest up to $10 billion

in our newly launched alternative energy business. We believe these efforts will pave the

way for our success in the years to come.


BEYOND POWER

Since its inception, AES has successfully identified andbenefited from new opportunities in power markets world-wide. To accelerate the growth of our company and createlong-term value, we are leveraging our global footprint,market insights and skills to seize new opportunities beyondtraditional power. Our experience in operating waterdesalination facilities at our plants in Oman and Qatar couldposition us to take advantage of opportunities as the world’s

freshwater supply becomes constrained. We are also pursu-ing new technologies that expand or complement our cur-rent business including broadband over power lines, energystorage and energy efficiency solutions and power manage-ment. We are actively evaluating future investments inother alternative energy sources such as ethanol, biodieseland solar power.

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HIGHLIGHTS

■ 13 distribution businesses owned by AES

■ Three distribution businesses operated under management agreements

■ Eight countries

■ 4,526 MW installed capacity, over 11 million customers, 77,027 GWh sold in 2006

■ Key drivers: strength of local economy and demand for electricity, reliability of service and loss reduction programs, tariff adjustments

■ Key businesses: IPL and Eletropaulo

Our power distribution businesses have a variety of structures.Some businesses are fully vertically integrated with genera-tion, transmission and distribution. They benefit from thenatural hedge that is created by combining both generationand distribution facilities. Other businesses are partiallyintegrated with transmission and distribution. Some arepure distribution businesses, serving customers within a concession area by transporting purchased electricity fromindependent generators or marketers.

Quality of service, changing demand for electricity,working capital management, tariff adjustments and, indeveloping countries, reduction of commercial and technicallosses are important influences on revenues, earningsand cash flow.

The performance of these businesses is impacted by theregulatory environment in which they operate and the variations in the policies and practices of the local andinternational entities that regulate activities relating toownership, marketing, delivery and pricing of electricityand fuel. Most of our power distribution companies operate in monopolistic concession areas and face very limited competition from other distributors.

Power distribution revenues result primarily from retailelectricity sales to customers under regulated tariffs. Inmany instances, regulators set rates on a cost-plus basis,where rates are set to recover costs and to provide a returnon shareholder investment. The prospects for stable growthin this segment are highly correlated to the strength of thelocal economy, the unique electricity market conditions,weather conditions, success of the operational changesimplemented and growth in the customer base.

Most of AES’s power distribution is located in transitionaleconomies where demand for electricity is expected to grow at a higher rate than in more developed parts of theworld. These businesses may face challenges related to out-dated equipment, theft-related losses, problems associatedwith safety and nonpayment, emerging economies, andpotentially less stable governments or regulatory regimes.

However, these conditions often provide for significantopportunities to implement operating improvements thatmay stimulate growth in earnings and cash flow at ratesgreater than those typically achievable in AES’s other linesof business.

AES distributes power to customers in eight countries on five continents. One of our Brazilian

businesses is the largest distribution company in Latin America.* We serve markets with

growing needs for power, such as Cameroon, where we are the primary generator and

distributor of electricity.

* In terms of revenue and volume distributed.


AES’s Generation business includes businesses operating or under construction in 24 countries

on five continents. AES’s first investments were in contracted power plants, as are some of

our most recently announced projects including our lignite-fired plant in Bulgaria and many

others in early stages of development around the world.

Our generation portfolio uses a wide range of technologiesand fuel sources, from combined cycle gas turbines in theMiddle East and hydroelectric power in Brazil to coal plantsin the United States and biomass plants in the CzechRepublic and Hungary.

Approximately 68% of AES’s Generation business is composed of generation facilities that have contractuallylimited their exposure to commodity price risks, primarilyelectricity price volatility and volume risk, by entering intopower sales agreements with initial terms of five years orlonger for at least 75% of their output capacity.

These businesses typically enter into a contract with onemajor customer, but may also have a series of contractswith several unrelated customers. In addition, the facilitiesgenerally enter into long-term agreements for most of theirfuel supply requirements, or they may enter into tolling or

“pass through” arrangements in which the counter-partydirectly assumes the risks associated with providing thenecessary fuel and then markets the generated power.Revenues for many contracts are also adjusted to pass throughhigher costs due to changes in inflation. Due to these contractual agreements, the businesses in this segment arecharacterized by relatively stable and predictable revenues,earnings and cash flows. The degree of predictability variesfrom business to business based on the degree to whichtheir exposure is limited by the contracts that the busi-nesses negotiated with their offtakers.

AES seeks to enter into power purchase agreements withcustomers who have their debt or preferred securities rated“investment grade,” or to obtain sovereign governmentguarantees of the customer’s obligations. Since customersvary from business to business, our contracted generationbusinesses have minimal exposure to the creditworthiness

HIGHLIGHTS

■ 117 power generation facilities owned by AES, including wind generation and facilities owned by AES’s integrated powerdistribution businesses

■ 6 power generation facilities under construction

■ 4 generation facilities under management agreements

■ 24 countries

■ 44 GW installed capacity*

■ Key drivers: reliable operations, high availability, effective contract negotiation and management, customer credit quality, commodity prices

■ Key businesses: Gener, Eastern Energy, Southland, Puerto Rico, AES Kazakhstan

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* Includes facilities under construction and generation owned by integrated power distribution businesses

8 A E S 2 0 0 6 FA C T B O O K

of a single large customer. Additionally, in countries wherewe own distribution companies, we seek to contract ourgeneration businesses with the distribution companies thatwe control. AES believes that locating its plants in differentgeographic areas helps mitigate the effects of regional economic downturns, thereby reducing risks associatedwith operating in less developed countries.

We face most of our competition in contracted generationbusinesses prior to the execution of a power sales agreementduring the development phase of a project and as contractsnear expiration and we seek to extend contracts or seeknew contracts with other customers. Due to the long-termnature of sales contracts, we generally face very limitedcompetition during the operational phase.

The remainder of AES’s generation businesses sell powerthrough competitive markets under short-term contractsor directly in the spot market. A relatively small number ofAES’s generation businesses operate in truly competitivecommodity markets, such as the US, UK, and Argentina.Other businesses operate in more structured (less com -petitive) markets, such as Kazakhstan, where power salesare conducted through short-term bilateral sales agreementsafter direct negotiations.

These businesses tend to have more varied revenues, earningsand cash flow. However, the profitability can be well aboveaverage for a low-cost production facility in a strong demandmarket. Demand can be affected by weather, electricitytransmission constraints, fuel prices and competition.

The absence of long-term contracts can result in uncertaintyrelating to future production volumes, which in turn causes uncertainty with respect to the volume of fuel to be consumed to support such production.

AES has used hedging strategies, where appropriate, tohedge its financial performance against the effects of fluc-tuations in energy commodity prices. The implementationof this strategy involves the use of commodity forward contracts, futures, swaps and options. AES maintains creditpolicies with regard to its counterparties.

AES does not engage in speculative trading, but insteadactively manages its spread risk, the difference betweenpower price and fuel cost. To the extent allowed by creditlimits, these businesses lock in power and fuel prices tocover their fixed costs and hedge the majority of dividendsin the short term. Some capacity remains uncontracted,providing an operational hedge against unit outages andsome upside potential.

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(1) 2006 results include Brazil restructuringimpacts that are unfavorable to income before tax and minority interest by $634 million and unfavorable to diluted EPS from continuing operations by $0.76 per share.

(2) A non-GAAP financial measure. See page 21.

Maintenance CapexEnvironmental CapexFree Cash Flow

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12,000 11,56410,320

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Non-Recourse Debt

Net Cash Provided by OperatingActivities and Free Cash Flow(2)

$ in millions $ in millions $ in millions

$ per share $ per share $ in millions

$ in millions $ in millions

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CONSOLIDATED STATEMENTS OF OPERATIONS

2004 2005 2006

REVENUES Regulated $ 4,553 $ 5,617 $ 6,198Non-regulated 4,192 4,703 5,366 Total revenues 8,745 10,320 11,564

COST OF SALES Regulated (3,328) (4,021) (4,114)Non-regulated (2,859) (3,371) (4,052)Total cost of sales (6,187) (7,392) (8,166)Gross margin 2,558 2,928 3,398General & administrative expenses (181) (225) (305)Interest expense (1,816) (1,826) (1,763)Interest income 254 375 426Other income (expense), net 37 47 (343) (Loss) gain on sale of investments &

impairment expense (1) – 98 Loss on sale of subsidiary stock (24) – (539) Asset impairment expense (49) (16) (28)Foreign currency transaction losses, net (109) (145) (88)Equity in earnings of affiliates 63 71 72Income before income taxes &

minority interest 732 1,209 928 Income tax expense (365) (483) (334) Minority interest expense (195) (324) (459)Income from continuing operations 172 402 135Income from operations of discontinued businesses 41 188 105Gain (loss) on sale of discontinued businesses 91 – (57) Extraordinary item – – 21Cumulative effect of change in accounting principle – (3) – Net income 304 587 204

BASIC EARNINGS PER SHARE Income from continuing operations $ 0.27 $ 0.62 $ 0.21Discontinued operations 0.20 0.29 0.07 Extraordinary item – – 0.03 Cumulative effect of change in accounting principle – (0.01) – Basic earnings per share 0.47 0.90 0.31Basic shares outstanding 641 654 661

DILUTED EARNINGS PER SHARE Income from continuing operations $ 0.27 $ 0.61 $ 0.20Discontinued operations 0.20 0.28 0.07 Extraordinary item – – 0.03 Cumulative effect of change in accounting principle – (0.01) – Diluted earnings per share 0.47 0.88 0.30 Diluted shares outstanding 648 665 672

ADJUSTED EPS RECONCILIATION Diluted EPS from continuing operations $ 0.27 $ 0.61 $ 0.20FAS 133 mark to market (gains) losses (0.01) – – Currency transaction (gains) losses 0.04 0.03 0.01 Net asset (gains) losses & impairments 0.08 – 0.68 Debt retirement (gains) losses 0.02 – 0.04 Adjusted EPS 0.40 0.64 0.93

SUPPLEMENTAL DISCLOSURE Depreciation & amortization from continuing operations $ 692 $ 770 $ 835

In millions, except per share data, for the years ended December 31

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CONSOLIDATED BALANCE SHEETS

2004 2005 2006

ASSETSCURRENT ASSETS Cash & cash equivalents $ 931 $ 1,176 $ 1,379

Restricted cash 441 437 548Short-term investments 133 199 640Accounts receivable, net 1,406 1,517 1,769Inventory 374 421 471Receivable from affiliates 4 71 76Deferred income taxes – current 191 258 208Prepaid expenses 69 113 109Other current assets 666 670 927Current assets of held for sale &

discontinued businesses 721 425 438Total current assets 4,936 5,287 6,565

PROPERTY, PLANT & EQUIPMENT Land 765 837 928Electric generation & distribution assets 19,535 20,266 21,835Accumulated depreciation (4,940) (5,632) (6,545)Construction in progress 374 681 979 Property, plant & equipment, net 15,734 16,152 17,197

OTHER ASSETS Deferred financing costs, net 313 268 279Investments in & advances to affiliates 742 664 595Debt service reserves & other deposits 515 546 524Goodwill, net 1,401 1,410 1,416Other intangible assets, net 224 276 298Deferred income taxes – noncurrent 685 698 602Other assets 1,523 1,407 1,634Long-term assets of held for sale &

discontinued businesses 2,344 2,287 2,091Total other assets 7,747 7,556 7,439Total assets $28,417 $28,995 $31,201

In millions, as of December 31


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LIABILITIES & STOCKHOLDERS’ EQUITYCURRENT LIABILITIES Accounts payable $ 932 $ 998 $ 795

Accrued interest 311 373 404 Accrued & other liabilities 1,589 2,037 2,131 Recourse debt – current portion 142 200 – Non-recourse debt – current portion 1,396 1,367 1,411 Current liabilities of held-for-sale &

discontinued businesses 447 301 288Total current liabilities 4,817 5,276 5,029

LONG-TERM LIABILITIES Non-recourse debt 10,587 10,318 9,834 Recourse debt 5,010 4,682 4,790 Deferred income taxes – noncurrent 726 789 803Pension liabilities & other

post-retirement liabilities 828 829 844 Other long-term liabilities 3,367 3,337 3,554 Long-term liabilities of held-for-sale &

discontinued businesses 817 545 434Total long-term liabilities 21,335 20,500 20,259

Minority interest 1,308 1,607 2,948

STOCKHOLDERS’ EQUITY Common stock 7 7 7 Additional paid-in capital 6,478 6,561 6,654 Accumulated deficit (1,887) (1,300) (1,096) Accumulated other comprehensive loss (3,641) (3,656) (2,600)Total stockholders’ equity 957 1,612 2,965Total liabilities & stockholders’ equity $28,417 $28,995 $31,201

In millions, as of December 31

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CONSOLIDATED STATEMENTS OF CASH FLOWS

2004 2005 2006

OPERATING ACTIVITIES Net income $ 304 $ 587 $ 204Adjustments to net income:

Depreciation & amortization of intangible assets 777 864 933

Loss from sale of investments & goodwill & asset impairment expense 74 49 491

(Gain) loss on disposal & impairment write-down associated with discontinued operations (98) – 62

Provision for deferred taxes 211 138 (34)Minority interest expense 211 354 478Contingencies 28 (10) 173(Gain) loss on extinguishment of debt (59) 1 148Other 297 132 58

Changing in operating assets & liabilities:(Increase) decrease in accounts receivable (110) – 93Increase in inventory (23) (58) (13)(Increase) decrease in prepaid expenses &

other current assets (82) 124 (55)(Increase) decrease in other assets (62) 83 151Increase (decrease) in accounts payable &

other current liabilities 74 (134) (382)(Decrease) increase in other liabilities (45) 102 53

Net cash provided by operating activities 1,497 2,232 2,360

INVESTING ACTIVITIES Capital expenditures (706) (826) (1,460)Acquisitions, net of cash acquired (20) (85) (19)Proceeds from the sales of businesses 35 22 898Proceeds from the sales of assets 28 26 24Sale of short-term investments 1,402 1,499 2,011Purchase of short-term investments (1,388) (1,345) (2,359)(Increase) decrease in restricted cash (43) 94 (8)Purchase of emission allowances (5) (19) (77)Proceeds from the sales of emission allowances 3 42 82(Decrease) increase in debt service reserves &

other deposits (63) (100) 46Purchase of long-term available-for-sale securities – – (52)Other investing 14 31 12Net cash used in investing activities (743) (661) (902)

In millions, for the years ended December 31


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FINANCING ACTIVITIES Borrowings (repayments) under the revolving credit facilities, net $ – $ 53 $ 72

Issuance of recourse debt 491 5 –Issuance of non-recourse debt 2,110 1,710 3,097Repayments of recourse debt (1,140) (259) (150)Repayments of non-recourse debt (2,534) (2,651) (4,059)Payments for deferred financing costs (109) (21) (86)Distributions to minority interests (139) (186) (335)Contributions from minority interests 24 1 125Issuance of common stock 16 26 78Financed capital expenditures (6) (1) (52)Other financing 2 (16) (7)Net cash used in financing activities (1,285) (1,339) (1,317)Effect of exchange rates changes on cash 6 13 62Total (decrease) increase in cash &

cash equivalents (525) 245 203Cash & cash equivalents, beginning 1,456 931 1,176Cash & cash equivalents, ending 931 1,176 1,379

SUPPLEMENTAL DISCLOSURES Cash payments for interest – net of amounts capitalized $ 1,759 $ 1,674 $ 1,718

Cash payments for income taxes – net of refunds 197 268 479

Maintenance capital expenditures 528 635 867Growth capital expenditures 184 192 645Free cash flow 969 1,597 1,493

SCHEDULE OF NON-CASH Common stock issued for debt retirement 168 – –INVESTING & FINANCING ACTIVITIES Brasiliana Energia debt exchange 773 – –

Transfer of Infoenergy to Brasiliana – – 13IQP – Buyers’ Assumption of Debt – – 30


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REVENUES

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LATIN AMERICA Utilities $ 991 $1,013 $1,022 $1,135 $ 4,161 $1,104 $1,156 $1,170 $1,165 $ 4,595Generation 474 515 587 569 2,145 600 620 685 711 2,616Subtotal 1,465 1,528 1,609 1,704 6,306 1,704 1,776 1,855 1,876 7,211

NORTH AMERICA Utilities 227 229 254 241 951 255 251 274 252 1,032Generation 408 430 470 477 1,785 495 459 490 427 1,871Subtotal 635 659 724 718 2,736 750 710 764 679 2,903

EUROPE, CIS Utilities 129 119 112 145 505 152 136 131 152 571& AFRICA Generation 224 169 153 189 735 208 186 196 262 852

Subtotal 353 288 265 334 1,240 360 322 327 414 1,423

ASIA & MIDDLE EAST Generation 155 137 136 172 600 180 240 191 174 785

OTHER (117) (133) (153) (159) (562) (188) (186) (190) (194) (758)Total 2,491 2,479 2,581 2,769 10,320 2,806 2,862 2,947 2,949 11,564

GROSS MARGIN

1Q 2Q 3Q 4Q 2005 1Q 2Q 3Q 4Q 2006

LATIN AMERICA Utilities $207 $ (40) $176 $253 $ 596 $229 $267 $188 $200 $ 884Generation 179 166 280 232 857 259 255 267 273 1,054Subtotal 386 126 456 485 1,453 488 522 455 473 1,938

NORTH AMERICA Utilities 82 75 88 56 301 64 59 89 65 277Generation 132 135 178 154 599 176 133 149 107 565Subtotal 214 210 266 210 900 240 192 238 172 842


Subtotal 104 59 38 97 298 116 84 68 93 361


OTHER 10 9 10 6 35 12 13 12 20 57Total 782 468 825 853 2,928 905 867 826 800 3,398

In millions


DEPRECIATION & AMORTIZATION FROM CONTINUING OPERATIONS

1Q 2Q 3Q 4Q 2005 1Q 2Q 3Q 4Q 2006

LATIN AMERICA Utilities $ (36) $ (39) $ (40) $ (40) $(155) $ (43) $ (45) $ (46) $ (48) $(182)Generation (33) (33) (33) (37) (136) (39) (37) (38) (40) (154)Subtotal (69) (72) (73) (77) (291) (82) (82) (84) (88) (336)

NORTH AMERICA Utilities (34) (33) (34) (35) (136) (34) (34) (34) (34) (136)Generation (39) (40) (40) (43) (162) (41) (42) (42) (42) (167)Subtotal (73) (73) (74) (78) (298) (75) (76) (76) (76) (303)

EUROPE, CIS Utilities (12) (12) (12) (11) (47) (11) (12) (13) (13) (49)& AFRICA Generation (15) (16) (14) (15) (60) (15) (15) (16) (15) (61)

Subtotal (27) (28) (26) (26) (107) (26) (27) (29) (28) (110)

ASIA & MIDDLE EAST Generation (16) (16) (16) (14) (62) (16) (16) (16) (14) (62)

OTHER (2) (3) (3) (4) (12) (4) (6) (5) (9) (24)Total (187) (192) (192) (199) (770) (203) (207) (210) (215) (835)

INTEREST EXPENSE

1Q 2Q 3Q 4Q 2005 1Q 2Q 3Q 4Q 2006

LATIN AMERICA Utilities $(113) $(136) $(139) $(153) $ (541) $(116) $(130) $(141) $(118) $ (505)Generation (85) (71) (66) (96) (318) (69) (72) (78) (72) (291)Subtotal (198) (207) (205) (249) (859) (185) (202) (219) (190) (796)

NORTH AMERICA Utilities (29) (28) (29) (29) (115) (29) (28) (29) (34) (120)Generation (59) (69) (56) (67) (251) (56) (58) (70) (65) (249)Subtotal (88) (97) (85) (96) (366) (85) (86) (99) (99) (369)

EUROPE, CIS Utilities (4) (4) (3) (1) (12) (2) (2) (3) (3) (10)& AFRICA Generation (16) (16) (15) (15) (62) (15) (11) (18) (14) (58)

Subtotal (20) (20) (18) (16) (74) (17) (13) (21) (17) (68)


OTHER Recourse (111) (110) (105) (109) (435) (107) (108) (110) (113) (438)Non-recourse – – – 1 1 (2) (1) – – (3)Subtotal (111) (110) (105) (108) (434) (109) (109) (110) (113) (441)

Total (439) (459) (436) (492) (1,826) (418) (432) (473) (440) (1,763)

In millions

1 8 A E S 2 0 0 6 FA C T B O O K

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INCOME BEFORE TAX & MINORITY INTEREST

1Q 2Q 3Q 4Q 2005 1Q 2Q 3Q 4Q 2006

LATIN AMERICA Utilities $ 125 $ (34) $ 63 $ 134 $ 288 $ 127 $165 $(443) $ (33) $(184)Generation 113 108 233 129 583 239 203 212 149 803Subtotal 238 74 296 263 871 366 368 (231) 116 619

NORTH AMERICA Utilities 53 47 59 26 185 34 29 58 32 153Generation 74 64 135 82 355 211 65 62 26 364Subtotal 127 111 194 108 540 245 94 120 58 517


Subtotal 86 47 25 86 244 117 80 38 56 291


OTHER (146) (155) (143) (177) (621) (174) (134) (145) (173) (626)Total 357 123 416 313 1,209 585 450 (178) 71 928

MINORITY INTEREST EXPENSE

1Q 2Q 3Q 4Q 2005 1Q 2Q 3Q 4Q 2006

LATIN AMERICA Utilities $ (46) $ 50 $ 6 $ (59) $ (49) $ (2) $ (85) $ (106) $ 28 $(165)Generation (33) (37) (66) (55) (191) (53) (63) (63) (45) (224)Subtotal (79) 13 (60) (114) (240) (55) (148) (169) (17) (389)

NORTH AMERICA Utilities – – – – – – – – – –Generation – (1) (1) 3 1 (1) (2) – – (3)Subtotal – (1) (1) 3 1 (1) (2) – – (3)

EUROPE, CIS Utilities (5) (5) (3) (11) (24) (7) (5) (5) (8) (25)& AFRICA Generation (1) – – – (1) (1) – – (1) (2)

Subtotal (6) (5) (3) (11) (25) (8) (5) (5) (9) (27)


OTHER – – (7) 7 – 1 – 1 3 5Total (103) (10) (85) (126) (324) (74) (169) (185) (31) (459)

In millions


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DISTRIBUTIONS FROM SUBSIDIARIES

1Q 2Q 3Q 4Q 2005 1Q 2Q 3Q 4Q 2006

LATIN AMERICA Utilities $ 22 $ – $ 29 $ 72 $123 $ 19 $ – $106 $ 17 $142Generation 3 16 11 53 83 1 38 1 102 142Subtotal 25 16 40 125 206 20 38 107 119 284

NORTH AMERICA Utilities 47 52 55 54 208 – 65 34 43 142Generation 86 58 122 71 337 82 21 175 75 353Subtotal 133 110 177 125 545 82 86 209 118 495

EUROPE, CIS Utilities 1 1 – 27 29 – 10 5 10 25& AFRICA Generation 7 30 17 29 83 15 16 27 14 72

Subtotal 8 31 17 56 112 15 26 32 24 97


OTHER – – – – – – 2 3 4 9Total 195 170 274 354 993 131 177 352 311 971

In millions

2 0 A E S 2 0 0 6 FA C T B O O K

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TOP 10 SUBSIDIARY DISTRIBUTIONS

2004 2005 2006

IPALCO, U.S. $ 177 IPALCO, U.S. $208 Eastern Energy, U.S. $ 162Gener, Chile 151 EDC, Venezuela 107 IPALCO, U.S. 142Eastern Energy, U.S. 94 Eastern Energy, U.S. 85 EDC, Venezuela 100EDC, Venezuela 77 Shady Point, U.S. 57 Gener, Chile 81Shady Point, U.S. 76 Hawaii, U.S. 46 Hungary 37Hawaii, U.S. 47 Ras Laffan, Qatar 45 Hawaii, U.S. 35Ebute, Nigeria 33 Gener, Chile 36 Alicura, Argentina 33Southland, U.S. 28 Alicura, Argentina 30 CAESS & EEO, El Salvador 31Barka, Czech Republic 21 Southland, U.S. 29 Shady Point, U.S. 30CTSN (San Nicholas), Argentina 21 Global Insurance, U.S. 25 Deepwater, U.S. 29Subtotal – top 10 725 Subtotal – top 10 668 Subtotal – top 10 680Other businesses 279 Other businesses 325 Other businesses 291Total 1,004 Total 993 Total 971



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RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

2004 2005 2006

RECONCILIATION OF Maintenance capital expenditures (528) (635) (867)CAPITAL EXPENDITURES Growth capital expenditures (184) (192) (645)

Capital expenditures (712) (827) (1,512)

RECONCILIATION OF Net cash provided by operating activities 1,497 2,232 2,360FREE CASH FLOW Maintenance capital expenditures (528) (635) (867)

Free cash flow 969 1,597 1,493

RECONCILIATION OF ADJUSTED Diluted earnings per share from EARNINGS PER SHARE continuing operations 0.27 0.61 0.20

Excluded factors, net 0.13 0.03 0.73 Adjusted earnings per share 0.40 0.64 0.93

RECONCILIATION OF Subsidiary distributions to parent 1,004 993 971SUBSIDIARY DISTRIBUTIONS Returns of capital to parent 127 57 72

Total subsidiary distributions & returns of capital to parent 1,131 1,050 1,043

RECONCILIATION OF Sum of business revenues presented in Fact Book 9,091 11,007 12,581REVENUES PRESENTED Other revenues, net of total IN FACT BOOK intercompany eliminations (346) (687) (1,017)

Consolidated revenues 8,745 10,320 11,564

In millions, except per share data, for the years ended December 31

2 2 A E S 2 0 0 6 FA C T B O O K

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Management uses certain non-GAAP measures to assessthe Company’s current and expected future financial performance. The non-GAAP measures complement, butdo not replace, the presentation of AES’s financial results byproviding supplemental information to better understandAES’s financial position and results of operation. AES provides this information to help investors better understandtrends and evaluate past, current and future operating results.

■ Adjusted Earnings per Share is defined as diluted earningsper share from continuing operations excluding gains orlosses associated with (a) mark-to-market amounts relatedto FAS 133 derivative transactions, (b) foreign currencytransaction impacts on the net monetary position relatedto Brazil and Argentina, (c) significant asset gains or lossesdue to disposition transactions and impairments, and (d)early retirement of recourse debt. AES believes thatadjusted earnings per share better reflects the underlyingbusiness performance of the Company, and is consideredin the Company’s internal evaluation of financial perform-ance. Factors in this determination include the variabilityassociated with mark-to-market gains or losses related tocertain derivative transactions, currency gains and losses,periodic strategic decisions to dispose of certain assetswhich may influence results in a given period, and theearly retirement of corporate debt.

■ Free Cash Flow is defined as net cash flow from operatingactivities less maintenance capital expenditures. Main -tenance capital expenditures reflect property additionsless growth capital expenditures. AES believes that freecash flow is a useful measure for evaluating our financialcondition because it represents the amount of cash pro-vided by operations less maintenance capital expenditures,as defined by our businesses, which may be available forinvesting or for repaying debt.

■ Liquidity is cash at the parent company plus availabilityunder corporate revolver plus cash at qualifying holdingcompanies (QHCs). AES believes that unconsolidatedparent company liquidity is important to the liquidityposition of AES as a parent company because of the non-recourse nature of most of AES’s indebtedness.

■ Subsidiary distributions are cash distributions (primarilydividends and interest income) from subsidiary companiesto the parent company and qualified holding companies.AES believes subsidiary distributions are an importantmeasure, as these cash flows are the source of cash flow tothe parent to meet corporate interest, overhead, cashtaxes, and discretionary uses such as recourse debt reduc-tions and corporate investments.

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2 4 A E S 2 0 0 6 FA C T B O O K

HIGHLIGHTS

■ Operating facilities in the region since 1986

■ 9,892 MW installed generating capacity across 21 facilities

■ One integrated electric utility, Indianapolis Power and Light (IPL), serves over 468,000 customers with four generationplants representing 3,599 MW of capacity

■ 25% of AES’s consolidated 2006 revenues

■ 25% of AES’s consolidated 2006 gross margin

■ 51% of AES’s 2006 subsidiary distributions

■ Key drivers: demand growth and tariff recovery for environmental projects (IPL); dark spread margins (Eastern Energyand Deepwater); operational efficiency; growth from new investments

AES’s North American operations include power generation

and distribution businesses in the U.S. and generation businesses

in Mexico. With efficient technologies and the expansion of

renewable generation, AES continues to drive performance and

growth in this region’s highly competitive power sector.

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Note: AES wind production facilities located in North America are discussed under Alternative Energy.

2 53 : B U S I N E S S D E S C R I P T I O N S – N O R T H A M E R I C A

CONTENTS

NORTH AMERICA

MEXICO 26

Mérida III 26

TEG and TEP 27

USA 28

USA Regulatory Overview 28

Indiana Regulatory Overview 30

IPALCO 31

Placerita 33

Hemphill 33

Southland 34

Thames 36

AES Hawaii 37

Warrior Run 38

Red Oak 39

Ironwood 39

Eastern Energy 40

Shady Point 42

Beaver Valley 43

AES Puerto Rico 44

Deepwater 45

Deepwater, Texas was the first AES power project, entering

commercial operation in 1986. Through greenfield construction

and selected acquisitions, AES has built a strong portfolio of

generation assets, largely supported by long-term contracts.

Approximately 86% of the generation capacity selling to

third parties is supported by long-term power purchase

or tolling agreements. For the balance of the generation

portfolio, AES limits the risk of variability between power

prices and fuel costs through an active hedging program,

largely matching contract revenues and fuel costs.

In late 2006, AES entered the independent transmission

business through the acquisition of the assets and

development pipeline of Trans-Elect, based in Reston,

Virginia. In February 2007 AES acquired two 230 MW

petroleum coke-fired power plants utilizing circulating

fluidized bed (CFB) technology in Mexico. AES now owns

and operates eight CFB plants. In the 1990s, AES helped

pioneer CFB technology in the U.S.; a cleaner way to burn

coal than conventional means.

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2 6 A E S 2 0 0 6 FA C T B O O K

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Mérida III is a 484 MW CCGT, dual fuel (natural gas and diesel) power generation facility located in Mérida, onMexico’s Yucatan peninsula. The base-loaded plant sellselectricity to the Comisión Federal de Electricidad (CFE)and represents approximately 50% of the total generationof the Yucatan peninsula. As of December 31, 2006, Méridaemployed 34 people.

AES, which owns 55% of the project, together with part-ners Sojitz Corp. (25%) of Japan and Grupo Hermes (20%)of Mexico, won a competitive bid in 1997 to build, own andoperate the facility. Construction began in October 1997and commercial operation began in June 2000.

Mérida consists of two combustion turbines that can burnnatural gas or diesel fuel, two heat recovery steam generatorsand a single steam turbine. Dry low-NOx technology combustors on the turbines and continuous NOx and COmonitoring were installed during construction.

Mérida sells power to CFE under a 25-year PPA thatexpires in June 2025. The contract includes (1) fixed pay-ments for capacity and fixed O&M costs and (2) variablepayments for energy, variable O&M and start-up costs.CFE also provides natural gas and diesel fuel under a 25-yearcontract. Power is primarily generated using natural gas;diesel fuel is used for back-up. Natural gas is delivered tothe plant through a 700 km pipeline from Ciudad Pemexand diesel fuel is delivered to the plant by truck. Fuelcosts are passed through to CFE under the terms of the PPA.

Revenue (In millions)2004 2005 2006

186 226 185

Commencement/Acquisition

2000

Segment

Generation

Country

Mexico

Fuel

Gas/Diesel

AES EquityInterest

55%

MW

484

POWER INDUSTRY SNAPSHOT

Installed capacity: 50 GWPer capita energy consumption: 63.0 million Btus

Capital Mexico CityLargest city Mexico CityPopulation 107.4 million (7/06 est.)GDP $1,134 billion (2006 est.)GDP per capita $10,600 (2006 est.)

Economic drivers Services, crude oil and mining production, manufacturing

Currency Mexican peso (MXN)Sovereign credit Fitch – BBB, Stablerating Moody’s – Baa1, Stable

S&P – BBB, Stable

COUNTRY FACTS

Power industry overview

Generation sources Electricity consumption

growth rate

Macroeconomic trends

Real GDP growth rate Inflation rate Average FX rate

(MXN:USD)

Thermal 76%19%Hydro

3%Nuclear2%Other

2002 0.8%1.4%1.0%

2.6%

17.3%

20034.2%2004

200220032004

3.0%20054.7%2006

0 100 0 18 0 5 0 120 5

2002 5.0%4.5%20034.7%20044.0%20053.6%2006

2002 9.6610.79200311.29200410.90200511.022006


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Termoelectrica del Golfo (TEG) and Termoelectrica del Peñoles (TEP) are adjacent 230 MW

pulverized petroleum-coke-fired power plants utilizing circulating fluidized bed (CFB)

technology and located near Tamuín, Mexico.

The facilities are fully contracted facilities selling power to industrial customers, CEMEX and Peñoles, respectively.

At the time of acquisition, TEG and TEP employed 149 people.

HISTORY AND BUSINESS STRUCTURE

AES acquired the TEG and TEP facilities from a joint venture between Alstom and Exelon in February 2007.

TEG and TEP commenced commercial operation inApril 2004.

PHYSICAL ASSETS

The TEG and TEP plants each consist of two Alstom CFBboilers and one Alstom turbine generator plant. In additionto the inherently low emission properties of CFB equipment,the facilities are equipped with dry electrostatic precipi -tators (ESPs). Ash disposal is handled through on-site

landfills or shipments to CEMEX. An affiliate of CEMEXand an affiliate of Peñoles have an indirect economic interestof 0.9% in TEG and TEP respectively. AES’s net economicinterest in TEG and TEP is 99%.

SALES & OPERATIONS

Electricity SalesTEG supplies power to CEMEX and TEP supplies powerto Peñoles under 20-year Power Supply Agreements (PSAs)that operate similar to tolling agreements and expire in2027. The PSAs include (1) fixed payments for capitalcharges and return on investment, payable in dollars, and(2) operating payments, payable in a mix of dollars andpesos. Availability factors are specified and include provi-sions for scheduled outages. TEG and TEP are responsiblefor providing power purchased from the grid to meet anyavailability shortfalls, and also receive market-price basedbonus payments for availability that exceeds the guaran-tees. The parties have negotiated an agreement whereby

CEMEX and Peñoles will receive the benefit of refinancingthe facilities and AES will receive enhanced bonus pay-ments and benefits for additional power productionexceeding the guaranteed capacity.

Fuel SupplyTEG and TEP secure petroleum coke from CEMEX under a 20-year contract expiring in 2027. CEMEX in turn obtains petroleum coke from two PEMEX refineriesunder back-to-back contracts. The petroleum coke is provided by the customers and is transported by rail fromthe PEMEX refineries via the Kansas City Southern deMexico, S.A. de C.V.

REGULATIONS AND MARKETS

TEG and TEP operate under a license granted by theComisión Reguladora de Energía (CRE) which authorizesthe provision of power from private generators accordingto the Mexican law governing self supply. Under Mexican law,end use customers may self supply power from affiliatedcompanies even if they own only a minor share of the entitythat supplies the electricity. This law allows companies toaccess pricing based on individual project economics ratherthan the regulated tariffs, offering significant potentialcost savings.

The agreements are not subject to market pricing for their out-put, but are subject to margin risk on actual vs. guaranteed heatrates and limestone use. AES is exposed to wholesale marginalcost prices to the extent that plant availability does not meetguarantees, and benefits by a corresponding amount forperformance better than the guaranteed performance.Similarly, AES benefits from the wholesale price margin ver-sus petr0leum coke costs for any sales greater than the guaran-teed output. The Comisión Federal de Electrici dad (CFE) regulates wholesale tariffs, which are largely set by the marginal production cost of oil and gas fired generation.

2 8 A E S 2 0 0 6 FA C T B O O K

The Federal Energy Regulatory Commission (FERC) hasratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electricenergy under the Federal Power Act (FPA). Each of the50 states regulates retail electricity markets and distribution.

The FERC also has primary jurisdiction over wholesaleelectricity markets and transmission services. Since 1986,the FERC has approved market based rate authority formany providers of wholesale generation, and the mix ofmarket players has shifted toward non-utility entities,referred to as Independent Power Producers (IPPs) orElectric Wholesale Generators (EWGs), whose rates arenegotiated rather than based on costs.

On August 8, 2005, the President signed into law theEnergy Policy Act of 2005 (EPAct 2005). The law repealedthe Public Utility Holding Company Act (PUHCA of 1935)and replaced it with the Public Utility Holding CompanyAct of 2005 (PUHCA of 2005), which became effective on February 8, 2006. The repeal removed utility holdingcompanies from the jurisdiction of the SEC and greatlyreduced the financial and governance restrictions imposedon utility holding companies. The PUHCA of 2005 doesnot restrict mergers and acquisitions of non-contiguousutilities as did the previous law. AES has been granted awaiver from the reporting requirements.

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Capital Washington, DCLargest city New YorkPopulation 298.4 million (7/06 est.)GDP $12,980 billion (2006 est.)GDP per capita $43,500 (2006 est.)

Economic drivers Services (distributive trades, real estate, transport,finance, business services); industry (motor vehicles, telecommunications, IT, chemicals)

Currency US dollar (USD)Sovereign credit Fitch – AAA, Stablerating Moody’s – Aaa, Stable

S&P – AAA, Stable

COUNTRY FACTS



growth rate



(N/A:USD)

ThermalHydroNuclearOther

200220032004

200220032004

20052006

0 100 0 3 0 4 0 350 4

20022003200420052006

20022003200420052006

79%8%

11%2%

2.5%0.7%2.5%

1.6% 3.9%3.2%

3.3%

2.3%

2.7%3.4%

3.2%

00

00

0

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Under the EPAct 2005, the FERC has increased authorityto review mergers and acquisitions, including acquisitionsof foreign utility companies. However, the FERC has issuedregulations that give a holding company that owns a trans-mitting utility or an electric utility company and has captiveU.S. customers (such as AES) blanket authority to acquire aforeign utility company upon making a notice filing con-taining specific certifications with respect to the protec-tion of such customers from the effects of the acquisition.

The EPAct 2005 also provides the FERC with new authorityto certify an Electric Reliability Organization (ERO) thatwill set mandatory reliability standards for the U.S. grid.The North American Electric Reliability Council (NERC)was certified as the ERO and has enforcement authority.The FERC approved an initial set of NERC reliability standardsthat consist of existing operating and planning standards, withan effective date of June 18, 2007. NERC will continue to issueadditional reliability standards. Although NERC has not historically had authority to mandate compliance withthese standards, utilities generally choose to voluntarilycomply with the standards. The new legislation gives NERCthe ability to make standards mandatory and grants themthe authority to enforce these standards through the issuanceof financial penalties. AES has submitted self certificationsthat we are in compliance with the required standards.

Finally, the EPAct 2005 amends the Public Utility RegulatoryPolicies Act of 1978 (PURPA) and instructs the FERC topromulgate regulations to implement the amendments.Pursuant to this directive, the FERC has issued a final rulethat: (i) prescribes new more restrictive criteria that new cogeneration facilities must meet in order to be designatedas qualifying facilities (QFs) under PURPA; (ii) removesthe restrictions on ownership of QFs by an entity that isprimarily engaged in the generation or sale of electricpower; and (iii) for new QFs eliminates certain regulatoryexemptions that QFs previously received. The FERC hasalso issued a final rule that for new power sales contractswould effectively remove the requirement that utilitiespurchase energy and capacity produced by QFs if the utilities(i) are located within the control areas of the MidwestIndependent Transmission System Operator, Inc., PJMInterconnection, L.L.C., ISO New England, Inc. or theNew York Independent System Operators or (ii) otherwisemeet certain criteria relating to market access for QFs. We believe that the repeal of the mandatory purchaserequirement will not have an immediate effect on our businesses.

3 0 A E S 2 0 0 6 FA C T B O O K

IPL is subject to regulation by the FERC and the IndianaUtility Regulatory Commission (IURC). The IURC setsIPL’s retail rates; approves any proposal to issue eitherequity or debt instruments; sets the rules and regulationsthat govern relations between IPL and its customers; prescribes the manner and form of IPL’s accounting records,including the fixing of its depreciation rates; approves any sale, assignment, transfer or lease of IPL’s system; andestablishes assigned service areas, within the boundaries ofwhich, IPL is authorized to furnish all retail electric service.

IPL’s tariffed rates for electric service to retail customers(basic rates and charges) are set and approved by the IURC after public hearings. Such proceedings, which haveoccurred at irregular intervals, involve IPL, the staff of theIURC, the Indiana Office of Utility Consumer Counselor(OUCC), and other interested consumer groups and customers. Pursuant to statute, the IURC is to conduct aperiodic review of the basic rates and charges of all utilitiesat least once every four years. In Indiana, basic rates andcharges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. Once set, the basic rates and charges authorizeddo not assure the realization of a fair return on the fairvalue of property. Numerous factors including, but not limited to, weather, inflation, customer growth and usage,the level of actual operating and maintenance expenditures,capital expenditures, including those required by environ-mental regulations, fuel costs, generating unit availabilityand purchased power costs and availability can affect thereturn realized. Substantially all IPL customers are servedpursuant to retail tariffs that provide for the monthlybilling or crediting to customers of increases or decreases,respectively, in the actual costs of fuel consumed from estimated fuel costs embedded in basic rates, subject tocertain restrictions on the level of operating incomedescribed below. In addition, IPL’s rate authority providesfor a return, between formal rate proceedings, on IPL’sinvestment and recovery of the depreciation and operationand maintenance expenses associated with qualifyingexpenditures made to comply with certain federal air regulations. IPL’s tariff rates for electric service to retailcustomers have been in effect at the current level sinceJuly 1996.

IPL may apply to the IURC for a change in its fuel chargeevery three months to recover its estimated fuel costs,including the fuel portion of purchased power costs, whichmay be above or below the levels included in IPL’s basicrates and charges. IPL must present evidence in each fueladjustment charge (FAC) proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power, or both, so as to provide electricity to itsretail customers at the lower fuel cost reasonably possible.

IPL must meet operating expense and income test require-ments as a condition for approval of requested changes in fuel adjustment charges. Customer refunds may result,among other reasons, if IPL’s rolling 12-month operatingincome, determined at quarterly measurement dates,exceeds its authorized annual jurisdictional net operatingincome and there are not sufficient applicable cumulativenet operating income deficiencies against which the excessrolling twelve month jurisdictional net operating incomecan be offset. In such a circumstance, the required customerrefund for the quarterly remeasurement period is calculatedto be the lesser of one-fourth of the excess annual jurisdic-tional net operating income, grossed up for federal and statetaxes, or one-fourth of the cumulative net operatingincome deficiencies and excess for the applicable periodgrossed up for federal and state taxes.

IPL’s authorized annual jurisdictional net operating income,for purposes of quarterly operating income tests, is $163 mil-lion, as established in IPL’s last base rate case, plus additionalreturns for authorized environmental compliance cost recoveryof approximately $17 million as of December 31, 2006. As ofIPL’s quarterly measurement date on October 31, 2006, IPL’srolling annual jurisdictional retail electric net operatingincome was less than the authorized annual jurisdictionalnet operating income by $27.5 million. Because IPL has acumulative net operating income deficiency, IPL has notbeen required to make customer refunds when its rollingannual jurisdictional retail electric operating income has beengreater than the authorized annual jurisdictional net operating income. Because of the deficiency it may be possiblefor IPL to earn above the authorized annual electric juris-dictional retail net operating income without being requiredto make customer refunds.

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IPALCO Enterprises, Inc. (IPALCO) is a holding company whose principal subsidiary is

Indianapolis Power & Light (IPL), a regulated utility incorporated in Indiana in 1926.

IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to more than 468,000 retail

customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL has an exclusive right to

provide retail electric service to those customers. IPL’s service territory is approximately 1,360 square km.

OVERVIEW

IPL owns and operates four generating stations with totalgross capacity of 3,599 MW. Historically, approximately99% of the total electricity produced by IPL is generatedfrom coal with the remainder from natural gas and fuel oil.

IPL is a balanced utility, with slightly more generation thanconsumption: in 2006, its net electric generation capabilityin winter was 3,400 MW with peak winter demand of

2,805 MW and net summer capability of 3,282 MW withpeak summer demand of 3,118 MW. Similarly, in 2006, IPLgenerated 16,471 GWh, purchased 293 GWh, and sold16,287 GWh to its retail and wholesale customers. Theremaining 477 GWh are primarily attributed to line losses.

As of December 31, 2006, IPL had 1,471 employees ofwhom 1,427 were full time.


AES acquired IPALCO in a stock-for-stock transaction inMarch 2001 for an aggregate purchase price of $2.15 billion

and $890 million in assumed debt and preferred stock.AES owns 100% of IPALCO.

DESCRIPTION OF PHYSICAL ASSETS

Petersburg is a seven unit plant located in Petersburg,Indiana with gross capacity of 1,897 MW. Unit 1 (255 MW)is a pulverized coal steam turbine with a tangential firedboiler, reheat turbine, and hydrogen cooled generator.Unit 2 (470 MW), Unit 3 (580 MW), and Unit 4 (584 MW)consist of pulverized coal steam turbines with tangentialfired boilers, reheat turbines, and hydrogen cooled withstator cooling water generators. Petersburg also includesthree diesel generators (8 MW). Environmental controltechnologies include electrostatic precipitators (Units 1–4),flue gas desulfurization (Units 1–4), SCR (Units 2 and 3),and low NOx burners (Unit 4).

Harding Street is a 12 unit plant located in Indianapolis,Indiana with gross capacity of 1,238 MW. Units 3 (42 MW)and 4 (42 MW) consist of oil-fired steam turbines with tangential fired boilers, non-reheat turbines, and hydrogencooled generators. Units 5 (114 MW) and 6 (114 MW) arepulverized coal steam turbines with tangential fired boilers,reheat turbines, and hydrogen cooled generators. Unit 7(463 MW) is a pulverized coal steam turbine with tangen-tial fired boilers, reheat turbines, hydrogen cooled with a

stator cooling water generator. Harding Street also includesone 3 MW diesel generator and six fuel oil/natural gas firedsimple cycle units (ranging from 25 to 183 MW) with turbinesand air or hydrogen cooled generators. Steam units 5 and 6have electrostatic precipitators and SNCR environmentaltechnologies; gas turbine units 4 and 5 have water injectionfor NOx control, and unit 7 has an electrostatic precipitatorand an SCR.

Eagle Valley is a seven unit plant located in Martinsville,Indiana with total gross capacity of 364 MW. Units 1 (42 MW)and 2 (42 MW) consist of oil-fired steam turbines with tangential fired boilers, non-reheat turbines, and hydrogencooled generators. Units 3 (46 MW), 4 (60 MW), and 5(66 MW) are pulverized coal steam turbines with tangentialfired boilers, non-reheat turbines, and hydrogen cooled generators. Unit 6 (105 MW) is a pulverized coal steam turbine with a tangential fired boiler, reheat turbine, andhydrogen cooled generator. Eagle Valley has one diesel generator (3 MW). Environmental control technologiesinclude electrostatic precipitators (Units 3–6), low NOxburners (Units 4–6) and neural network controls (Unit 6).

Revenue (In millions) 2004 2005 2006885 951 1,032

3 2 A E S 2 0 0 6 FA C T B O O K

SALES & OPERATIONS

Electricity SalesIPL’s service area is predominantly metropolitan includingcustomers in the city of Indianapolis and neighboring areaswithin the state of Indiana, the most distant point beingabout 65 km from Indianapolis. Total revenues in 2006consisted of 39% residential, 14% commercial, 38% industrial,6% wholesale, and 3% other, with the largest customeraccounting for less than 2% of the total. During the past10 years, IPL’s retail electricity sales have grown at a com-pound annual rate of 1.0%.

Fuel SupplyIn 2006, over 99% of the total electricity produced by IPLwas generated from coal. Natural gas and fuel oil combinedto provide the remaining generation.

As of December 31, 2006, IPL’s existing coal contracts pro-vided for approximately 90% of its projected requirementsin 2007 and approximately 85% through 2009. The long-term coal agreements are with four suppliers. Substantiallyall of the coal is currently mined in the state of Indiana.Approximately 61% of IPL’s coal is from one supplier, withwhom IPL has entered into three long-term contracts forthe provision of coal from three separate mines. IPL nor-mally carries fuel oil and a 30–60 day system supply of coal.Coal is shipped primarily by rail under regulated tariffs.

IPL’s coal contracts limit exposure to coal commodity pricerisk. IPL’s exposure to fluctuations in the price of coal andpurchased power are also limited because Indiana UtilityRegulatory Commission (IURC) regulations generally provide for the recovery of fuel and purchased power coststo meet jurisdictional retail load above or below the levelsincluded in IPL’s rate schedules. This recovery is accomplishedthrough a fuel cost adjustment filing with the IURC.

SO2 AllowancesIn 2006 IPL moved from an SO2 allowance long positionto a short position, having utilized its excess allowancesresulting from early installation of pollution control equip-ment. During 2006, IPL purchased 20,100 SO2 allowancesat a total cost of $16.3 million. On June 24, 2006, IPLenhanced existing clean coal technology, which is helpingto reduce SO2 emissions and the need for future allowancepurchases. In addition, IPL expects to place another cleancoal technology project in service in late 2007 to furtherreduce emissions and essentially meet its SO2 reductionrequirements under both the Clean Air Act and the first

phase of the Clean Air Interstate Rule and Clean AirMercury Rule of 2005.

Energy SupplyIn 2006, IPL self-generated more than 98% of the elec -tricity it sold. In April 2005, IPL began participation in the restructured wholesale energy market operated by theMidwest ISO (MISO). In the restructured market, IPLoffers its generation and bids its demand into the marketon an hourly basis. The MISO settles these hourly offersand bids based on locational marginal prices, pricing forenergy at a given location based on a market clearing pricethat takes into account physical limitations, generation anddemand throughout the MISO region. The MISO evaluatesthe market participants’ energy offers and demand bids to dispatch the most economic resources to meet loadrequirements reliably and efficiently in the entire MISOsystem on a five-minute basis. Market participants are ableto hedge their exposure to congestion charges, which resultfrom constraints on the transmission system, with certainFinancial Transmission Rights (FTRs). Participants areallocated FTRs each year and are permitted to purchaseadditional FTRs.

On December 22, 2006, IPL tendered its Notice ofWithdrawal from the MISO pursuant to the Midwest ISOTransmission Owner’s Agreement. In doing so, IPL pre-served its right to withdraw from the MISO (subject toFERC and IURC approval) at some date no earlier thanJanuary 1, 2008. IPL has made no decision as to whether it will seek withdrawal from the MISO. IPL will continueto assess the relative costs and benefits of being a MISOmember, as well as actively advocate for its positionsthrough the existing MISO stakeholder process and in filings at the FERC.

IPL is generally allowed to recover, through its fuel adjust-ment charge, the fuel portion of purchased power costsincurred to meet jurisdictional retail load. Purchasedpower costs below an established benchmark are presumedto be recoverable energy costs.

Other Commercial AgreementsIPL has long-standing transmission-related interconnectionagreements with Indiana & Michigan Electric Company,PSI Energy, Inc. CINERGY Services, Inc., SouthernIndiana Gas and Electric Company, and Hoosier EnergyRural Electric Cooperative, Inc.

Georgetown is a 100 MW gas-fired simple cycle plantlocated in Indianapolis, Indiana. It consists of a single

turbine, an air cooled generator, and dry low NOx emissioncontrol technology.

IPA

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Placerita is a 120 MW gas-fired combined cycle power gen-eration plant located 40 km north of Los Angeles,California. Placerita provides primarily peak power toSouthern California Edison (SCE). As of December 31,2006, Placerita employed 10 people.

AES developed and owns 100% of Placerita. Constructionbegan in February 1987 and commercial operation com-menced in February 1989. Placerita utilizes two combustionturbines with 48 MW generator sets each and one steamturbine with a 24 MW generator set. Other major equip-ment includes a pass steam condenser, two heat recoverysteam generators with selective catalyst reduction systems,a three cell cooling tower and a water treatment plant.

Placerita provides electricity to SCE under a five-year PPA,which expires December 2007. Revenues include a monthlycapacity payment and energy payment. Surplus generationis sold into the California Independent System Operator market based on requirement. SCE is responsible for sup-plying the required amount of natural gas needed for elec-tricity production and compensating for transportationcosts incurred.

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Hemphill is a 16 MW wood-fired biomass facility located in Springfield, New Hampshire. The base-loaded plant sells100% of its output to Public Service of New Hampshire(PSNH), a wholly owned subsidiary of Northeast Utilities,under a rate order that ended October 26, 2006. Hemphillis petitioning the New Hampshire Public UtilitiesCommission (NHPUC) to get an additional year added tothe rate order. Until a ruling is issued, PSNH is payingHemphill based on the ISONE real time hourly rates. Hemphillemployed 23 people as of December 31, 2006.

Hemphill began commercial operation in October 1987.AES acquired its 67% stake in Hemphill from ThermoElectron as part of the asset purchase of Thermo Ecotek in June 2001. The remaining 33% is held by Messer-HillAssociates, a group of local investors. The project is structuredas a leveraged lease. In the event the NHPUC denies

Hemphill’s petition to extend the rate order an additionalyear, the bank has the right to terminate the lease with 30 days’ notice. Hemphill is currently reflected in discontinued operations.

The facility burns wood chips utilizing a 21 MVA air-cooledsteam turbine/generator set and a stoker grate boiler with adry electrostatic precipitator for emissions control. Hemphillsells 13.8 MW to PSNH under a 20-year rate order whichbegan in October 1986. For all electricity delivered up tothe contract capacity, PSNH pays Hemphill a fixed on-peakand off-peak price per MWh. Any excess delivered above13.8 MW is sold at market rates. Hemphill utilizes a fuelmanager, MSI Energy, LLC, to procure all the fuel for theplant. MSI procures chipped wood or logs from over50 independent loggers within an 80 km radius. Hemphillpays the spot price for all fuel purchased.


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AES EquityInterest

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Southland consists of three gas-fired generation plants with a total capacity of 4,327 MW

located in Southern California along the Pacific Coast.

The facilities are Alamitos (2,047 MW), Huntington Beach (904 MW), and Redondo Beach (1,376 MW). Southland

accounts for approximately 10% of the state’s installed capacity and about 25% of the installed capacity in

Southern California. It sells electricity to the Williams Power Company (Williams)* and Southern California Edison

(SCE) under tolling agreements. As of December 31, 2006, Southland employed 193 people.


AES owns 100% of Alamitos, Huntington Beach, andRedondo Beach and all were acquired from SouthernCalifornia Edison in May 1998. Plant commercial operationcommenced between 1956 and 1966. AES has invested inreliability and environmental upgrades since the acquisition.

The three plants operate mostly inde pendently of eachother, with the exception of some shared services forinformation technology, regulatory and environmentalcompliance, safety, finance and corporate reporting, andbilling and settlements issues.

PHYSICAL ASSETS

Alamitos is a 2,047 MW gas-fired plant located in LongBeach, California and has been in service since 1956.Units 1 and 2 consist of boilers with turbine/generator sets.Both units began commercial operation in 1956. Units 3and 4 consist of boilers with turbine/generator sets. Unit 3went into commercial operation in 1963 and Unit 4 wentinto commercial operation in 1964. SCR NOx controlequipment was installed on all of these units in 2001. Units5 and 6 consist of boilers with turbine/generator sets. Bothunits went into commercial operation in 1966 and had SCRNOx control equipment installed in 1995.

Huntington Beach is a 904 MW gas-fired plant located in Huntington Beach, California. Units 1 and 2 consist of

cross-compound, conventional steam turbines and drum-type boilers. Units 3 and 4 utilize cross-compound, conventional steam turbines and subcritical, once-throughboilers. Units 3 and 4 were refurbished in 2003.

Redondo Beach is a 1,376 MW gas-fired plant located in Redondo Beach, California. Units 5 and 6 consist ofdrum type boilers and steam turbines and began commercialoperation in 1954. Units 7 and 8 consist of super-criticalboilers and steam turbines and began commercial operationin 1966. All of the units have been retrofitted with SCRsfor NOx control.

SALES & OPERATIONS

Electricity SalesSouthland primarily sells capacity and provides fuel conversion services under a 15-year Capacity Sale & TollingAgreement to Williams,* whereby Williams controls unitdispatch and provides the natural gas to fuel the plants. Thecontract began in 1998 and expires in 2013, but may beextended for an additional five-year term at the option ofeither Williams or AES. All of the Southland units with theexception of Huntington Beach Units 3 and 4 are contractedto Williams.

Revenues consist of a capacity payment based on plantavailability and an energy payment based on production.Additionally, a summer on-peak bonus plan is in effect.Williams Holdings of Delaware is a corporate guarantor of the contract; its guarantor obligations are capped at$1.2 billion with provisions to be reduced over the term of the financing.

Huntington Beach Units 3 and 4 are contracted to SCEthrough a tolling agreement. Similar to the Williams

Revenue (In millions) 2004 2005 2006194 181 192

* In May 2007, Williams announced that it has agreed to sell substantially all of its power assets, including the tolling agreements for Southland, Red Oak and Ironwoodto Bear Energy LP. Our businesses have typical counterparty rights for tolling agreements with respect to sales, the details of which are subject to confidentialityagreements. We are in discussion with Williams and Bear Energy and are still evaluating the impact of the potential sale on AES.


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Southland is not subject to market pricing for its output. As Exempt Wholesale Generators, Southland assets areregulated by the FERC. All three plants are connected toSouthern California Edison substations, which in turn areconnected to the California Independent System Operator(CAISO) grid.

CAISO operations cover a population of more than 30 millionwith a peak demand of 54,000 MW, 41,000 km of trans-mission lines and over 800 generating resources totalingmore than 54,000 MW. CAISO operates the transmission gridin California and operates a real-time balancing energy market and a day-ahead ancillary service market. Unlike themarkets in the Eastern U.S., CAISO does not operate a day-ahead energy market, does not use a centralized commitment program and does not have a capacity market.However, CAISO does conduct a daily and hourly ancillaryservices market which includes regulation, spin, non-spinand supplemental energy products. Generators and load-serving entities must deal with approved SchedulingCoordinators who submit balanced schedules to CAISO a day ahead of the dispatch day. CAISO uses zonal not

nodal pricing, and congestion costs within a zone are collectedfrom all loads in the zone. CAISO is a single state ISO and works closely with the California Public UtilitiesCommission (CPUC) and the Governor’s Office. CAISO is in the process of changing the market design to a modelthat would resemble the markets in the Eastern U.S.However, this design will not be in place before 2008. Marketpower concerns have led to the imposition of a $400/MWhenergy bid cap and the implementation of an AutomatedMitigation Procedure (AMP) that can mitigate a generatoroffer before setting the clearing price. The AMP is similarto the procedure used in the NYISO but with more restrictive triggers and thresholds.

During the 2000–2001 energy crisis, California experiencedhigh prices, which instigated changes in the original marketdesign. California lawmakers, regulators and market participants have worked together in an effort to enhancethe market rules which culminated in FERC’s approval ofthe Market Redesign Technology Upgrade (MRTU) design elements in 2006. CAISO plans to complete the MRTU project by early 2008.

contract, SCE controls unit dispatch and provides the gas.Huntington Beach receives revenue based on unit availabilityand the amount of energy produced. The current contractexpires at the end of 2009.

Fuel SupplyFor the units operating under the Williams Agreement, the natural gas is supplied by Williams. Natural gas forHuntington Beach Units 3 and 4 is supplied by SCE.Williams or SCE bears responsibility for both the quantity

and quality of gas delivered. Both Williams and SCE havefirm supply contracts with Southern California Gas Company,which delivers the gas through a distribution pipeline thatit owns and operates. The plants are required to convertthe gas to electricity at predetermined efficiencies, meas-ured as a heat rate on each unit. If a station’s efficiency islower than the contract, Southland must pay for the addi-tional gas used at market rates. Conversely, if the station’sefficiency is better than the contract, Southland is reim-bursed for the fuel savings at market rates.

3 6 A E S 2 0 0 6 FA C T B O O K

PHYSICAL ASSETS

Thames utilizes a turbine generator and two CFB boilers.It controls NOx and SOx emissions with its CFB boilertechnology. The addition of limestone into the boilersreduces SO2 emissions, while low operating temperatures

and staged combustion control NOx. The boilers use aback end baghouse to control particulate emissions fromthe facility. All environmental controls were installed when the facility was constructed.

SALES & OPERATIONS

Electricity SalesThames sells power to CL&P under a 25-year contract thatexpires March 2015. In 2001, Thames received a partialprepayment for future deliveries of on-peak and off-peakelectricity. This partial prepayment is amortized into revenuesas the electricity is delivered through the end of the originalPPA. There are no contract renewal provisions under theterms of the PPA. Power in excess of 181 MW is sold toCL&P at prevailing spot prices.

Steam SalesIn order to maintain its cogeneration QF status, Thamessells steam to Smurfit under a 50-year contract that providesfor five-year automatic renewal periods, after the initial

15 years of operation, at Smurfit’s option. The first 5-yearrenewal was exercised in 2005. The payment is based on thevolume of steam sold and is subject to an inflation adjustment.

Fuel SupplyEffective in 2007, Thames sources its coal under a two-yearagreement with Alpha Coal Sales. All coal currently comesfrom the Brooks Run Mine located in West Virginia.Thames has 10-year inflation-indexed agreements expiring in March 2015 for (1) coal rail transportation with CSX,(2) ash removal with Headwaters Resources and (3) limestonebarge transportation with Moran Towing.

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Thames is a 208 MW coal-fired cogeneration plant utilizing circulating fluidized bed (CFB)

technology, located in Montville, Connecticut.

The base-loaded plant is a Qualifying Facility (QF) under PURPA. Thames supplies electricity to the Connecticut

Light and Power Company (CL&P), a subsidiary of Northeast Utilities, and steam to the adjacent Smurfit Stone

Container Corporation (Smurfit). As of December 31, 2006, Thames employed 57 people.


AES developed and owns 100% of Thames. Construction began in January 1987 and commercial operation commenced in March 1990.


Thames is not currently subject to market pricing for itsoutput. Thames operates within the footprint of NortheastIndependent System Operator (ISO-NE), which operatesthe transmission grid and wholesale power markets for theNortheast region of the U.S. ISO-NE is under contract asan ISO with the members of the New England Power Pool

(NEPOOL) to operate the transmission grid and administerthe wholesale energy markets covering Connecticut,Maine, Massachusetts, New Hampshire, Rhode Island andVermont. NEPOOL is regulated as an electric utility by theFERC and has an Open Access Transmission Tariff (OATT)on file that incorporates rates and conditions.



AES Hawaii is a 203 MW coal-fired cogeneration plant utilizing circulating fluidized bed (CFB)

technology and located in Kapolei, Hawaii on the island of Oahu.

The base-loaded plant is a Qualifying Facility (QF) under PURPA and is Oahu’s single largest generator, providing approxi-

mately 20% of the island’s electrical energy demand. AES Hawaii sells power to the Hawaiian Electric Company

(HECO) and steam to Chevron USA Inc. (Chevron). As of December 31, 2006, AES Hawaii employed 54 people.


AES developed and owns 100% of AES Hawaii. Construction began in May 1990 and commercial operation began inSeptember 1992.

PHYSICAL ASSETS

AES Hawaii utilizes a turbine generator and two CFB boilers.The boilers use limestone injection for SO2 control, NH3injection for NOx control, and fabric filter bag houses forparticulate control. AES also owns and operates a

continuous ship unloader at the Barbers Point harbor. Thisseparate business, called AES Kalaeloa Venture, unloads thecoal purchased and used by the plant, and also loads cementbarges and unloads sand ships for other local customers.

SALES & OPERATIONS

Electricity SalesAES Hawaii sells electricity to HECO under a 30-year PPA,which expires in October 2022. Approximately 97% of theplant’s total capacity is committed under the PPA. AESHawaii is essentially a base-load facility, although HECOdoes have the ability to dispatch the plant from 63 MW upto 180 MW. Under the terms of the PPA, AES Hawaii receives(1) a capacity payment to cover capital costs and provide areturn on equity, (2) a fixed operation and maintenance(O&M) payment, (3) a variable O&M payment, (4) a fuel payment based on the theoretical volume of fuel consumedfor the electricity actually generated, and (5) an availabilitybonus if the average availability for the current and previouscontract years exceeds 91%. AES Hawaii has earned thisbonus every year since commercial operation began.

Steam SalesAES Hawaii sells steam to the adjacent Chevron refineryunder a 20-year steam sale agreement that expires inSeptember 2012. Under the agreement, the term automati-cally extends for three five-year periods, unless Chevrongives notice of termination one year before the scheduled expiration date.

Other Commercial AgreementsAES Hawaii currently acquires all of its limestone fromSphere LLC. AES Hawaii and PVT Land Company areparties to an ash utilization and services agreement forremoval of conditioned ash from the facility. This agreementexpires in May 2009. AES Hawaii also has an ash utilizationand services agreement with Hawaiian Cement, whichexpires in August 2013, to take approximately 6,000 tons of fly ash per year for use in concrete production.

Fuel SupplyAES Hawaii has a fuel supply agreement to purchaseapproximately 685,000 tons of coal per year from PT KaltimPrima Coal and Sprague Energy Corp. The contract expiresin September 2007. The coal is mined in Indonesia anddelivered by ship to the Barbers Point/Kalaeloa Harbor.

AES Hawaii, Inc. has entered into a three year agreementwith Constellation Coal to supply 500,000 metric tons(70% of coal needs) of bituminous coal from Indonesia,Australia and Canada effective October 2007, expiring inSeptember 2010. AES Hawaii will purchase from the spotmarket or short term contracts for the remaining200,000 metric tons. AES Hawaii has also contracted withConstellation Coal to provide 100% of the freight for thesame period.


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Warrior Run is a 205 MW coal-fired cogeneration plant utilizing circulating fluidized bed

(CFB) technology and located in Cumberland, Maryland.

The base-loaded plant is a Qualifying Facility (QF) under PURPA. Warrior Run supplies electricity to Potomac Edison (PE),

a subsidiary of Allegheny Power, and liquid CO2 to BOC Gases. As of December 31, 2005, Warrior Run employed 65 people.


PHYSICAL ASSETS

Warrior Run utilizes a single turbine generator and a singleCombustion Engineering Atmospheric CFB boiler. ForNOx control, the plant uses a selective non-catalytic reduction (SNCR) system which enables the plant toreduce emissions during the ozone season. Pulverized dry

limestone is directly injected into the boiler for SO2and mercury absorption and a fabric filter baghouse is utilized for particulate control. Warrior Run also includes a wastewater treatment facility and a liquid CO2processing plant.

SALES & OPERATIONS

Electricity SalesWarrior Run sells 180 MW of electricity to PE under a30-year PPA that expires in February 2030. The contractprovides for a capacity payment based on availability andan energy payment based on actual energy production. PEmay direct that the facility be operated in either QF controlmode, where Warrior Run directs the amount of energy tobe generated, or dispatch mode, where PE directs the amountof energy generated. To secure AES obligations under thePPA, PE has a mortgage lien on and security interest in allAES assets, revenues, and contract rights in respect of theproject. The contract has no renewal provisions.

Carbon Dioxide SalesWarrior Run uses steam to produce CO2 for sale to BOCGases under a 20-year supply contract, which expires inFebruary 2020. Payments are received monthly based on

tons shipped. The price per ton is based on the market performance of BOC Gases and is set annually in January.The liquid CO2 sold is beverage-grade and is used to produce many popular soft drinks and beer. Approximately4% of the CO2 generated at the plant is captured for sale.

Fuel SupplyWarrior Run has a 20-year fuel supply and ash removal con-tract with Anker Energy, a subsidiary of International CoalGroup (ICG). The contract expires in February 2020, withno renewal provisions. The prices for fuel and ash removal areindexed based on the energy rates provided in the PPA, thushedging Warrior Run against commodity price risk. Ankerobtains Western Maryland coal from local mines to meet itscontract obligations. Coal is shipped in and ash is hauled backto the mines for mine reclamation using independent truckingservices as a part of the Fuel Supply Agreement.


AES developed and owns 100% of Warrior Run. Con struction began in January 1997 and commercial operation commencedin February 2000.


Warrior Run is not subject to market pricing for its out-put. Warrior Run operates within the footprint of the PJM West

territory, which operates the transmission grid and whole-sale power markets for parts of the Middle-Atlantic region.


Ironwood is a 710 MW gas-fired combined cycle powergeneration plant located in Lebanon, Pennsylvania. Thefacility sells its Capacity and Ancillary Services and performsFuel Conversion Services for Williams Power Company Inc.(Williams)* for resale. The facility is utilized in mid-meritmode, primarily in the warmer months of the year, atWilliams’ direction.

AES developed and owns 100% of Ironwood. Constructionbegan in June 1999 and commercial operation commencedin December 2001. As of December 31, 2006, the plantemployed 26 people.

Ironwood utilizes two gas turbines with hydrogen-cooledgenerators, two triple pressure unfired heat recovery steam generators (HRSG), and one multi-cylinder steam

turbine with a hydrogen-cooled generator. Each HRSG has an SCR for NOx control and a CO catalyst for CO reduction.

Ironwood sells all capacity and provides fuel conversionservices to Williams* under a 20-year tolling agreementthat expires in December 2021. Revenues include a fixedcapacity payment with availability penalties, a variable opera-tion and maintenance payment, and a start-up payment.Williams Companies Inc. has guaranteed its subsidiary’sobligations up to 125% of the initial project debt. As part of the agreement, Williams provides all natural gas at nocost to Ironwood through the Texas Eastern TransmissionCorporation TETCO-M3 pipeline located five kilometersfrom Ironwood.

Red Oak is an 832 MW gas-fired combined cycle powergeneration plant located in Sayreville, New Jersey. The facility is an exempt wholesale generator that sells electricityto Williams Power Company Inc. (Williams)* for resale. The facility is utilized in mid-merit mode, primarily in thewarmer months of the year, at Williams’ direction.

AES developed and owns 100% of Red Oak. Constructionbegan in March 2000 and commercial operation commencedin September 2002. As of December 31, 2006, the plantemployed 28 people.

Red Oak utilizes three gas turbines coupled to three generators,three triple pressure heat recovery steam generators (HRSG),

and one steam turbine coupled to a hydrogen-cooled generator. Each HRSG is equipped with an SCR for NOxcontrol and a CO catalyst for CO reduction.

Red Oak sells all capacity and provides fuel conversionservices to Williams* under a 20-year tolling agreementthat expires in September 2022. Revenues include a fixedcapacity payment based on plant availability and an energypayment based on production. Williams Companies Inc.has guaranteed its subsidiary’s obligations up to 125% ofthe initial project debt. As part of the agreement, Williamsprovides all natural gas at no cost to Red Oak through aTransco pipeline located 1.5 miles from Red Oak.


70 69 71


2002

Segment

Generation

Country

USA – NJ

Fuel

Gas

AES EquityInterest

100%

MW

832


52 53 53


2001

Segment

Generation

Country

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Fuel

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AES EquityInterest

100%

MW

710

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* In May 2007, Williams announced that it has agreed to sell substantially all of its power assets to Bear Energy LP. See page 34 for further details.

* In May 2007, Williams announced that it has agreed to sell substantially all of its power assets to Bear Energy LP. See page 34 for further details.

4 0 A E S 2 0 0 6 FA C T B O O K

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AES Eastern Energy (AEE) consists of four coal-fired generation plants with total capacity of

1,268 MW located in upstate New York.

The facilities, Somerset (675 MW), Cayuga (306 MW), Greenidge (161 MW), and Westover (126 MW), sell electricity

into the power pool managed by the New York Independent System Operator (NYISO), mainly at the New York

West and Central Zones. AEE’s operating strategy is to continue to improve availability and lower operating costs

in order to maintain its position as a low cost, reliable, and environmentally sound provider of base load capacity.

Availability at AEE has continued to be high at above 94%. As of December 31, 2006, AEE employed 340 people.


AES owns 100% of Eastern Energy, which was acquiredfrom New York State Electric & Gas in May 1999 as part ofNew York’s deregulation of the electric industry. Owner shipwas assumed for two of the plants, Greenidge and Westover.AES sold the other two plants to an unrelated third party

and simultaneously entered into a leasing arrangement with the unrelated party. The transaction was structured asa leveraged lease. The lease is accounted for as an operatinglease, with lease expense included in cost of goods sold.

PHYSICAL ASSETS

Somerset is a 675 MW coal-fired facility in Barker, New York.Commercial operation began in August 1984. The plant is one of the most efficient of its kind in the U.S. The facilityhas historically been operated in a base-loaded mode. TheSomerset 1 boiler is designed to burn bituminous coal with13,000 Btu/lb, but is capable of burning various types of coaland a 30% blend of petroleum coke. Somerset is equippedwith electrostatic precipitators to remove particulate matterand SCR technology to control NOx emissions. Somersetis also fitted with FGD technology and is among the clean-est coal technology electricity suppliers in New York.

Cayuga is a 306 MW coal-fired facility in Lansing, New York,comprising two units that began commercial operation in 1955 and 1958. Unit 1 has a net generating capacity of152 MW, composed of a steam turbine generator. Steam issupplied from a balanced draft, drum type, pulverized coalsteam generator with reheat steam capability. It has an SCRthat was installed in 2001. Unit 2 has a net generatingcapacity of 154 MW. It utilizes a steam turbine generatorand is supplied steam from the same type of boiler as Unit 1.Cayuga historically has been operated in a base-loadedmode and is capable of burning low, medium and high sulfurcoals. In 1995, Cayuga participated in the Department ofEnergy Clean Coal Technology Program, which providedemissions technology upgrades and facility modernization.Cayuga is also fitted with wet limestone FGD technology.

Both Somerset and Cayuga are among the cleanest coalfacilities in New York.

Greenidge is a 161 MW coal-fired facility in Dresden, New York. It has two units consisting of two pulverizedcoal front-fired boilers, one pulverized coal tangential firedboiler, one non-reheat turbine generator and one reheatturbine generator. Commercial operation for the unitsbegan in 1950 and 1953, respectively. Greenidge’s reheatunit is equipped with an NOx control system consisting of an overfire air system and gas reburn. Construction on a$46 million multi-emissions control technology project forthe 107 MW Unit 4 was completed in July 2007. The proj-ect includes a dry scrubber for SOx and mercury removal aswell as an SCR and SNCR system for NOx removal.

Westover is a 126 MW coal-fired facility located nearBinghamton, New York. Unit 7 generates 42 MW and isprovided steam from two non-reheat boilers. Unit 8 generates84 MW and is provided steam from a reheat boiler. Thereis also an environmental lab located on the site that providesanalytical services to the other AEE plants and a variety ofother AES and non-AES businesses. A $56 million multi-emissions control technology project for Unit 8 is expectedto be completed in the fourth quarter 2008. The projectincludes a dry scrubber and polishing baghouse for SOxreduction and an SCR system for NOx removal.



AES Creative Resources owns a 100% interest in the Hicklingand Jennison coal-fired plants, located in Corning andBainbridge New York, respectively, with combined capacity

of 156 MW. The plants were placed on long-term cold standbyin 2000. The long-term cold standby designation means thatthese plants require more than 14 days to be brought online.

SALES & OPERATIONS

Electricity SalesAEE sells electricity into the power pool managed byNYISO mainly at the New York West and Central Zones.AES Odyssey, a subsidiary of AES, performs power marketingfor the units. AEE manages its commodity pricing anddelivery risks with exchange traded instruments, over-the-counter products, derivatives, and bilateral contracts. ARisk Hedging Policy, managed by an AEE Risk Committee,governs activities and transactions. The associated businessrisks are managed on a portfolio basis and are marked-to-market daily. The hedging operates within establishedauthority levels for volumetric limits, transactable commodi-ties, and term limits. The strategy allows for the maintenanceof varying levels of unhedged capacity as a means to manage operational exposure and to take advantage ofsome upside opportunities. AEE typically hedges 75 to 80%of total capacity rolling forward one to three years.

Fuel SupplyEastern Energy engages in the forward purchase of coal tomatch its exposure to the forward sales of electricity.Transportation of fuel is procured under regulated tariffs

on either of two rail lines, Norfolk Southern and CSX. The plants are located close to the major coal producers in the Pittsburgh Seam and AEE provides an important market for producers of high and medium sulfur coal inPennsylvania and West Virginia.

Greenidge burns mostly low sulfur eastern bituminous coaland is permitted to burn up to 30% western sub-bituminouscoal. It also has a 20% natural gas capability and a 10% biomasscapability on Unit 4. Cayuga and Somerset are equipped withFGD technology, which allows them to burn a wide variety ofcoals, including less expensive medium and high sulfur coals.Somerset is also permitted to burn petroleum coke. Westoverburns mostly low sulfur eastern bituminous coal and is permitted to burn up to 30% western sub-bituminous coal.

Other Commercial AgreementsIn 2006 AES NY Surety, an AES subsidiary, established a$350 million letter-of-credit facility which directly supportsAEE by providing credit support to counterparties as partof the AEE risk management program. This facility expiresin July 2011.


NYISO is a FERC approved ISO and operates the trans-mission grid, the wholesale energy markets, ancillary servicemarket, and capacity market in New York. NYISO is regulated as an electric utility by the FERC and has an OpenAccess Transmission Tariff (OATT) on file that incorporatesrates and conditions for use of the transmission system and a Market Services Tariff that describes the rules andconditions of use for the various markets. NYISO operationscover a population of more than 18 million with a peak demandof 30,900 MW, 18,000 km of transmission lines, and over360 generating resources totaling more than 35,000 MW.

The wholesale power markets are based on a combinationof bilateral contracts, CFDs and NYISO-administeredday-ahead and real-time energy markets. The day-aheadmarket is a financially binding, security-constrained unitcommitment market that includes energy, regulation andoperating reserves. NYISO uses Locational Based Marginal

Pricing (LBMP) calculated at each node to representcongestion on the grid. Generators are paid the LBMP attheir node, while loads pay a zonal price that is the averageof nodes within a zone. Financial transmission rights areavailable as Transmission Congestion Contracts (TCC) andare used to hedge congestion risk in the day-ahead market.NYISO also administers reliability requirements set by the New York State Reliability Council, through the deter -mination of capacity obligations of Load Serving Entities. The market has a $1,000/MWh cap on bids for energy.

NYISO is a non-profit NY corporation governed by aboard of directors with ten members and three commit-tees: the Management Committee, the OperatingCommittee, and the Business Issues Committee. Thesecommittees are composed of representatives from all market participants, including buyers of power, sellers ofpower, consumer groups and transmission owners.

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Shady Point is a 320 MW coal-fired cogeneration plant utilizing circulating fluidized bed

(CFB) technology located in Panama, Oklahoma.

The base-loaded plant is a Qualifying Facility (QF) under PURPA. Shady Point supplies electricity to Oklahoma

Gas & Electric (OG&E) and liquid CO2 to Tyson Foods. As of December 31, 2006, Shady Point employed 87 people.

PHYSICAL ASSETS

Shady Point utilizes four coal-fired CFB boilers and twosteam turbines and generators. It controls NOx and SO2emissions with its CFB boiler technology. The addition oflimestone into the boilers reduces SO2 emissions while low

operating temperatures and staged combustion controlNOx. The boilers use a back end baghouse to control particulate emissions from the facility. All environmentalcontrols were installed when the plant was constructed.

SALES & OPERATIONS

Electricity SalesShady Point sells electricity to OG&E under a 32-year PPAexpiring in 2022. In 2008, OG&E had the right to terminatethe agreement, and it has similar rights in 2013 and 2018. Currently, the PPA has been extended through July 2012.Payments under the PPA consist of a capacity paymentbased on availability and an energy payment composed of avariable fuel cost component, a design heat rate, OG&E’scost of coal, and a variable O&M component. Under thisagreement, exposure to fuel price risk is limited.

Carbon Dioxide SalesIn order to maintain its QF status, approximately 6% of theproject steam generation is used to produce over 200 tons ofliquid food-grade carbon dioxide per day. The carbon dioxide,which is removed from the flue gas stream, is sold to Tyson

Foods under a contract expiring in December 2007. ShadyPoint also has a contract with Continental Carbonic forapproximately 40 tons a day of dry ice pellets which renewsannually with a 2% price increase each year unless writtennotice is given by AES Shady Point.

Fuel SupplyShady Point’s fuel supply consists of 60% Oklahoma coaland 40% Powder River Basin coal. Oklahoma coal is supplied by George Colliers, Inc. (to July 2016) and MarineCoal Sales Company (to December 2007) all within25 miles of the Shady Point plant and all shipments arereceived by truck. The remaining coal is supplied from thePowder River Basin in Wyoming and shipped by rail. ShadyPoint has a transportation agreement with BurlingtonNorthern Railroad for all PRB coal through 2010.


AES developed and owns 100% of Shady Point. Con struction began in September 1988 and commercial operation commenced in January 1991.


Shady Point is not subject to market pricing for its output.There is no wholesale power market in Oklahoma and bilateralcontracts with utilities are recovered through cost of servicefilings with the state commission. OG&E is a member of theSouthwest Power Pool (SPP). The SPP provides independentsecurity coordination and tariff administration, regionalengineering model development, planning and operating

studies, reliability assessment studies, a computer basedtelecommunications network, and operating reserve sharing.SPP is currently implementing regional transaction schedul-ing and market settlement functionality as required by FERCOrder 2000. SPP has been in discussions with severalRegional Transmission Organizations (RTOs) about combin-ing operations but has not reached an agreement at this time.


Beaver Valley is not currently subject to market pricing forits output. Beaver Valley is located within the PJM Inter -connection. Beaver Valley should not be exposed directly to

any regulatory intervention from either the PJM RegionalTransmission Organization or from the state commission.

Beaver Valley is a 125 MW pulverized coal-fired cogeneration plant located in

Monaca, Pennsylvania.

The base-loaded plant is a Qualifying Facility (QF) under PURPA. Beaver Valley supplies electricity to West Penn

Power and steam to two chemical plants owned by BASF and NOVA. As of December 31, 2006, Beaver Valley

employed 61 people.


AES acquired the facility from ARCO Chemical Companyin 1985 through its 80% majority interest in BV Partners, a joint venture partnership with Shepperton LeasingCompany. Beaver Valley was originally built in 1942 and wasconverted into a cogeneration plant after its purchase by

AES. Commercial operation as a cogeneration plant under AES ownership began in July 1987. In November 1999,AES purchased the remaining partnership interest and currently owns 100% of the project.

PHYSICAL ASSETS

Beaver Valley consists of four pulverized coal-fired boilers,one condensing steam turbine generator, and one toppingturbine generator. The plant controls SO2 emissions with

the use of wet scrubber technology and NOx emissionswith the use of low NOx burners, separated overfire air andSNCR technology.

SALES & OPERATIONS

Electricity SalesBeaver Valley sells up to 125 MW of capacity to West PennPower, a subsidiary of Allegheny Power, under a 30-yearElectrical Energy Purchase Agreement (EEPA) that expiresDecember 2016. Under the EEPA, West Penn pays a capacitypayment, which varies over time according to a fixed sched-ule, and a variable payment based on the actual monthly costof production at a reference Allegheny power plant. The cost ofproduction is based on established FERC accounts thatinclude fuel, variable, and fixed costs. The payment BeaverValley receives from West Penn under its EEPA is not tied tothe actual fuel costs incurred by the project. Monthly revenueis based on the monthly aggregate electric output delivered toWest Penn. Beaver Valley is paid solely on its production anddoes not receive an availability payment.

Steam SalesIn order to maintain its QF status, Beaver Valley sells steam to neighboring NOVA and BASF chemical plants.The contracts are long term and supply 100% of the steamrequirements of both facilities. The payment is based onvolume of steam sold and is escalated through the term of the contract.

Fuel SupplyBeaver Valley has a fuel agency agreement concurrent withthe EEPA with Anker Energy Corporation, a subsidiary ofInternational Coal Group. Beaver Valley’s current strategy is to purchase coal under short term contracts, but it expectsto pursue longer term contracts in the future. All coal is cur-rently contracted under one year agreements with Consol,Foundation and local suppliers. Beaver Valley’s coal price riskis partially mitigated by the reference plant pricing structure.



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4 4 A E S 2 0 0 6 FA C T B O O K

PHYSICAL ASSETS

AES Puerto Rico utilizes two steam turbine generators andtwo CFB boilers. It controls NOx and SOx emissions withits CFB technology. It also uses a circulating dry scrubberfor additional SOx removal and urea injection for further

NOx emission reductions. It uses electrostatic precipitatorsfor particulate emissions control. AES Puerto Rico utilizesa zero-discharge water treatment system.

SALES & OPERATIONS

Electricity SalesAES Puerto Rico sells power to PREPA under a 25-yearPPA that expires in November 2027. Revenues include (1) a capacity payment representing capital recovery andreturn on investment, (2) an energy payment consisting of apass through of fuel cost and (3) a fixed and variable operationand maintenance component that escalates with U.S. CPI.

Steam SalesIn order to maintain its QF status, AES Puerto Rico sells up to 400,000 pounds per hour of steam to Chevron Phillips

under a 25-year steam supply agreement that expires inNovember 2027.

Fuel SupplyFuel cost is a pass through under the PPA with performanceguaranteed to a contracted heat rate curve. AES PuertoRico has a supply agreement with Coal Marketing Company(CMC) for coal from the Cerrejón mine in Colombia. Theagreement expires in December 2008. In addition, AESPuerto Rico sources the limestone used in the fluidized bedfrom the Bahamas.

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AES Puerto Rico is a 454 MW coal-fired power generation plant utilizing circulating fluidized

bed (CFB) technology, located in Guayama, Puerto Rico, approximately 55 km south

of San Juan.

The base-loaded plant is a Qualifying Facility (QF) under PURPA. It is the only coal-fired power plant in Puerto Rico

and supplies approximately 15% of the island’s electricity. AES Puerto Rico supplies electricity to the government-

owned Puerto Rico Electric Power Authority (PREPA) and steam to the adjacent Chevron Phillips Puerto Rico Core

refinery. As of December 31, 2006, AES Puerto Rico employed 110 people.


AES developed and currently owns 100% of AES Puerto Rico. Construction began in November 1999 and commercialoperation commenced in November 2002.



AES Puerto Rico is not subject to market pricing for its output. AES Puerto Rico operates within the footprint ofPREPA’s transmission and distribution system which

serves the island exclusively. PREPA is owned by theCommonwealth of Puerto Rico.


The Public Utility Commission of Texas (PUCT) has primaryjurisdiction over activities conducted by the ElectricReliability Council of Texas (ERCOT). ERCOT, a non-profitcorporation regulated by the PUCT, is the organizationentrusted to keep electric power flowing to approximately20 million Texas customers, representing 85% of the state’selectric load and about 75% of the Texas land area. As theIndependent System Operator for its region, ERCOTmanages the scheduling of power on an electric grid consistingof 77,000 MW of generation capacity and 61,000 km oftransmission lines.

Deepwater operates in the ERCOT Houston Zone, one of five wholesale pricing zones. As a competitive marketthat accommodates both bilateral transactions and ancillaryservices, ERCOT manages financial settlements for marketparticipants in Texas’ deregulated wholesale bulk power andretail electric market. Generators in ERCOT are currentlyunable to wheel power outside of Texas. As one of tenregional reliability councils in North America, ERCOTmonitors and enforces industry reliability standards forgrid and utility operations.

PHYSICAL ASSETS

Deepwater utilizes an arch-fired boiler, a single flow, extraction condensing turbine, an air-cooled generator and athree-stage flue gas cleaning system. It also utilizes a low-NOxburner and selective catalyst reduction (SCR) equipment to

reduce total NOx emissions. The installation of the low-NOx burner and SCR equipment was completed in 2007and is expected to reduce total NOx emissions by 96%.

SALES & OPERATIONS

Electricity SalesDeepwater sells 100% of its generation to TXU under acontract that expires December 31, 2008. TXU’s obligationsare secured by a parent guarantee from TXU Corporationfor the benefit of Deepwater. Deepwater’s obligation issecured by a lien on the plant.

Fuel SupplyDeepwater purchases a contractually guaranteed quantityof petroleum coke from TCP Petcoke Corporation under anannually renewable agreement which expires December 31,2007. The petroleum coke is produced at the adjacentLyondell refinery. The petroleum coke price is based on thespot PACE price, which is determined each month based

on petroleum coke contracts from the previous month. Thepetroleum coke is transported by rail using Deepwater railcars on private railroad tracks.

Other Commercial AgreementsDeepwater has a fly ash sales agreement with Stratcor (U.S. Vanadium). The agreement is an evergreen contractthat allows both parties to terminate with six months writtennotice. Deepwater is paid for the fly ash based on its vanadiumcontent; the price paid is a negotiated contract price looselytied to the market price of vanadium. In addition to vanadiumsales, Deepwater sells approximately 90,000 tons of highquality synthetic gypsum to U.S. Gypsum annually, which isused to make wall board.

Deepwater is a 160 MW pulverized petroleum coke-fired power plant located in Pasadena,

Texas near the Houston Ship Channel.

As a base-loaded plant, Deepwater supplies electricity to TXU Portfolio Management Company (TXU) and employed

54 people as of December 31, 2006.


AES developed and owns 100% of Deepwater. Con struc tion began in August 1983 and commercial operation began inJune 1986. Deepwater was AES’s first greenfield power plant.



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HIGHLIGHTS

■ Seven countries: Argentina, Brazil, Chile, Colombia, Dominican Republic, El Salvador and Panama



■ Nine distribution businesses serving more than 8 million customers

■ Three publicly traded companies on local stock exchanges




■ Key drivers: foreign currency exchange rates; regulated tariff adjustments & electricity demand; hydrology andoil /natural gas prices; availability for generation

AES’s Latin American operations span seven countries and include

power generation and distribution businesses. If all of the AES

businesses in Latin America were combined into one, it would be

the second largest privately owned power company in the region.

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4 73 : B U S I N E S S D E S C R I P T I O N S – L AT I N A M E R I C A

AES entered the Latin American market in 1993 with the

acquisition of the CTSN power plant in Argentina. In the

span of a decade, AES has become a leader throughout the

region, powering growth in both urban and rural communities.

We also have deep local roots throughout Latin America.

Eletropaulo in Brazil, the largest distribution company in

the region (in terms of revenue and volume distributed) with

over five million customers, has been serving its customers

for over 100 years.

In Chile, AES is the second largest generator of electric

power. In El Salvador, AES provides electricity to over 80%

of the country, including campesinos and remote villages

that have never had reliable power before. In Argentina,

AES is one of the largest private power generators in the

country and its two distribution businesses in Argentina

serve over 450,000 customers in the province of Buenos

Aires. In the Dominican Republic, AES Andres is the newest

private power generator in the country. The facility is a

319 MW gas-fired plant and LNG regasification terminal.

In Panama, AES will be the largest producer of electricity in

the country, once our new hydroelectric power plant is up

and running, expected in 2010.

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CONTENTS

LATIN AMERICA

ARGENTINA 48

Argentina Regulatory Overview 48

Argentina Utilities 49

Argentina Generation 50

BRAZIL 52

Brazil Regulatory Overview 52

Brazil Business Structure 54

Eletropaulo 55

Sul 56

Tietê 57

Uruguaiana 58

CHILE 59

Chile Regulatory Overview 60

COLOMBIA 59

Colombia Regulatory Overview 61

Gener 62

DOMINICAN REPUBLIC 66

DR Regulatory Overview 66

Dominican Republic Generation 67

EL SALVADOR 69

El Salvador Regulatory Overview 69

El Salvador Distribution 70

PANAMA 71

AES Panama 72

Panama Regulatory Overview 73

4 8 A E S 2 0 0 6 FA C T B O O K

Capital Buenos AiresLargest city Buenos AiresPopulation 39.9 million (7/06 est.)GDP $600 billion (2006 est.)GDP per capita $15,000 (2006 est.)

Economic drivers Natural resources, services, agriculture, industries(food and beverage chemicals, petrochemicals, andmotor vehicles)

Currency Argentine peso (ARS)Sovereign credit Fitch – Brating Moody’s – B3, Positive

S&P – B+, Stable

COUNTRY FACTS



growth rate



(ARS:USD)



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The regulatory entity authorized to manage and operate theArgentine Interconnected System, or the SADI, is CompañiaAdministradora del Mercado Mayorista Eléctrico S.A., orCAMMESA. Sales of electricity may be made on the spotmarket at the marginal cost of energy to satisfy the system’shourly demand, or in the wholesale energy market undernegotiated term contracts. Generators are also remuneratedfor their capacity to generate electricity in excess of supplyagreements or private contracts executed by them.

Distribution companies that operate exclusively with geographic concessions are subject to regulation throughthe rates they charge and must comply with service qualitystandards. Distribution companies may purchase the electricity that they require to satisfy consumers’ demandin either the spot market or through agreements with generating companies.

As the result of a political, social and economic crisis, theArgentine government adopted many new economic measuresin 2002 and 2003. The regulations adopted in the energysector effectively terminated the use of the U.S. dollar asthe functional currency of the Argentine electricity sector.

During 2004, the Energy Secretariat reached agreementswith natural gas and electricity producers to reform theenergy markets. In the electricity sector, the EnergySecretariat passed Resolution 826/2004, inviting genera-tors to partially contribute their existing and future creditsin the Wholesale Electricity Market (WEM) fromJanuary 2004 to December 2006 to fund the developmentand construction of two new power plants to be installedby 2008/2009. In exchange, the Government committedto reform the market regulation to match the pre-crisisrules prevailing before December 2001.

Under the previous regulations, distribution tariffs werebased upon U.S. dollars and adjusted by the U.S. consumerprice index and producer price index. Under regulationsadopted after the crisis, tariffs of all distribution companieswere converted to pesos and were frozen at the peso notionalrate as of December 31, 2001. In October 2003, the ArgentineCongress enacted Law No. 25,790 that established the pro-cedure for renegotiation of the public utilities concessionsand extended the period for that process until December 2007.During such process, AES distribution businesses have obtainedtariff increases and other favorable regulatory changes.


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AES’s two distribution companies in Argentina serve approximately 460,000 customers in the

province of Buenos Aires with 3,201 GWh of electricity sold in 2006.

Both companies hold 95-year concessions to operate as the exclusive electric energy distributor in their service

areas. Empresa Distribuidora La Plata S.A. (EDELAP) serves the districts of La Plata, Ensenada, Berisso, Magdalena,

Punta Indio and Coronel Brandsen. Empresa Distribuidora de Energia Sur (EDES) serves customers in the southern

part of the province. Together, the companies provide service through a network of 12,995 km to total service areas

of 82,059 km2. As of December 31, 2006, the companies employed approximately 754 people.


AES purchased EDES in June 1997 in a 60%/30% partner-ship with PSEG, as part of the privatization of ESEBA. Theremaining 10% of the capital stock was distributed amongthe employees in accordance with a program of shared property set by the province of Buenos Aires. AES boughtout PSEG’s share in 2003, and held a 90% equity interest inEDES as of December 31, 2006. In June 1998, AES acquired

a 90% interest in EDELAP from subsidiaries owned by theHouston and Techint Groups. AES sold a 30% interest toPSEG later that year and subsequently repurchased it in2003. AES now holds a 90% equity interest in EDELAP;the remaining 10% was distributed to employees at the timeof the privatization in accordance with a program of sharedproperty set by the national government.

SALES & OPERATIONS

Electricity SalesThe concession term of EDELAP and EDES is dividedinto nine administrative periods, the first period lasting15 years and subsequent periods lasting 10 years each. The concession agreement establishes an auctioning mechanismwhereby the regulator rebids the rights and obligations ofthe concession at the end of each administrative period.EDELAP is regulated by a federal agency called EnteNacional Regulador de la Electricidad (ENRE). EDES isregulated by a provincial entity called Organismo deControl de Energía Eléctrica de la Provincia de BuenosAires (OCEBA).

The tariffs of these distribution companies have two compo-nents: Pass Through and Distribution Value Added (DVA).The first component allows the pass through to customers ofthe distributor’s cost to acquire electricity on the WholesaleElectric Market (WEM).The second component representsthe distributor’s contribution to the electric energy value

chain. The tariff structure also includes specific taxes to bepaid by final customers in their consumption invoices.

EDELAP’s 2006 GWh sold were divided as follows: 28%residential, 13% commercial, 56% industrial, and 3% other.About 80% of EDELAP’s residential customers are locatedin the urban nucleus of La Plata city, another 15% in thenearby cities of Berisso and Ensenada, and the remainingare in rural areas.

EDES’s 2006 GWh sold were divided as follows: 31% residential, 17% commercial, 31% industrial, and 21%other. EDES’s industrial and urban clients are primarilylocated in Bahia Blanca, while the southern and westernparts of the concession area are more rural.

Energy SupplyEDELAP and EDES purchase electricity in the WholesaleElectric Market.

RECENT EVENTS

In May 2006, AES reached an agreement to sell 100% ofits interest in EDEN, a distribution company serving thenorthern and central areas of the province of Buenos Aires.EDEN has been classified in discontinued operations since

the second quarter of 2006. The approval of the share transfer from governmental authorities was received in May 2007 and the transfer of EDEN shares from AES tothe buyer occurred in June 2007.


5 0 A E S 2 0 0 6 FA C T B O O K

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AES owns four generation companies in Argentina with 2,828 MW installed capacity. AES

operates an additional 45 MW.

Alicura includes a 1,050 MW hydro plant located in the Neuquen province and the 675 MW CTSN plant, which is

located 230 km east of Buenos Aires and can burn coal, natural gas, or fuel oil. Paraná is an 845 MW CCGT plant

located adjacent to CTSN. Rio Juramento & San Juan consists of two groups of plants in the Salta and San Juan

provinces totaling 190 MW, of which 157 MW is hydro and 33 MW is natural gas/diesel. Central Dique is a 68 MW gas

plant located in La Plata in the Buenos Aires province. The companies primarily sell their output into the Argentine

competitive wholesale market. AES’s generation companies employed 306 people as of December 31, 2006.


AES acquired an 88% interest in the CTSN plant from thenational government in May 1993. AES acquired its inter-est in Alicura from Southern Company in August 2000.AES has a concession to operate Alicura until 2023. InApril 2004, AES merged its interests in Alicura and theCTSN plant. AES owns 99% of the continuing company;the other 1% is owned by employees through a participatedproperty program (PPP).

AES acquired its 98% interest in Rio Juramento & SanJuan from the national government in two transactions inNovember 1995 and March 1996; the acquired companieswere then merged in March 2000. The other 2% is ownedby employees through a PPP. AES has 30-year concessions

to operate the companies composing Rio Juramento & San Juan.

Paraná was constructed by AES through a 67%/33% jointventure with PSEG. The plant began commercial operationin November 2001. AES acquired PSEG’s minority interestin 2003 and now owns 100%.

AES also owns a 51% share in Central Dique, a 68 MW gasplant located in La Plata in the Buenos Aires province. Inaddition, Caracoles, a subsidiary of AES, operates and main-tains the 45 MW Quebrada de Ullum hydroelectric plantunder an agreement signed with the government of theSan Juan province in June 2004.

PHYSICAL ASSETS

The Alicura plant consists of four 260 MW turbines,which are supplied by a reservoir on the Limay River. InNovember 2005, an output upgrade was completed, whichresulted in an additional 10 MW of capacity. The earthfilled dam provides a head of 116 meters. The civil worksinclude a spillway with 3,000 m3 per second capacity.

The CTSN plant consists of four turbines of 75 MW each,a 350 MW turbo-generator, and a 25 MW gas turbine. It isthe most flexible plant of the Argentine electrical systemdue to the possibility of burning coal, natural gas, or fueloil, or a combination of these fuels in its boilers. It is theonly coal plant in the country, which implies that it is the first plant that CAMMESA, the system administrator,requires when there is a lack of natural gas in the system.

Paraná has two gas turbines, two heat recovery steam generatorsof 1,200 tons per hour of steam each, and one steam turbine.The plant can use natural gas or gas oil.

Rio Juramento & San Juan consists of four plants: two in the Salta province (Cabra Corral and El Tunal) and two in theSan Juan province (Ullum and Sarmiento). Cabra Corral is a102 MW hydro plant with a 91-meter storage reservoir andtwo-year capacity storage dam. The earth filled dam providesa head of 110 meters powering three 34 MW units. The civilworks include a spillway with 1,500 m3 per second capacity.El Tunal is a 10 MW hydro plant with a storage reservoirand a dam located downstream. The earth and concretedam provides a head of 20 meters powering two 5 MWunits. The civil works include a spillway with 2,000 m3 persecond capacity. Ullum is 45 MW hydro plant with twoapproximately 23 MW units. Sarmiento is a thermal plantwith three 11 MW gas turbines.



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Electricity SalesThe four generation companies primarily sell their outputinto the competitive wholesale market. The wholesale electricity market is managed by CAMMESA, which plansthe operation of the interconnected system to meet theexpected demand with a reserve agreed between the parties(economic load dispatching). The wholesale market isdivided into two segments: a spot and a contract market. Inthe latter case, distributors and large consumers may enterinto supply agreements with producers and brokers, atprices freely settled in the respective contracts. This marketis currently based mainly on short-term agreements of oneyear. In the spot market, the hourly marginal price defines a generator’s selling price and its seasonal average represents the basis for determining the purchasing pricefor distributors.

As of December 31, 2006, Alicura had the following industrial customers in the contract market: AySa S.A., JuanMinetti S.A., LDC Argentina, Petroken and EastmanChemical Argentina S.R.L.

As of December 31, 2006, Rio Juramento & San Juan hadthe following industrial customers in the contract market:Juan Minetti S.A., Sipar Aceros S.A., Prysmian Cables &Systems, and Carraro Argentina S.A.

As of December 31, 2006, Paraná had the following indus-trial customers in the contract market: Loma NegraCIASA and Volkswagen Argentina S.A.

Contract revenues represented approximately 9% of thetotal revenues of the Argentina generation businesses in2006; the remaining revenues consisted of spot market sales.

Water RightsFor the right to access water Alicura pays 13.5% of its revenues as cannon and royalties; Rio Juramento & San Juanpays 14.5% of its revenues.

Fuel SupplyCTSN has short-term coal supply agreements with GLENCORE and buys gas and oil in the spot market. The coal is transported by ship from South Africa. Theprices of the spot purchases and the prices of its contractsreflect market conditions as well as the reference fuel priceused to calculate the energy spot price. Consequently,CTSN has no risk in spot fuel purchases.

Paraná has long-term gas supply agreements with TotalAustral S.A., Panamerican Energy L.L.C., WintershallEnergia S.A. and Rafael Albanesi S.A. and buys diesel in the spot market. Gas and diesel prices are hedged against theenergy spot price due to fuel reference prices that reflectthe market conditions of each fuel.

The Rio Juramento & San Juan thermal plant, Sarmiento,does not have a gas supply agreement due to lower dispatchrequirements; it buys natural gas and diesel in the spot market.

Energy SupplyIf a plant has a contract with a large customer and cannot generate, it must buy energy in the spot market for every hourin which it does not generate, in order to supply the contract.

SALES & OPERATIONS

5 2 A E S 2 0 0 6 FA C T B O O K

Capital BrasíliaLargest city São PauloPopulation 188.1 million (7/06 est.)GDP $1,616 billion (2006 est.)GDP per capita $8,600 (2006 est.)

Economic drivers Services, industrial products and mining, agricultureCurrency Brazilian real (BRL)Sovereign credit Fitch – BB, Stablerating Moody’s – Ba2, Stable

S&P – BB, Positive

COUNTRY FACTS



growth rate



(BRL:USD)



Thermal 14%78%Hydro

2%Nuclear6%Other

2002 1.9%0.6%5.3%

5.4%

4.3%

20034.9%2004

200220032004

2.3%20052.9%2006

0 100 0 6 0 5 0 40 15

2002 8.5%14.7%2003

6.6%20046.9%2005

4.2%2006

2002 2.923.0820032.9320042.4320052.192006

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Under the present regulatory structure, the power industryis regulated by the Federal Government, acting through theMinistry of Mines and Energy (MME) and the NationalElectric Energy Agency (ANEEL), an independent federalregulatory agency.

ANEEL’s main function is to ensure the efficient and economic supply of energy to consumers by monitoringprices and ensuring adherence to market rules by marketparticipants in line with policies dictated by the MME.ANEEL supervises concessions for electricity generation,trans mission, trading and distribution, including theapproval of applications for the setting of tariff rates, andsupervising and auditing the concessionaires.

In order to maintain the economic and financial equilibriumof the concession, utilities are entitled to the followingtypes of tariff adjustments contemplated in the concessioncontracts: annual tariff adjustments, tariff resets, andextraordinary revisions, in the event of significant changesin concessionaires’ cost structure.

The Annual Tariff Adjustment (IRT) primarily adjusts forinflation and for sharing of efficiency gains with consumers.The IRT passes through non-manageable (Part A) costs to the consumers and indexes manageable (Part B) costs toinflation. Examples of Part A costs include charges relatingto the use of transmission and distribution systems andenergy purchase costs. Examples of Part B costs includedepreciation, operations and maintenance expenses, andtaxes on revenues. An “X-Factor” is applied to capture thesharing of efficiency gains, effectively reducing the inflationindex that is applied to Part B costs. The operations andmaintenance costs considered in the tariff are based on theconcept of a Reference Company, not on actual costs. Inmany cases, the Reference Company may not be reflectiveof distribution companies in Brazil and thus true operatingcosts may be underestimated. These costs, which include certain taxes and other issues, are discussed under adminis-trative appeal with ANEEL. In addition, the distributioncompanies are challenging certain methodologies used forthe tariff revision.


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Tariff resets occur every four to five years depending on the specific concession. The revision percentage change is equal to required revenue divided by verified revenue.Required revenue is composed of depreciation (gross assetbase multiplied by depreciation), capital remuneration (netasset base multiplied by pre-tax weighted average cost ofcapital), and Reference Company operations and maintenancecosts. Verified revenues are calculated as energy sold in MWhmultiplied by the tariff.

In December 2003, the Brazilian government enactedProvisional Measures #144 and #145, which set forth thebasic rules that govern a new model for the Brazilian powersector (New Power Sector Model). In March 2004, Law#10848 was enacted, which sets forth the basis of the new regulatory framework and general rules for powercommercialization, regulated by Decree #5163, of July 2004,and other administrative rulings.

The main points of the New Power Sector Model and itsimpact on AES businesses in Brazil are as follows:

• It creates two energy commercialization environments:the regulated contractual environment (ACR), intendedfor the distribution companies, and the free contract envi-ronment (ACL) designed for traders and free consumers.Free customers are required to pay a wheeling fee for theuse of a distribution company’s distribution system.

• As of January 2005, every distribution utility is obligatedto meet 100% of its anticipated energy requirements, subject to the application of penalties. Compliance withsuch obligation requires distribution companies to contractfor energy through: (i) auctions from new (proposed) generation projects; (ii) auctions from existing generationfacilities; and (iii) other sources, including public calls topurchase energy from distributed generation; renewableenergy sources (through public auctions or the BrazilianRenewable Energy Incentive Program – PROINFA); pre-existing purchases made before Law #10848/04; andpurchases from Itaipu.

• Distribution utilities can pass through the amounts contracted, up to 103% of their load. ANEEL adopted anew pass through methodology in the annual tariff adjust-ment; and variations of the energy purchase costs will becontemplated in the tracking account (CVA).

As part of the New Power Sector Model, distribution companies signed Amendments to the Concession Contracts,modifying the methodology of power purchase cost passthrough tariffs (mentioned above) and excluding PIS/COFINS(taxes over revenue) from the tariffs.

In order to optimize the generation of electricity throughBrazil’s nationwide system, generation plants are allocateda generating capacity referred to as “assured energy.”Together with the system operator, ANEEL establishes the amount of assured energy to be sold by each plant. The system operator determines generation dispatch whichtakes into account nationwide electricity demand, hydro-logical conditions and system constraints. In order to mitigate risks involved in hydroelectric generation a mechanism is in place to transfer surplus energy from thosewho generated in excess of their assured energy to thosewho generated less than their assured energy. The volumeof electricity actually generated by each plant is priced pursuant to an energy optimization tariff.

The New Power Sector Model law is currently being challenged on constitutional grounds before the BrazilianSupreme Court. The timing of any decision is not currentlyknown and the New Power Sector Model law currentlyremains in force. Regardless of the Supreme Court’s finaldecision, certain portions of the law relating to restrictionson distributors performing activities unrelated to the distribution of electricity, including sales of energy by distributors to free consumers and the elimination of contracts between related parties are expected to remain in full force and effect.

5 4 A E S 2 0 0 6 FA C T B O O K

The predecessor company to Brasiliana (Brasiliana Energia,S.A.) was created as part of the December 2003 restructuringagreement executed between AES and the BrazilianNational Development Bank (BNDES). AES controlsBrasiliana through direct ownership of 50% plus one common share. BNDES’s wholly owned subsidiary directlyowns the remaining common shares. Ownership ofadditional non-voting preferred shares gives BNDES a53.84% economic interest in Brasiliana; AES’s economicinterest is 46.16%.

Brasiliana owns, directly and through intermediary holdingcompanies, controlling stakes in Eletropaulo, Tietê andUruguaiana, as well as InfoEnergy (a commercial energy trading company) and the telecom businesses (EletropauloTelecom and AES Communication). Neither InfoEnergy nor the telecom businesses are material contributors toAES’s consolidated financial results.

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Companhia Brasiliana de Energia (Brasiliana) is the holding company that owns AES’s interest

in many of its Brazilian subsidiaries, including most importantly Eletropaulo, Tietê and

Uruguaiana, as well as InfoEnergy and the telecom businesses. Sul is 100% owned by AES,

outside of the Brasiliana ownership chain.

BRASILIANA OVERVIEW

The ownership structure for all of AES’s Brazil businessesis presented as of December 31, 2006, in the diagram below.The chart reflects the impacts of the 2006 Brazil restructuring,including the secondary offering of Eletropaulo shares andsubsequent mergers of intermediary holding companies. As part of the 2006 restructuring, proceeds from the saleof Eletropaulo shares were used to fully repay debt at

Brasiliana held by BNDES. This U.S. dollar-denominateddebt had a cash sweep provision that effectively precludedthe payments of dividends from Brasiliana to AES Corp.Brasiliana is no longer prohibited from paying dividends toits shareholders, although it must continue to service itsremaining debt obligations.

AES BRAZIL OWNERSHIP AND DEBT STRUCTURE

AES BRAZIL STRUCTURE

INFOENERGY AES COMM RIO

ELPA

Holding Company Intermediary Holding Company Operating Company V = Voting (%) E = Economic (%) Net AES Ownership

50.1 V 46.2 E100 V 100 E

0 V 4.4 E

98.3 V 98.3 E

77.8 V 31.0 E

71.3 V 52.5 E 100 V 100 E100 V 100 E

100 V 100 E100 V 100 E100 V 100 E 38.2 V 16.1 E

50.1 V 46.2 E 49.1 V 45.4 E 50.1 V 46.2 E

35.7 V 24.3 E 50.1 V 46.2 E

49.9 V 53.8 E

AES

SUL

BNDES

BRASILIANA

ELETROPAULO TIETÊ

ELETROPAULO TELECOM

URUGUAIANA


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Eletropaulo is the electricity distribution company serving São Paulo and 23 municipalities

that make up the greater metropolitan area.

It is the largest distribution company in Brazil in terms of revenues and volume of energy distributed. Eletropaulo

serves over 5 million customers in an area of 4,526 km2. It has a transmission and distribution network of 43,995 km.

As of December 31, 2006, Eletropaulo employed 4,316 people.


Eletropaulo was privatized in 1998 and purchased byLightgas, which was owned at that time by a consortium ofinvestors; namely AES, Électricité de France (EDF),Companhia Siderurgica Nacional (CSN), and ReliantEnergy. In 2001, through a shareholder restructuring, AESbecame its controlling shareholder.

AES now controls Eletropaulo through its holdings inBrasiliana. Following a secondary offering in 2006,

Brasiliana owns 76% of the voting shares of Eletropauloand has a 35% economic interest. Approximately 56% ofthe shares (economic interest) are publicly held and tradeon the BOVESPA. The other main shareholder inEletropaulo is the Brazil government (20% voting, 8% economic). AES’s net economic interest in Eletropaulo isapproximately 16%. See page 54 for additional details onAES’s holdings in Eletropaulo.

SALES & OPERATIONS

Electricity SalesEletropaulo holds a 30-year concession granted in 1998,which might be extended at the discretion of the regulator,ANEEL. Its service area has approximately 16 millioninhabitants with the highest per capita purchasing power inBrazil. Eletropaulo has a monopoly franchise, but is subjectto extensive local, state and national regulation relating toownership, marketing, delivery and pricing of electricity,with a focus on protecting customers.

The Brazilian tariff model is described on pages 52 to 53.Eletropaulo’s annual tariff adjustments for the past threeyears have been as follows: 18.6% in 2004, 2.1% in 2005and 11.5% in 2006.

On July 4, 2007, Eletropaulo had its periodic tariff reviewand reset, which resulted in an average tariff reduction of8.43%. As part of the tariff reset process, ANEEL recal -culated the regulatory return on capital for all of the distribution companies in Brazil based on current Brazilianinterest rates, which have decreased since the last reset,and a lower country risk. The lower regulatory return on capital was one of the main drivers of the reduction in tariff. However, lower local interest rates do benefit

Eletropaulo’s financial results. Although the tariff wasreduced overall, the Reference Company costs wereincreased and the X-Factor was decreased. This may allowEletropaulo to be more efficient than the ReferenceCompany and increase its margins over the next few years.Eletropaulo has a tariff reset every four years.

Eletropaulo’s 2006 GWh sold were divided as follows:40% residential, 31% commercial, 21% industrial, 3% public, and 5% other.

Energy SupplyEletropaulo purchased electricity from the followingsources in 2006: (1) energy auctions (36% of total purchases);(2) mandatory supply from the Itaipu plant (32%); and(3) bilateral contracts (32%). In 2006, the electricity purchasedby Eletropaulo was from the following sources: 96% hydro,3% gas, and 1% biomass.

In compliance with the New Power Sector Model,Eletropaulo’s contracting strategy is to purchase 100% to 103% of its forecasted total demand over the nextfive years. This is done through regular energy auctions.

Revenue (In millions) 2004 2005 20062,359 3,154 3,454

5 6 A E S 2 0 0 6 FA C T B O O K

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5S

ul

Sul is an electricity distribution company located in the southern region of Brazil, serving the

Rio Grande do Sul state central-west region, from the Porto Alegre metropolitan region to

the international border with Argentina and Uruguay, including 118 municipalities.

Sul serves over one million customers in a concession area of 99,512 km2 with a transmission and distribution

network of 58,385 km2. As of December 31, 2006, Sul employed 810 people.


Sul was one of three distribution companies created throughthe Companhia Estadual de Energia Electrica (CEEE) privatization process in 1997. CEEE was the state-owned

company that used to supply the entire Rio Grande do Sulstate. AES acquired Sul’s exclusive concession rights for30 years and currently owns 100% of the equity.

SALES & OPERATIONS

Electricity SalesSul’s concession area covers approximately 35% of the Rio Grande do Sul state. Its concession, which might beextended at the discretion of the regulator, ANEEL,expires in April 2027. Sul has a monopoly franchise but issubject to extensive local, state and national regulationrelating to ownership, marketing, delivery and pricing ofelectricity, with a focus on protecting customers.

The Brazilian tariff model is described on pages 52 to 53.Sul’s annual tariff adjustments for the past three years have been as follows: 4.2% in 2004, 3.9% in 2005 and6.2% in 2006. The next tariff reset for Sul is scheduled for April 2008.

Sul’s 2006 GWh sold were divided as follows: 26% residential, 13% commercial, 36% industrial, 8% public and 17% other.

Energy SupplySul purchased energy from the following sources in 2006:(1) energy auctions (42% of total purchases); (2) mandatorysupply from the Itaipu plant (26%); (3) Uruguaiana (20%);and (4) other contracts (12%). In 2006, the electricity pur-chased by Sul was from the following sources: 74% hydro,20% gas, and 6% coal.

In compliance with the New Power Sector Model, Sul’scontracting strategy is to purchase 100% to 103% of itsannual forecasted total demand. This is done through regular energy auctions.



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ietê

Tietê, with 2,650 MW of installed capacity, represents approximately 21% of the total capacity

in the State of São Paulo.

Tietê is the second largest private generator in Brazil. Tietê consists of 10 hydro electric power plants located in the

central and northeast regions of the State of São Paulo. It supplies 100% of its energy to Eletropaulo under a

long-term contract. As of December 31, 2006, Tietê had 285 employees.


Tietê was formed in April 1999 as a result of the restructuringand privatization of certain assets of Companhia Energeticade São Paulo (CESP), the energy company owned by theState of São Paulo. In October 1999, AES acquired themajority of the company’s shares in a public auction on theSão Paulo Stock Exchange (BOVESPA). Tietê has a 30-yearconcession agreement that expires in 2029, but may beextended at the discretion of the regulator.

AES controls Tietê through its holdings in Brasiliana.Brasiliana owns 71% of the voting shares of Tietê, and has a 53% economic interest. The other main shareholder isEletrobrás, a company owned by the Federal Government(0% voting, 8% economic). The remaining shares are publicly held and trade on the BOVESPA. AES’s net economic interest in Tietê is approximately 24%. Seepage 54 for additional details on AES’s holdings in Tietê.

PHYSICAL ASSETS

The Agua Vermelha plant accounts for more than half of theenergy generated by the company and for approximately53% of its installed capacity. It is the only Tietê facility onthe Grande River. The Agua Vermelha plant inflows areregulated from the Agua Vermelha Reservoir on the GrandeRiver. It also benefits from additional flow regulation ofupstream reservoirs on the Pardo River. It began operationsin 1978 and has an installed capacity of 1,396 MW.

Tietê has five facilities on the Tietê River totaling 1,027 MWof installed capacity. The Barra Bonita plant is the mostupstream facility on the Tietê River, with 141 MW ofinstalled capacity. It commenced operations in 1963 andhas a reservoir. The Bariri and Ibitinga plants are run-of-the-river plants also located on the Tietê River with143 MW and 132 MW of installed capacity, respectively.Bariri began operations in 1965 and lbitinga in 1969.

Located below the Ibitinga plant, the Promissão plant hasan installed capacity of 264 MW and began operations in1975. The fifth facility, Nova Avanhandava, is a run-of-the-river plant with 347 MW of installed capacity that beganoperations in 1982.

Tietê has three facilities on the Pardo River totaling 221 MWof installed capacity. The Caconde plant has an installedcapacity of 80 MW and has a reservoir. It began operations in1966. The Euclides da Cunha and Limoerio plants are run-of-the-river plants with 109 MW and 32 MW of installed capacity,respectively. The Euclides da Cunha plant began operations in1960 and the Limoeiro plant in 1958.

Mogi Guaçu is a run-of-the-river plant located on the MogiGuaçu River with 7 MW of installed capacity. It beganoperations in 1997.

SALES & OPERATIONS

Electricity SalesTietê is a fully contracted generator, historically supplyingelectricity to all major distribution companies in the Stateof São Paulo. Tietê currently sells 100% of its assuredenergy under a long-term power purchase agreement withEletropaulo through December 2015. The contract price isadjusted annually for inflation (IGP-M).

In October 2003, Tietê and Eletropaulo executed anamendment to the PPA extending the expiration date until2028. This amendment was denied by ANEEL. Eletropaulofiled a lawsuit against ANEEL’s denial, but there had beenno decision as of the date of publication.


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Uruguaiana is a 639 MW thermoelectric plant located in the city of Uruguaiana, in Rio Grande

do Sul state. Uruguaiana represents approximately 10% of the installed capacity of

Rio Grande do Sul state.

Uruguaiana sells electricity under long-term contracts. As of December 31, 2006, Uruguaiana employed 57 people.


Uruguaiana was the first generation project in Brazil to usenatural gas on a large scale to generate electricity. The projectwas developed by AES; construction started in 1998 andoperations commenced in December 2000. AES controls

Uruguaiana through its holdings in Brasiliana. Brasilianaowns 100% of the equity of Uruguaiana. AES’s net economicinterest in Uruguaiana is approximately 46%. See page 54for additional details on AES’s holdings in Uruguaiana.

PHYSICAL ASSETS

Uruguaiana consists of two 187 MW dry low NOx gas turbinesand one 265 MW triple pressure stage steam turbine configured as a 2x1 combined cycle with supplemental duct

firing. Uruguaiana may use oil as an alternative fuel only incases of emergency.

SALES & OPERATIONS

Electricity SalesUruguaiana sells electricity to AES Sul (37%), CompanhiaEstadual de Energia Eletrica (CEEE, 33%), and Rio GrandeEnergia (RGE, 30%) under 20-year 495 MW power purchaseagreements effective since December 2000. Prices areadjusted annually by IGP-M for inflation and for variances ingeneration costs. Energy payments are adjusted for the costof delivered natural gas under the gas supply agreement.

In addition, Uruguaiana has a PPA with AES Eletropaulofor 59 MW that expires in July 2009. In 2005, the regulatorrequired Uruguaiana to perform an availability test whengas was only partially available. As a result the assuredenergy of the plant was reduced to 217 MW from 560 MW.

Fuel SupplyIn December 1999, Uruguaiana signed a 20-year gas supplyagreement (GSA) with Sulgas, a Brazilian company that

sources gas from Argentina through YPF Argentina. TheGSA is extendable up to 2029. Transportadora de Gas delMercosur and Transportadora de Gas del Norte are the gascarriers. The contract establishes a daily volume of 2.8 millioncubic meters during 350 days per year with an average take-or-pay of 75% and a ship-or-pay of 100%. Prices are basedon U.S. dollars and periodically indexed, although theadjustment is limited to a cap of PPI plus 2.5%. Currentlythere is no alternative source of supply.

Since 2004, due to the Argentinean energy crisis, Uruguaianahas had its gas supply interrupted from May to Septemberin order to satisfy the Argentine demand. During thisperiod, Uruguaiana purchases energy from the spot marketand through bilateral contracts, ensuring the compliance of its PPA commitments with the distribution companies.Additionally, the take-or-pay obligation was released forthe same period from 2005 to 2009.



Capital SantiagoLargest city SantiagoPopulation 16.1 million (7/06 est.)GDP $203 billion (2006 est.)GDP per capita $12,600 (2006 est.)

Economic drivers Financial services, other services including tourism,copper and other minerals, agriculture

Currency Chilean peso (CLP)Sovereign credit Fitch – A, Stablerating Moody’s – A2, Stable

S&P – A, Positive

COUNTRY FACTS



growth rate



(CLP:USD)



Thermal 60%40%Hydro

0%Nuclear0%Other

2002 2.2%3.9%6.4%

4.6%

8.1%

20036.2%2004

200220032004

6.3%20054.4%2006

0 100 0 9 0 7 0 7000 4

2002 2.5%2.8%2003

1.1%20043.1%20053.4%2006

2002 688.94691.432003609.372004560.092005532.122006

Ch

ile

Capital BogotaLargest city BogotaPopulation 43.6 million (7/06 est.)GDP $367 billion (2006 est.)GDP per capita $8,400 (2006 est.)

Economic drivers Services (financial services, retail, telecommunica-tions), industry (processed food, textiles), agriculture (cattle rearing, coffee production)

Currency Colombian peso (COP)Sovereign credit Fitch – BB, Positiverating Moody’s – Ba2, Stable

S&P – BB+, Stable

COUNTRY FACTS



growth rate



(COP:USD)



Thermal 34%65%Hydro

0%Nuclear1%Other

2002 1.9%3.9%3.1%

0.6%

20034.9%2004

200220032004

5.3%20056.1%2006

0 100 0 4 0 7 0 3,0000 8

2002 6.3%7.1%5.9%

20032004

5.0%20054.3%2006

2002 2,504.242,877.6520032,628.6120042,320.7520052,382.902006

3.0%

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The electricity sector in Chile is regulated by the ElectricLaw, which was originally enacted in 1982. Under theElectric Law, the electricity market is 100% privately-ownedand divided into three distinct segments: generation, transmission and distribution. The general frameworkestablishes market competition for generation and trans-mission and benchmark regulation based on a model company for distribution. The Chilean Ministry ofEconomy and Energy regulates the granting of concessionsto generation companies for hydroelectric facilities and todistribution companies for distribution networks. Concessionsare not required for thermoelectric power plants. TheNational Energy Commission (NEC) defines energy policyand generally oversees electric regulation. The Superintendencyof Electricity and Fuels supervises compliance with qualityof service and safety standards. In 2005, an autonomouscommission, the Panel of Experts, was established toresolve technical disputes within the electricity sector.

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

In Chile, in order to minimize the operational cost of thesystem, independent load centers dispatch plants on amandatory basis in order to achieve the lowest cost of production available to meet the level of demand at anygiven time, constrained to maintain safety and reliability of service. The electricity systems are intended to be

near-perfect markets for the generation of electricity inwhich the lowest cost producer is used to satisfy demandbefore the next lowest cost producer is dispatched. As aresult, although generation companies freely enter intopower purchase agreements with distribution companiesand other customers for the sale of capacity and energy, theelectricity necessary to fulfill these agreements is providedby the contracting generation company only if the genera-tion company’s marginal cost of production is low enoughfor its generating capacity to be dispatched to meet demand.Otherwise, the generation company will purchase electricityfrom other generation companies at the system marginalcost. The marginal cost of production is the cost of theleast expensive next unit required to meet system demandat a given time.

Since 2004, the Argentine government has enacted regula-tions that privilege the domestic supply of natural gas incomparison to exports. The Argentine natural gas exportrestrictions and duties have significantly impacted theChilean electricity industry, modifying the dispatch supplyportfolio and increasing the cost of production. InMay 2005 an amendment to the Electric Law known as the“Short Law II” was approved by the Chilean Congress andExecutive Branch. The bill was designed to mitigate theeffects of the natural gas restrictions on natural gas exportsto Chile imposed by the Argentine government by providingincentives for future generation projects. In general, thenew law increased the flexibility of the regulated price system.One of the principal aspects of the new law is a gradualreplacement of the price currently applied to sales by generation companies to distribution companies, which iscalculated every six months by the NEC, with marketprices determined through public bidding processes. Underthe terms of the amendment, distribution companies arerequired to hold auctions for new supply contracts. Thesecontracts are assigned based on the lowest energy priceoffered and have a maximum term of 15 years. Capacityprices are determined by the NEC every six months.


In 1994 the Colombian Congress enacted the laws ofDomiciliary Public Services and the Electricity Law, whichset the institutional arrangement for the electric sector andthe general regulatory framework. The Regulatory Commissionof Electricity and Gas (CREG) was created to foster theefficient supply of energy through regulation of the whole-sale market, the natural monopolies of transmission anddistribution, and by setting limits for horizontal and verticaleconomic integration. The control function was assignedto the Superintendency of Public Services. The Mining andEnergy Planning Unit (UPME) develops indicative plansfor the energy sector. These plans are then adopted by theMinistry of Mines and Energy. The general regulatoryframework established free access in the networks, freeentrance in the business, the creation of a wholesale market,the unbundling of activities, the principles for setting formulas for tariffs and the free selection of the provider by the consumer, among others.

The wholesale market is organized around both bilateralcontracts and a mandatory pool and spot market for allgeneration units larger than 20 MW. Each unit offers itsavailability quantities for a 24 hour period with one priceset for those 24 hours. The dispatch is arranged by price meritand the spot price is set by the marginal unit. The systemhas a single node price.

The spot market started in July 1995, and in 1996 a capacitypayment was introduced for a term of 10 years. InDecember 2006, a regulation was enacted that replacedthe capacity charge with a reliability charge. Under the reli-ability charge mechanism, plants present firm energy priceand volume offers in public auctions that are held three yearsprior to the initiation of supply. Plants are allowed to bid up to the maximum firm energy level which can be providedduring drought conditions, as defined in a methodologyutilized by the CREG. The new regulation includes a tran-sition period from December 2006 to November 2009,during which the price is equal to US$13 per MWh and volume is determined based on firm energy offers which are pro-rated so that the total firm energy level does notexceed system demand.

Bilateral contracts are freely negotiated and prices agreedbetween the agents, with the exception of contracts to supply regulated (small) consumers. In such cases, contractsare awarded via public bid processes to the lowest bidder.Bilateral contracts between a generator and suppliers aresettled by the Market Administrator. These contracts arenormally either “take or pay” or “take and pay” agreements,and normally have a term of one to three years. There is noregulatory obligation for an electricity supplier to hedge itsconsumers’ demand, and the negotiation of energy contractsbetween generators and suppliers for unregulated customersis unrestricted.

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In November 2000, AES, through its subsidiaryInversiones Cachagua Limitada, announced a tender offerfor cash for approximately 62% of Gener’s outstandingshares in Chile, as well as an exchange tender offer of all ofGener’s American Depositary Shares (ADS) for shares inAES. The purchase price for the offer was US$16.50 perADS, or its equivalent in Chilean pesos per common share.In December 2000, AES acquired approximately 61% ofGener’s total capital for the Chilean peso equivalent ofUS$841 million and effectively assumed control of Gener.In January 2001, AES acquired an additional approximately35% stake in Gener for a total purchase price of US$476 millionin the form of AES common stock. AES increased its stakein Gener through a series of subsequent transactions andby 2004 owned approximately 99%. Following a sale ofshares in 2006, AES currently holds approximately a 91%interest in Gener.

Gener consists of the operations of the parent company (AES Gener) and six consolidated subsidiaries. NorgenerS.A. (Norgener), Energia Verde S.A. (Energia Verde),TermoAndes S.A (TermoAndes), and InterAndes S.A.(InterAndes) are owned 100% by Gener (AES’s net owner-ship is 91%). Chivor is 100% owned by Gener (AES’s netownership is 91%). Sociedad Electrica Santiago S.A.(Electrica Santiago) is 90% owned by Gener (AES’s netownership is 82%); the remaining shares are held byCompañia General de Electricidad.

In addition, Gener has a 50% interest in Empresa ElectricaGuacolda S.A. (Guacolda), which is not consolidated, and a25% interest in Empresa Generadora de Electricidad ItaboS.A. (Itabo). AES’s net ownership of Guacolda is 46%; theremaining shares are held by Empresas Copec S.A. andInversiones Ultraterra Limitada. AES owns an additional25% interest in Itabo for total net ownership of 48%. Itabois described in the Dominican Republic Generation sectionon pages 67 to 68.


AES Gener S.A. (Gener) generates and sells electricity in Chile and Colombia, and is also

engaged, directly or through equity-method affiliates, in electricity generation in the

Dominican Republic, coal distribution in Chile, and natural gas transportation in Chile

and Argentina.

Gener, its subsidiaries and 50% equity-method affiliate own 2,559 MW of installed capacity which is used to supply

the Chilean market. Gener is the largest thermal generator and the second largest electricity generation company in

Chile based on generating capacity. The company provides electricity to the largest interconnected system in Chile,

the SIC, which serves central Chile, where more than 90% of the country’s population lives. It also provides electricity

to the SING, the interconnected system that serves the northern part of the country, where mining industry

consumption prevails. As of December 31, 2006, Gener, its subsidiaries and 50% equity-method affiliate related

company accounted for approximately 19% of the installed capacity in the SIC, and approximately 26% of the

installed capacity in the SING. In Colombia, Gener’s 100% owned subsidiary, Chivor, owns a 1,000 MW dam-based

hydro plant which represents approximately 8% of the country’s installed capacity. Gener also has a 25% interest

in Itabo, a 472 MW generation facility in the Dominican Republic. As of December 31, 2006, Gener and its

subsidiaries had 630 full-time employees.



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Gener directly owns and operates four hydroelectric plantsand four thermoelectric plants in Chile’s SIC. The hydro-electric facilities are all run-of-the-river facilities located inthe Andes Mountains southeast of Santiago. The Alfalfalplant is Gener’s largest hydroelectric plant with installedcapacity of 178 MW; it consists of two units and was commissioned in 1991. The Queltehues plant was commis-sioned in 1928; it consists of three units with total capacityof 49 MW. The five-unit 31 MW Maitenes power plant wasoriginally commissioned in 1923. The Volcan power plant,commissioned in 1949, has one unit with installed capacityof 13 MW. Gener also has four thermoelectric facilities,which are located in Chile’s Region V. The Ventanas plant is a 338 MW coal-fired plant with two units, commissionedin 1964 and 1977. Ventanas has electrostatic precipitators(ESPs). The Laguna Verde plant is also a coal-fired plantwith installed capacity of 55 MW. This plant has two unitsthat were commissioned in 1939 and 1949, respectively.Gener installed a diesel-fired gas peaking turbine withinstalled capacity of 19 MW at its Laguna Verde site in2003. This turbine was originally commissioned in 1990 ata different site but was transferred to Laguna Verde in2003. Gener’s newest plant, the Los Vientos plant, initi-ated commercial operation in January 2007. This 125 MWplant is a one unit turbine able to utilize gas or diesel as fuel.

In northern Chile, Norgener has two coal-fired units withinstalled capacity of 277 MW. Both units have steam turbinesand boilers that were commissioned in 1995 and 1997,respectively. In June 2004, Norgener was authorized toburn a mix of coal and petroleum coke. Both Norgenerunits were constructed with ESPs and stack gas monitoringsystems were installed in 2004.

In south-central Chile, Energia Verde consists of twoco-generation power plants with capacity of approximately

11 MW and 13 MW respectively, one steam generationplant and one 25 MW diesel peaking turbine. EnergiaVerde uses forestry and agricultural waste to generatesteam, with installed capacity of 142 tons of steam per hour.

In north-central Chile, Guacolda has two coal-fired unitswith capacity of 152 MW each. The units were commissionedin 1995 and 1996. Guacolda also possesses a mechanizedmulti-purpose port with capacity of 1,500 tons/hour whichis utilized for unloading coal and general bulk cargo.

In Santiago, Chile, Electrica Santiago consists of one379 MW combined-cycle plant and one 100 MW diesel oil-fired plant, both of which operate in the SIC. The CCGTbegan commercial operation in 1998 and the diesel oil-fired plant began commercial operation in 1962.

In Salta, Argentina, TermoAndes consists of two gas turbinesand one steam turbine with a gross capacity of 643 MW.InterAndes operates a 345 kV transmission line from theTermoAndes plant to the Chilean border.

Chivor’s 1,000 MW hydroelectric power plant is composedof eight generating units distributed among two sub-facilities that began commercial operation in 1977 and1982. The principal sources of water are the Somondocoand Garagoa Rivers, which merge into the Bata River. Tworiver diversion structures also route water from the Tunjita,Negro and Rucio Rivers into deviation tunnels. The dam is a clay core rockfill structure. Water in the reservoir istransported to the two sub-facilities via two tunnels, whichare each eight kilometers long. The powerhouse is situatedat an elevation that is 800 meters below that of the reservoir.This elevation difference guarantees sufficient water pressure to power the generating units.

PHYSICAL ASSETS

SALES & OPERATIONS

Electricity SalesGener’s strategy seeks to maximize its electricity business,managing risk in accordance with the existing market andindustry conditions. Gener estimates demand growth andprojects the levels of regulated prices and marginal costswithin the system. It then determines the level of contractualsales which will allow it to stabilize cash flow, supply othercompanies with generation deficits during droughts andpurchase power on the spot market when the marginal cost

is lower than its own cost of production. In general terms,the company’s strategy is to execute long-term contractsfor an amount of energy approximately equal to the annualfirm energy from its most efficient, or market-based cost,units, while reserving the remaining capacity associatedwith its higher cost units for sales in the wholesale market.Gener and its subsidiaries enter into contracts with bothregulated and unregulated customers.

6 4 A E S 2 0 0 6 FA C T B O O K

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Under the amendment to the electricity law enacted in2005, regulated customers (distribution companies) mustcontract 100% of the forecasted demand for their regulatedcustomers through periodic public auctions held at leastthree years prior to the effective contract date. These con-tracts may have a term of up to 15 years. Bidders submit anenergy price offer and select the coefficient assigned to thevariables in the indexation mechanism which is composedof inflation and fuel cost variables. The capacity price isdetermined by authorities every six months based on thedevelopment cost for a peaking turbine and is indexed byCPI. Competitive bid processes are also generally held by unregulated customers, such as mining companies andlarge industrial users. Contracts typically include a variableenergy payment for the energy consumed and a capacitypayment for peak capacity consumption.

Gener’s largest regulated customers in Chile are two distribution companies operating in the SIC, Chilectra S.A.(Chilectra) and Chilquinta Energia S.A. (Chilquinta).Gener currently sells energy to Chilectra and Chilquintaunder long-term contracts expiring in 2010. Additionally, inthe first distribution company auction held in October 2006,Gener was awarded new long-term contracts with Chilectraand Chilquinta for 1,200 and 189 GWh per year, respectively.In the second distribution company bid process held inJanuary 2007, Gener was awarded a 1,130 GWh contractwith Empresas Emel S.A. The new contracts all initiate in 2010 and the termination dates are between 2020 and2025. Gener also plans to participate in the upcoming regulated and unregulated bid processes. The next large distribution company auction is scheduled for October 2007.Gener also sells electricity in the SIC to Cemento PolpaicoS.A., under a long-term contract expiring in 2010. In theSING, Gener has contracts with three mining companies.The contracts with Compañía Minera Zaldivar S.A. andCompañía Minera Lomas Bayas S.A. for a total of 110 MWof capacity, terminate in June 2008. A supply contract withMinera Mantos de la Luna for up to 25 MW was initiated in2006 and expires in 2010.

Norgener has supply contracts totaling 252 MW of capacityand expiring in 2015 with Minera Escondida Ltda.(Escondida), which operates one of the largest coppermines in the world. Norgener also has two long-term contracts with SQM Nitratos and SQM Salar, which expirein 2013 and 2017, respectively.

Energia Verde has various long-term contracts for electricityand steam supplies. Its principal electricity contractsexpire in 2010 and 2011 and its steam contracts expirebetween 2010 and 2016. Energia Verde’s contracts are generally adjusted by reference to the regulated node price.

Electrica Santiago has a 220 MW contract with Gener,which is used to supply Chilectra, and expires in 2010.Surplus capacity is sold in the spot market.

Approximately 95% of Guacolda’s revenues are derivedfrom long-term contracts for the supply of capacity and energy,expiring between 2009 and 2015. Guacolda’s principal customers are mining companies located in the third andfourth Regions of Chile. In the distribution company bidauction held in October 2006, Guacolda was awarded acontract with Chilectra for 900 GWh per year for theperiod from 2010 to 2020.

All capacity and energy generated by TermoAndes is sold to Gener under a contract ending in December 2025. Thecontract price includes a fixed charge as well as a variablecharge for energy produced, and the transmission price isequal to InterAndes transmission toll.

Chivor’s strategy is to maximize its commercial margin andto minimize the variability of its commercial margin.Commercial margin consists of energy sales less associatedenergy costs. Maximization of commercial margin is basedon an active reservoir management and portfolio flexibility.Chivor limits the amount of its generating capacity that isunder contract in order to be able to determine whether tofulfill its energy supply agreements with self generation orenergy purchases in the spot market. The minimization ofthe variability of Chivor’s commercial margin is based on astable revenue base and high credit quality of energy supplyagreement counterparties.

Cogeneration SalesEnergia Verde supplies steam to several sawmills and pulpand paper companies in the south-central region of Chile.

Water RightsThe principal sources of water for Gener’s hydroelectricfacilities located in Chile are the Colorado and Maipo rivers,each located near the company’s hydroelectric facilities.The company has been granted water rights under applicable Chilean law to use such water sources withoutcharge for an indefinite period of time. Gener also possesseswater rights for potential future generation projects, whichbeginning in 2007 are subject to payment of an annual permit.

Chivor has two concessions under applicable Colombianlaw that enable the company to use its water sources without charge. Both Colombian water rights concessionsgranted to Chivor are for 50-year terms and terminate in2019 and 2034, respectively. Each concession allows Chivorto use the water sources for the purpose of electricity gener-ation and is renewable during the last year of each term.


Fuel SupplyGener purchases coal internationally and it is transportedto Chile by ship. During 2006, the company was the largestcoal importer in Chile, which enables Gener to negotiateattractive prices and directly arrange coal transportationand delivery. Gener has taken advantage of its position inthe Chilean coal market by selling coal to third parties.During 2006, Gener purchased its coal requirements fromproducers in Canada (27%), Indonesia (25%), New Zealand(20%), Colombia (19%) and Australia (9%). Gener’s coalacquisition strategy includes a mix of short, medium andlong-term purchase contracts.

The company’s peaking plants, plants which are typicallyonly dispatched in order to meet system demand during highconsumption periods, utilize petroleum-based fuels such asdiesel oil, which are typically purchased on the spot market.

Argentine natural gas is purchased under long-term marketbased contracts for Electrica Santiago and TermoAndes’combined-cycle units. Since 2004, the Argentine governmenthas enacted regulations that privilege the domestic supplyof natural gas with respect to exports, which has resulted in temporary suspension of supplies to certain plants andoccasional reductions in electric generation. The partialreductions in the supply of natural gas to Electrica Santiagosince 2004 have, at certain times, forced it to reduce its output, as well as to generate with diesel oil as a substitutefor natural gas.

Energia Verde’s cogeneration plants use biomass, principallyforestry and agricultural waste, as fuel. The primary sourceof fuel is from Energia Verde’s timber and paper pulp customers and the remainder is purchased on the spot market. Fuel prices are fixed under the contracts or equalto a portion of the energy sold to the customer.

Guacolda’s coal and petroleum coke are purchased primarilyfrom Australia and Indonesia, and to a lesser extent Colombia,Canada and the United States. Guacolda has its own portfacilities that can handle approximately 17,500 tons of fuel per day.

Energy SupplyIn the SIC, Gener elects to be a spot purchaser of electricityfrom other generation companies during relatively wetyears that result in high hydroelectric generation conditionsand lower marginal costs. The company’s spot purchases of electricity decline in periods of low hydro conditions.Gener’s spot market purchases decreased from 2,571 GWhin 2005 to 2,202 in 2006 principally as a result of higher generation from its coal plants and a decrease incon tractual commitments.

In the SING, both TermoAndes and Norgener have continued to increase their production in order to compensate for the interruption of other natural gas-firedplants located in Chile. TermoAndes’ sales to the spot market increased from 1,336 GWh in 2005 to 1,357 GWhin 2006. Additionally, in 2006 Norgener made net spot market sales of 110 GWh, which compares to net pur-chases of 510 GWh in 2005.

RECENT EVENTS

In 2006, Gener initiated development of two coal plants.The Nueva Ventanas plant, which is owned by a 100%-owned subsidiary of Gener, Empresa Electrica VentanasS.A., consists of a 267 MW (gross) coal-fired power plantlocated at the existing Ventanas plant site. The Guacolda IIIplant is being developed by Gener’s 50%-owned affiliate,Guacolda. This plant is a 152 MW (gross) pulverized coal unit

located at the existing Guacolda plant site. In 2006, bothprojects were granted environmental impact studyapprovals and executed engineering, procurement and construction contracts. Construction of Nueva Ventanasand Guacolda III began in the first quarter of 2007 andcommercial operations are scheduled for January 2010and September 2009, respectively.

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Under current regulations, the Dominican governmentretains ultimate oversight and regulatory functions as well as control and ownership of the transmission grid and thehydroelectric facilities in the country. The Dominican government’s oversight responsibilities for the electricitysector are carried out by the CNE (National EnergyCommission) and by the SIE (Superintendency of Electricity).Corporación de Empresas Eléctricas Estatales (CDEEE),leads and coordinates the operations of the state-owned utilities in the Dominican electricity sector, implements theDominican government’s electricity programs and administersthe various energy contracts with independent power producers.

The spot market in the Dominican Republic commencedoperations in June 2000. All participants in the Dominicanelectric system with available units are put in order of meritfor dispatch. The order of merit is effective for one week.Sector participants may execute private contracts in whichthey agree to specific energy and capacity transactions. The financial settlement of power purchase agreements is independent of the actual dispatch of any particularpower generator.

The financial and political crisis in the Dominican Republicduring 2004 caused a financial crisis in the electricity sector.The inability to pass through higher fuel prices and the costsof devaluation led to a gap between collections at the distri-bution companies and the amounts required to pay the gen-erators. In 2005 the government committed itself to staycurrent with its energy bills and also to cover the potentialdeficit of distribution companies. During 2005 and 2006,the government has been paying both the subsidies and itsown energy bills on time. In December 2006, a bill with theprimary goal of supporting fraud prosecution was sent toCongress by the Executive Branch. Approval of this bill isexpected in 2007. Despite these improvements, the electric-ity sector has not completely recovered from the financialcrisis of 2004. In 2006 it needed more than $500 million ingovernment support to cover current operations. For 2007an amount of $400 million has been included in the govern-ment’s budget.

In October 2006, a government commission presented a General Proposal to the Generation Companies forrenegotiation of PPAs, however the parties have not yet initiated the negotiations.

Capital Santo DomingoLargest city Santo DomingoPopulation 9.2 million (7/06 est.)GDP $74 billion (2006 est.)GDP per capita $8,000 (2006 est.)

Economic drivers Manufacturing, commerce, agriculture (sugarcane,coffee, cotton, cocoa, tobacco), communications,and tourism

Currency Dominican peso (DOP)Sovereign credit Fitch – B, Positiverating Moody’s – B3, Rating Under Review

S&P – B, Positive

COUNTRY FACTS



growth rate



(DOP:USD)



Thermal 76%10%Hydro0%Nuclear15%Other

2002 4.3%(2.0)%17.4%

11.8%

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2002 5.2%27.5%

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2002 18.6130.83200342.122004

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With combined generation installed capacity of 1,027 MW and 973 MW effective capacity,

AES’s three plants in the Dominican Republic, Itabo, Andres and Los Mina represent 32% of

the country’s total effective capacity.

Itabo is a 472 MW coal and diesel-fired power plant near Santo Domingo. It has the lowest-cost thermal power

generation units in the Dominican Republic. Andres is the newest and largest single-unit power plant in the country,

a 319 MW gas-fired combined cycle generation plant with a liquefied natural gas (LNG) import terminal and a 34 km

natural gas pipeline. Andres is located on the southern tip of the Caucedo Peninsula, 35 km east of Santo Domingo.

Los Mina is a 236 MW simple cycle gas-fired plant located in Santo Domingo. As of December 31, 2006, the three

companies employed a total of 289 people.


Gener has had a 25% interest in Itabo since it was priva-tized in 1999. In May 2006, AES acquired an additional25% interest in Itabo from El Paso Corp. bringing AES’stotal net ownership to 48%. As a result of the incrementalpurchase AES gained control of Itabo and now consolidatesits financial results. CDEEE owns 49.97% and formeremployees own the remaining 0.03% of Itabo. AES

acquired Dominican Power Partner (DPP, known asLos Mina) from DESTEC Energy in 1997. It commenced commercial operation in 1996. Andres was developed by AES in 2001 and commercial operation started inDecember 2003. Both companies are 100% owned by AES.AES also has a contract to manage EDE Este, a regionaldistribution company located in Santo Domingo.

PHYSICAL ASSETS

Itabo consists of two steam units (Itabo I and Itabo II)designed to operate using coal, petroleum coke or fuel oiland five gas-fired single-cycle combustion units. Itabo I hasan installed capacity of 128 MW and commenced operationin 1984, while Itabo II has an installed capacity of 132 MWand commenced operation in 1988. Both units were reha-bilitated and converted to use coal as their main fuel in2003. The five gas turbine units have installed capacity of34.5 MW each and commenced operation in 1998. Theywere designed to operate using fuel oil #2 or natural gas.

Andres is a 319 MW combined cycle plant capable of burning both natural gas and fuel oil #2 to mitigate fuelprice volatility. The power plant is one of the most efficientplants in the country, since it operates in combined cyclemode with a high efficiency gas turbine. It consists of onegas turbine and one steam turbine.

Andres has an LNG import terminal, storage and regasificationfacility with a 34 km natural gas pipeline from the terminalon the southeastern tip of the Caucedo Peninsula to LosMina. The pipeline has a capacity of 45 million standardcubic feet per day at 650 psig. The LNG storage tankaccommodates 160,000 liquid cubic meters of LNG.

Los Mina is a 236 MW generation plant that was convertedto gas-fired operations in 2003. It burns natural gas suppliedby Andres. The facility utilizes two simple-cycle combustionturbine generators on land adjacent to a government ownedsubstation, and is dispatched primarily in peaking mode.


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SALES & OPERATIONS

Electricity SalesItabo has contracted 300 MW of capacity and associatedenergy through PPAs with EDE-Este, EDE-Norte andEDE-Sur, the three electricity distribution companies inthe Dominican Republic. All three PPAs are for a term of15 years and expire in July 2016. Contracted capacity underthe PPAs is a firm commitment at a fixed U.S. dollar priceper KW/month adjusted over time for changes in the U.S.CPI and transmission costs for energy. Energy sales arebased on actual customer demand and energy prices arefixed per kWh and adjusted over time for changes in theU.S. CPI and coal prices. The PPAs specify a U.S. dollaramount as the price payable for capacity and energy, withpayment in Dominican pesos at the exchange rate pub-lished by the Central Bank at the time of payment or inU.S. dollars.

Andres has 15-year PPA with EDE Este, expiringJanuary 2019. Under this contract the plant is committedto provide capacity and energy on demand in amountsbetween 50 and 300 MW. The price for contracted capac-ity is calculated using a base purchase price that is adjustedover time for changes in the U.S. CPI and costs to transportthe energy to the location requested. The price for energypurchased is calculated using a base energy price that isadjusted over time for changes in natural gas prices and U.S.CPI. All amounts are calculated in U.S. dollars pursuant tothe exchange rate in effect on the date of payment.

Los Mina sells 210 MW of capacity and related energy toEDE Este under a 15 year PPA, expiring in July 2016.Los Mina receives a base capacity payment indexed to U.S.

CPI, and a base energy payment indexed to NYMEXNatural Gas. The capacity payments are made net of trans-mission and interconnection fees. All amounts are calculatedin U.S. dollars pursuant to the exchange rate in effect onthe date of payment.

Fuel SupplyThe procurement of coal for Itabo’s power generation ismade through annual bidding processes, for which Itabodelivers a request for proposal to several international coalsuppliers. Historically, Itabo’s coal has been supplied fromproducers in Colombia.

The Andres LNG terminal has a 20-year take-or-pay supplycontract with BP Gas Marketing Ltd., a subsidiary of BPplc, of up to 33.6 Tbtu per year. The Andres plant benefitsfrom having cost effective fuel and a strategic location. Thefuel is mainly imported from Trinidad and Tobago and thepricing mechanism is related to NYMEX Henry Hubfuture contracts of natural gas.

Andres sells natural gas and provides firm transportation toLos Mina under a natural gas sales and purchase contract,and a natural gas transportation contract. Both the naturalgas contract and the transportation contract expire inMarch 2023. Under the natural gas contract, Andres sellsgas to Los Mina of up to 18.25 TBtu per year with no take-or-pay obligation. The price is set at the weighted averagecost of gas stored for Andres plus a margin per MMBtu.Under the transportation contract, Andres supplies firmtransportation capacity to Los Mina for an annual fee,which is indexed to U.S. CPI.

RECENT EVENTS

In October 2006, Empresa Generadora de ElectricidadItabo, S.A. (Itabo) issued $125 million in seven-year notes.The coupon is 10.875% and the notes are rated B- with apositive outlook by Fitch and B with a stable outlook byS&P. The proceeds were used to pay a declared and out-standing dividend to Itabo’s shareholders, repay short-termdebt, accelerate capital expenditures to increase the avail-ability of its core coal-fired assets, and for increased liquidity.

In October 2006, Itabo completed the construction of aloading dock for private use to unload coal directly into theItabo complex. This is the only loading dock in the DominicanRepublic with the capacity to handle Panamax vessels.


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El Salvador’s electricity industry is regulated under theElectricity Law enacted in October 1996 and subsequentlyamended in June 2003. The Electricity Law regulates thegeneration, transmission, commercialization, distributionand supply of electricity in El Salvador and provided thebasis for private sector participation and competition inthe Salvadoran energy sector, the unbundling of electricitygeneration, transmission and distribution, the privatizationof electricity distribution and thermal and geothermalgeneration assets, and the creation of a transparent regulatory structure.

The Superintendencia General de Electricidad yTelecomunicaciones (SIGET) is an independent regulatoryauthority that regulates the electricity and telecommunica-tions industries in El Salvador. SIGET is headed by a president-director, designated by the President of El Salvador, for afive-year term. SIGET has two other directors who are designated by the Supreme Court of El Salvador and by theNational Association of Private Businesses (ANEP),respectively. SIGET is responsible for ensuring that all

industry participants comply with the laws and regulationsrelated to the electricity and telecommunications sector inEl Salvador and for issuing further regulations in accordancewith the Electricity Law. The Ministry of Economy hasgeneral oversight responsibilities related to the energy policy through the Secretary of Energy.

In El Salvador the components of the electricity tariff are(a) the average energy price (“energy charge”), (b) the chargesfor the use of the distribution network based on average capital costs and operation & maintenance costs of an efficient distribution network (“distribution charge”), and(c) customer service costs (“service charge”). The energycharge is adjusted every six months to reflect the changes inthe spot market price for electricity. The distribution chargeand service charge are approved by SIGET every five years andhave two adjustments: (1) an annual adjustment consideringthe inflation variation and (2) an automatic quarterly adjustmentprovided that the increase or reduction of the adjusted valuewith respect to the value in effect exceeds 10% of the latter.The next reset will take place in January 2008.

Capital San SalvadorLargest city San SalvadorPopulation 6.8 million (7/06 est.)GDP $33 billion (2006 est.)GDP per capita $4,900 (2006 est.)

Economic drivers Services (commerce, financial services); industrialproducts, especially manufactured goods in themaquila sector

Currency U.S. dollar (USD)Sovereign credit Fitch – BB+, Stablerating Moody’s – Baa3, Stable

S&P – BB+, Stable

COUNTRY FACTS



growth rate



N/A:USD (since 2001)



Thermal 42%36%Hydro

0%Nuclear22%Other

2002 2.5%1.7%0.2%

(2.8)%

4.9%

20031.5%

2.8%2004

200220032004

4.0%

20052006

0 100 –3 5 0 4 0 100 5

2002 1.8%2.1%

4.5%20032004

4.7%20054.0%2006

20022003200420052006

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–89

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AES is the largest electric distributor in El Salvador, with four distribution companies that

serve over one million customers with approximately 3,383 GWh of electricity sold in 2006.

CAESS is the largest distribution company in El Salvador, serving over 491,000 customers in an area of 4,284 km2.

It serves the central and northern region of the country, including San Salvador (the capital of El Salvador). CLESA’s

service territory covers the western region of the country, including the city of Santa Ana. CLESA serves approximately

281,000 customers in an area of 4,633 km2. DEUSEM provides electricity to 53,000 customers in an area of 1,129 km2.

DEUSEM’s service area is located in the southeastern area of the country along the Pacific coast. EEO covers the

eastern region of El Salvador, including the city of San Miguel, with over 200,000 customers in an area of 6,212 km2.

Together, the four companies provided electricity to 82% of the country’s electricity distribution customers in 2006

and employed 976 people as of December 31, 2006.


AES directly purchased an 80% interest in CLESA from the former state-owned monopoly in February 1998 for$97 million. AES now indirectly owns 64% of CLESA (AESCLESA y Compañia), 16% is owned by a foreign strategicinvestor, 15% is held by present and former employees, and5% is held by members of the Salvadoran public.

In January 1998, EDC, a Venezuelan utility, acquired 75%of CAESS and 89% of EEO for $297 million as part of theprivatization of the companies. In February 1998, ReliantEnergy bought 50% of EDC’s interest in both CAESS and EEO. In June 2000, AES launched a successful tenderoffer for EDC and purchased 87% of EDC’s shares and, as a result, took control of EDC’s Salvadoran assets. In

October 2000, AES bought Reliant Energy’s 50% stakeand consolidated those shares with the shares previouslyowned by EDC. AES now indirectly owns 75% of CAESS(Compañia de Alumbrado Eléctrico de San Salvador) and89% of EEO (Empresa Eléctrica de Oriente). The remain-ing shares of both companies are primarily held by presentand former employees, as well as by the government andmembers of the Salvadoran public.

In June 1998, CAESS purchased a 98% interest inDEUSEM; the remaining shares are held by members ofthe Salvadoran public. AES’s net ownership in DEUSEM(Distribuidora Eléctrica de Usulután) is 74%.

SALES & OPERATIONS

Electricity SalesThe four distribution businesses do not operate underlong-term concession agreements. Rather, they own nearlyall of their respective distribution assets and operate theseassets under a rolling one-year electricity distributionlicense, which is renewed annually based on limited formalrequirements by SIGET.

During the tariff revision process that takes place everyfive years, distribution companies present their tariff proposals,which are then revised and approved by SIGET as describedin the El Salvador Regulatory Overview on page 69.

The distribution tariffs are based on the average cost of invest-ment, operation, and maintenance of an efficiently-sized

network. This regulatory framework allows the distributioncompanies to retain the benefits of operating and capitalefficiency during the five-year regulatory period, providingincentives to earn higher returns through operating andcapital expenditure efficiencies.

Combined 2006 GWh sold were divided as follows: 49% residential, 8% commercial, and 43% industrial.

Energy SupplyThe El Salvador distribution companies purchase electricityto meet their distribution customers’ needs through powerpurchase agreements and also through purchases on thespot market. The power purchase strategy is designed toobtain a margin within the energy component of the tariff.



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The distribution companies contract for approximately60% to 65% of their total annual energy requirements viapower purchase agreements on the contract market. ThePPAs are short-term agreements and the purchase pricesare generally based on the spot market price less a discount.These agreements do not include take-or-pay provisions,but do impose penalties on the distribution companies in the

event of early termination. The balance of the distri butioncompanies’ energy requirements, including peak demand,are satisfied by purchases of electricity in the spot market.Since the Salvadoran regulatory framework allows for passthrough of the average spot market price, discounts fromthe spot market price allow the distribution companies toobtain a margin on the energy component.

Pan

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Capital Panama CityLargest city Panama CityPopulation 3.2 million (7/06 est.)GDP $25 billion (2006 est.)GDP per capita $7,900 (2006 est.)

Economic drivers Services: The Panama Canal, Zona Libre de Colon(ZLC), Centro Bancario International (CBI), andother financial services and commerce.

Currency balboa (PAB); US dollar (USD)Sovereign credit Fitch – BB+, Stablerating Moody’s – Ba1, Stable

S&P – BB, Stable

COUNTRY FACTS



growth rate



(PAB:USD)

Thermal 32%54%Hydro

0%Nuclear15%Other

2002 2.2%4.2%2.4%

5.4%

41%

20037.6%2004

200220032004

6.4%20057.4%2006

0 100 0 41 0 8 0 10 3

2002 1.2%1.5%2003

0.4%20042.9%2005

2.4%2006

2002 1.001.0020031.0020041.0020051.002006

7 2 A E S 2 0 0 6 FA C T B O O K

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476

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AES Panama is the largest generator in Panama with 476 MW of installed capacity.

The La Estrella, Los Valles, and Esti hydroelectric plants are located in the Chiriqui province, west of Panama City, and

are operated as base-load. The Bayano hydroelectric plant is located in the Panama province, east of Panama City,

and is operated as a peaker. At least 79% of AES Panama’s firm capacity is contracted through 2018 with credit worthy

counterparties. As of December 31, 2006, AES employed 109 people in Panama.


AES acquired 49% of the two government-owned generationcompanies, Bayano and Chiriqui, in January 1999. AES hasoperating control through an administration contract and consolidates AES Panama’s financial results. AES merged thesecompanies to form AES Panama S.A. in October 1999. As part

of the acquisition, AES also acquired the rights to develop,construct and operate the Esti project, a new 120 MW hydro-electric project. The project entered commercial operation inNovember 2003. The government of Panama retained a 50.5%interest with the remaining 0.5% held by former employees.

PHYSICAL ASSETS

AES Panama owns four hydroelectric plants. Esti (120 MW),La Estrella (45 MW) and Los Valles (51 MW) are operatedtogether as the Chiriqui hydroelectric center. The Esti planthas two units and is a run-of-the river plant with a small regulation reservoir. La Estrella and Los Valles are both run-of-the-river plants, consisting of two units each. They originallycommenced operations in the 1970s, and are in the processof being repowered. The first phase of the repowering wascompleted in 2006, increasing the combined installed capacity

by 6 MW. The second phase is scheduled for 2007, whichwill increase the combined installed capacity by an additional6 MW. The fourth plant is Bayano (260 MW). Bayano originallycommenced operations in the 1970s, but AES Panama addeda third unit in 2002 and upgraded the existing two units in2003 and 2004, increasing the installed capacity by 110 MW.AES Panama’s geographical diversity in the eastern and western regions of Panama mitigates the impact of weather-related volatility in hydrology.

SALES & OPERATIONS

Electricity SalesAES Panama sells most of its electricity under variouspower purchase agreements to the distribution companiesEdemet and Edechi (Union Fenosa) and Elektra Noreste(Ashmore) within Panama. The remaining generation issold into the spot market. As of December 31, 2006, AESPanama had contracted 81% of its firm capacity in 2007and 2008, 79% in 2009 and 2010, 95% from 2011 to 2013and 90% from 2014 to 2018. AES Panama supplies con-tract capacity (firm capacity) and energy under the offtakestructure of the PPA. Firm capacity is the plant capacitywhich is allowed to be contracted, based on adjustments forhydrology and plant design (e.g., reservoir characteristics).

Approximately 305 MW of AES Panama’s installed capacity is defined as firm by the CND (National DispatchCenter). The price terms contained in AES Panama’s PPAsare fixed, with no indexation, including charges for bothcapacity and energy. Distributors are required to pay forcontracted firm capacity without regard to the CND’s dispatch decisions.

Water RightsThe hydroelectric plants of AES Panama are operatedunder four renewable 50-year concessions, expiring in2048 (Esti, La Estrella and Los Valles) and 2052 (Esti).Water royalties are fixed and total less than $100k per year.



RECENT EVENTS

In January 2006, AES announced its intention to build a223 MW hydroelectric plant approximately 350 kmnorthwest of Panama City in the Province of Bocas delToro. The project, called AES Changuinola, has a 10-yearPPA with AES Panama, which has entered into a PPA withtwo distribution companies affiliated with Union Fenosa.Construction is expected to begin in 2007 and the plant isexpected to be operational in 2010. The project is expectedto be financed through a $366 million project financing, with banks in Panama and Central America. AES has 90%

ownership of the voting stock and an 83% economic interestin Changuinola.

In December 2006, AES Panama completed a 144-A offeringof $300 million of 6.35% Senior Unsecured Notes due2016. This was the largest non-sovereign issuance out ofPanama. The proceeds were used primarily to repay existingdebt obligations, reducing the cost of debt by 245 basispoints and extending the average life of AES Panama’s debtportfolio from 5.5 to 10 years.

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The Panamanian electricity sector was privatized in 1998. The following organizations participate in the regulation of the electricity sector: the National Authorityof Public Service (ASEP), the National Dispatch Center(CND), the Ministry of Economy and Finances (specifically,the Energy Policy Commission), and the ETESA PlanningUnit. Panama has a mixed hydro-thermal electricity system,consisting of approximately 58% hydroelectric and 42%thermal (currently fired on imported oil).

The CND is responsible for planning, supervising and controlling the integrated operation of the NationalInterconnected System and for ensuring its safe and reli-able operation. The dispatch order is determined by theCND, which dispatches electricity from generation plantsbased on lowest marginal cost. In the case of thermal units,variable costs are calculated based on incremental fuelcosts and non-fuel costs. For run-of-the-river hydroelectricfacilities (such as AES Panama’s Esti, La Estrella and LosValles plants), variable costs are considered to be zero. Inthe case of reservoir hydroelectric facilities (such as AESPanama’s Bayano plant), variable costs correspond to theopportunity value of water.

The Panamanian power sector is structured as a spot marketwith an overlay of bilateral contracts between the distribu-tion companies and generation companies. Energy spottransactions correspond to the hourly differences betweenthe actual dispatch of energy by each generator and its

contractual commitments to supply energy. A generatorwhose dispatched energy is greater than its contractualcommitments to supply energy at any given time is a sellerin the energy spot market. A generator whose dispatchedenergy is less than its contractual commitments to supplyenergy at any given time is a buyer in the energy spot market.Generators, distribution companies and large users canpurchase energy in the energy spot market, while only generators can sell energy in the energy spot market.

Generators may also receive a capacity charge that isintended to remunerate thermal and hydroelectric generatorsfor the firm capacity made available under their power purchase agreements. The capacity charge provides generators with a source of fixed revenue that is primarilydependent on the generator’s own availability.

In order to mitigate spot market volatility, generators canenter into long-term PPAs with distribution companiesand large users. The terms and contents of PPAs are deter-mined through a competitive bidding process. Generatorscan also enter into reserve supply contracts with each other.Distribution companies are required to contract 100% of their annual energy requirements (although they canself-generate up to 15% of their demand). The PanamanianElectricity Law restricts participation by distribution companies in generation and transmission and by genera-tion companies in the control of distribution companies.

7 4 A E S 2 0 0 6 FA C T B O O K

HIGHLIGHTS

■ 11 countries: Bulgaria, Cameroon, Czech Republic, Hungary, Kazakhstan, Netherlands, Nigeria, Spain, Turkey, Ukraineand United Kingdom



■ Two distribution businesses serving more than 1.2 million customers

■ 1,033 MW installed generating capacity under concession agreement in Kazakhstan

■ One integrated utility serving more than 500,000 customers with 927 MW of capacity




■ Key drivers: foreign currency exchange rates; regulated tariff adjustments & electricity demand; new legislation and regulations, including environmental regulations

AES’s presence in Europe and Africa includes power and steam

generation and distribution businesses in operation or under

construction in 11 countries. This complex region contains some

of the most developed countries in the world, as well as countries

that are just on the cusp of rapid economic expansion.

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7 53 : B U S I N E S S D E S C R I P T I O N S – E U R O P E , C I S A N D A F R I C A

CONTENTS

EUROPE, CIS & AFRICA 74

BULGARIA 76

Maritza East I 76

CAMEROON 78

Cameroon Regulatory Overview 78

SONEL 79

CZECH REPUBLIC 80

Bohemia 80

HUNGARY 81

Hungary Regulatory Overview 81

Hungary Generation 82

KAZAKHSTAN 84

Kazakhstan Regulatory Overview 84

AES Kazakhstan 85

NETHERLANDS 87

Elsta 87

NIGERIA 88

Ebute 88

SPAIN 89

Cartagena 89

TURKEY 91

Turkey Generation 91

UNITED KINGDOM 92

Kilroot 93

UKRAINE 94

Ukraine Regulatory Overview 94

Ukraine Distribution 95

AES’s presence in the region began with the acquisition of

the coal-fired AES Kilroot power plant in Northern Ireland

in 1992, and today extends from Spain in Western Europe,

to Cameroon in West Africa to Kazakhstan in the CIS. AES’s

integrated utility in Cameroon, AES SONEL, is the only

source of electricity for the country and has introduced

reliable power to communities that have never had it before.

In Kazakhstan, AES has gone from accepting payment in

barter when it first entered the country in 1996, to helping

develop an economy powered by reliable, affordable heat

and electricity. Today, AES operates five power plants in

Kazakhstan that account for almost 30% of the country’s

installed capacity. In addition, AES operates a coal mine and

manages two distribution businesses and a heating company.

AES began full commercial operation of its first power plant

in Spain, a 1,200 MW gas-fired plant in Cartagena. In May 2006,

AES commenced construction of its 670 MW lignite-fired

plant in Bulgaria, the first large-scale plant to be built in that

country in decades, and the largest foreign investment in

Bulgaria to date.

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7 6 A E S 2 0 0 6 FA C T B O O K

Revenue (In Millions) 2002 2003 2004

Ma

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Maritza East I is a 670 MW lignite-fired power plant currently under construction at the site

of the old Brikel Power Plant in the Galabovo Municipality within the Stara Zagora District,

approximately 270 km southeast of Sofia, Bulgaria.

The plant will sell electricity output to the Natsionalna Elektricheska Kompania EAD (NEK), the state-owned utility,

under a 15-year PPA. Lignite will be supplied under a 15-year lignite supply agreement with Maritza East Mines EAD

(MMI), a state-owned mining company operating the largest lignite deposit in Bulgaria, 10 km away from the project’s

site. The project will employ on average 2,500 people at the peak of construction, and 200 people during operations.


The project company is wholly owned by AES BulgariaHoldings BV, which is indirectly wholly owned by AES . Theconstruction began in May 2006, and commercial operation

is expected to commence in late 2009. The total cost of theproject is $1.4 billion, with 30% funded by AES equity, and theremaining funding provided through seven non-recourse debt

* Under construction during the periods presented

Capital SofiaLargest city SofiaPopulation 7.4 million (7/06 est.)GDP $77 billion (2006 est.)GDP per capita $10,400 (2006 est.)

Economic drivers Services (government, tourism), industrial products(minerals, especially copper, zinc)

Currency lev (BGL)Sovereign credit Fitch – BBB, Stablerating Moody’s – Baa3, Stable

S&P – BBB, Stable

COUNTRY FACTS



growth rate



(BGL:USD)



Thermal 56%18%Hydro26%Nuclear

0%Other

2002 4.9%4.5%(1.9)%

0.1%

11.3%

20035.7%2004

200220032004

5.5%20056.1%2006

0 100 -2 12 0 7 0 30 8

2002 5.8%2.3%2003

6.1%20045.0%20057.2%2006

2002 2.081.7320031.5820041.5720051.562006

Bu

lga

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Revenue* (In millions)2004 2005 2006

n/a n/a n/a


2009

Segment

Generation

Country

Bulgaria

Fuel

Lignite

AES EquityInterest

100%

MW

670


Ma

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PHYSICAL ASSETS

Maritza East I was designed by Alstom, and will comprisetwo pulverized coal boilers of 335 MW (gross) eachequipped with low NOx burners, two generators, state ofthe art ESPs and wet limestone Flue Gas Desulfurization

(FGD) units designed to achieve an SO2 removal rate inexcess of 95% to comply with EU directives. Maritza East Iis expected to operate as a base-load plant.

SALES & OPERATIONS

Electricity SalesThe initial PPA was signed with NEK in 2001, and was further amended in 2002, 2005, and 2006. Under the termsof the 15-year PPA, Maritza East I will sell its electricity outputto NEK. It is an availability-based PPA where debt service,equity returns, and fixed costs are recovered through acapacity payment payable based on the availability of theplant. The actual price per unit of fuel is directly passedthrough. NEK is the second largest company in Bulgaria. It was initially established in 1992 as a vertically integratedstate owned utility. In the late 1990s NEK was unbundledinto generation, distribution and transmission companies.NEK was BB-rated by Standard & Poor’s with a negativeoutlook as of December 31, 2006. Although AES is notaware of any plans by the Bulgarian government to privatizeNEK in the future, the project benefits from a letter of support from the Bulgarian government in which it under-takes to ensure that any purchaser of NEK is able to continueto meet the obligations under the PPA. A breach of the sup-port letter is a breach of the PPA. It is also anticipated thatthe project will be granted sufficient emission credits underBulgaria’s Kyoto commitments. The project’s PPA includesprovisions to protect against increased operating costs as aresult of changes in law after the date of the agreement.

Fuel SupplyLignite will be supplied under a 15-year lignite supply agreement with MMI, a state-owned mining company,operating the largest lignite deposit in Bulgaria. The geologicalreserves of the mines were estimated at 2,173 million tons.The lignite produced at the mines is considered lowcalorific, high sulfur content fuel. The government supportletter has strong undertakings by the Bulgarian governmentin respect of the Maritza East I project to ensure propersuccession of the rights and obligations of the mines.

EPC AgreementThe EPC agreement was signed in 2002 and furtheramended in 2005 with a consortium comprising AlstomPower Generation AG and Alstom Power Boiler GmbH.Alstom has extensive experience in lignite-fired plants and FGD. Under the terms of the agreement the contractoris responsible for all work and services necessary for thedesign, engineering, procurement, construction, start-up,demonstration, testing, and commissioning of the plantand lignite handling facilities. Alstom will also supply all thematerials, equipment, machinery, labor and other servicesto complete the construction and start-up of the plant. Theguaranteed performance acceptance dates are 33 monthsand 36 months respectively for unit 1 and unit 2 after thefinal notice to proceed, which was given in August 2006.Should substantial completion be late or if the facility doesnot achieve 100% of its heat rate, liquidated damages maybe payable to Maritza East I. The contractor is also entitledto an early completion bonus.

Other Commercial AgreementsA 15-year supply agreement was signed with Ognianovo-KAD and Kaolin AD, local limestone suppliers. Ognianovoand Kaolin will supply up to 400,000 tonnes of limestoneper year to Maritza East I. Limestone costs are a pass-throughitem under the PPA tariff.

AES has established a separate wholly owned subsidiary toundertake the waste disposal services. The disposal companywill load gypsum and ash from the plant, via conveyors andtrucks, and transport the waste to the landfill for a period of 15 years. AES has provided a parent company guarantee ofup to €56 million to secure the funding of the waste disposalcapital costs associated with the construction of the wastedisposal facilities by the disposal company.

facilities through a syndicate of 29 lenders. German (HER-MES) and French (COFACE) export credit agencies andthe Multilateral Investment Guarantee Agency (MIGA) ofthe World Bank are providing political risk insurance or

guarantees to cover the lenders for a portion of the debt.Maritza East I is expected to generate about $300 millionin revenues annually at current exchange rates and fuelcosts over the term of the PPA.

7 8 A E S 2 0 0 6 FA C T B O O K


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The Cameroon power market is represented almostentirely by AES SONEL and accounts for almost 2% of thecountry’s GDP.

The law governing the electricity sector was passed inDecember 1998 and, together with subsequent ministerialdecrees and orders, governs the activities of the electricitysector. This includes setting rates, recovering and distribut-ing royalties due by operators in the sector, and spelling out required documents and charges for the processing ofapplications relating to various regulatory requirementsaffecting the sector. The regulator is the Electricity SectorRegulatory Agency (ARSEL) and its role is regulating andensuring the proper functioning of the electricity sector,maintaining its economic and financial balance and safe-guarding the interests of electricity operators and consumers.

ARSEL has the legal status of a Public AdministrativeEstablishment and is placed under the dual technical supervisory authority of the Ministries charged with electricity and finance.

The Concession agreement of July 2001 between theRepublic of Cameroon and AES SONEL covers a 20-yearperiod. The first three years constituted a grace period to permit resolution of issues existing at the time of the privatization and all penalties were waived. In 2006, AESSONEL and the Government of Cameroon signed anamended concession agreement. The amendment updatesthe schedule for investment to more than double the numberof people AES SONEL currently serves over the next15 years and provides for upgrading the transmission and dis-tribution system and investing in new generation capacity.

Capital YaoundeLargest city DoualaPopulation 17.3 million (7/06 est.)GDP $42 billion (2006 est.)GDP per capita $2,400 (2006 est.)

Economic drivers Agriculture (forestry, livestock, fishing, cocoa, cotton), crude oil, aluminum

Currency Communaute Financiere Africaine franc (XAF)Sovereign credit Fitch – B, Stablerating Moody’s – N/A, N/A

S&P – B–, Stable

COUNTRY FACTS



growth rate



(XAF:USD)



Thermal 10%90%Hydro

0%Nuclear0%Other

2002 4.2%4.7%11.6%

(6.9)%

7.8%

20033.6%2004

200220032004

2.4%20053.8%2006

0 100 –7 12 0 5 0 7000 5

2002 2.9%0.6%20030.3%2004

2.0%20054.5%2006

2002 696.99581.202003528.292004527.472005522.592006

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SONEL is the national electricity utility of Cameroon, with an installed capacity of 927 MW

and a service territory of approximately 475,000 km2.

SONEL provides electricity to over 538,000 customers. As of December 31, 2006, SONEL employed 3,048 people.


AES acquired a 56% interest in SONEL in July 2001 as partof the privatization process. SONEL has a 20-year concessionto generate, transmit and distribute electricity in most of the

Republic of Cameroon. The concession became effective inJuly 2001. SONEL is a public-private partnership betweenAES (56%) and the Republic of Cameroon (44%).

PHYSICAL ASSETS

SONEL’s distribution network is composed of three distinct sections. The Southern Interconnected Grid (SIG)serves the southern and central regions of the country,including the major population centers of Douala andYaounde. The Northern Interconnected Grid (NIG) servesthe three provinces in the northern region. The remotenetwork consists of 31 independent systems throughoutthe 10 provinces of Cameroon and provides electricity to38 isolated towns and centers.

SONEL’s installed capacity is 927 MW, including 77%hydroelectric, 20% grid-connected thermal, and 3% isolatedthermal capacity. The primary sources of generation includethree hydro plants and seven thermal plants. Two hydroplants, Song Loulou (384 MW) and Edea (263 MW), provideelectricity to the SIG. These plants and three associated

storage reservoirs are on the Sanaga River system. Thermalplants providing electricity to the SIG include: Limbe(85 MW), Bassa (19 MW),Oyomabang I (20 MW),Logbaba I (16 MW), Oyomabang II (13 MW), Bafoussam(14 MW), and Mefou (2 MW). All of the SIG thermalplants are diesel fired, except Limbe and Oyomabang I,which burn heavy fuel oil. Lagdo (72 MW) and Djamboutou(14 MW) provide electricity to the NIG. Lagdo is a hydroplant and Djamboutou is diesel fired. The remote networkconsists of 86 small diesel fueled units with a total of25 MW of capacity.

SONEL is currently constructing the Logbaba II heavyfuel oil facility with installed capacity of 13 MW. The plantis expected to come on line in 2007.


SALES & OPERATIONS

Electricity SalesSONEL provides electricity to over 538,000 customers, thevast majority of whom are located in the Douala andYaounde regions. Sales to Alucam, an aluminum smeltingventure, and four other large customers are governed bybilateral power purchase contracts. Over the last five yearsSONEL has made significant improvements in cash collectionfrom 89% in 2002 to 98.5% in 2006. 2006 GWh sold were

divided as follows: 29% residential, 18% commercial, 44%industrial, 8% public, and 1% other.

Fuel SupplyHeavy fuel oil is sourced directly from the national refinery(SONARA). Diesel is purchased under a two year contractwith MOBIL.

RECENT EVENTS

In December 2006 AES SONEL secured a 13-year $340 million (€260 million) financing package from a syndicate of developmental finance institutions. This non-recourse financing will be used to extend SONEL’s

network to previously unserved parts of the country,improve the reliability and efficiency of the generation,transmission and distribution systems, and more than double the number of people currently served.

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Bohemia is a 50 MW primarily coal-fired cogenerationplant located in the Czech Republic, approximately 90 kmsouth of Prague.

The facility supplies electricity, steam, water, and compressed airto industrial and municipal customers in the surrounding area.Seven contracted customers account for over 99% of revenues(excluding revenues from the Emissions Trading Scheme). As ofDecember 31, 2006, Bohemia employed 91 people.

AES acquired Bohemia from Thermo EcoTech in 2001.AES attained 100% ownership in 2002. The plant wasoriginally commissioned in the early 1960s but underwenta major upgrade in 1999, including a new steam turbinegenerator and a minor boiler upgrade. The assets consist ofone 50 MW steam turbine generator and three 65 tons per hour boilers. Bohemia has extensive water treatmentfacilities to support its other product lines.

Up to 100% of the capacity can be delivered under the contract signed in April 1998; its initial term runs throughDecember 2015. The main electricity offtaker is E.ONEnergie, a.s., a subsidiary of E.ON. The payment structure is

linked to the CEZ (state owned) supply price and is also par-tially regulated. The contract also contains a minimum annualescalator for inflation. Bohemia supplies heat as steam andhot water to a number of industrial users on the site and toone district heating company under long-term agreements.The heat price is regulated so price and volume are negotiatedon an annual basis for some of these contracts. Contract termsvary but those of the major offtakers run until 2014 or 2015.

Bohemia maintains competition in its fuel supply fromtwo mining companies. Bohemia has a fuel supply agreement(FSA) signed with Sokolovska Uhelna (SU) for the supply of low sulfur coal, representing 97.5% of its annual coal consumption. The contract with SU runs initially until 2012.Prices are defined in the contract; however, Bohemia has inrecent years secured prices lower than those specified in thecontract on an annual basis. Bohemia started to use biomass asfuel in 2004. Biomass currently accounts for 2% of the plant’stotal fuel. A future increase in biomass consumption willdepend on the availability of this fuel from local suppliers andits acceptability for the plant’s operations. The Government ofthe Czech Republic provides subsidies to generation facilitiesfor the use of renewable sources of energy.


Bo

he

mia

Capital PragueLargest city PraguePopulation 10.2 million (7/06 est.)GDP $221 billion (2006 est.)GDP per capita $21,600 (2006 est.)

Economic drivers Services (wholesale and retail trade, catering, financial services, tourism), industrial products

Currency Czech koruna (CZK)Sovereign credit Fitch – A, Stablerating Moody’s – A1, Positive

S&P – A–, Positive

COUNTRY FACTS



growth rate



(CZK:USD)




0%Other

2002 1.9%3.6%2.1%

(0.5)%

4.1%

20034.2%2004

200220032004

6.1%20055.9%2006

0 100 –1 5 0 7 0 350 3

2002 1.8%0.1%2003

2.8%20041.9%20052.6%2006

2002 32.7428.21200325.70200423.96200522.312006

Cze

ch R

ep

ub

lic


19 20 31


2001

Segment

Generation

Country

Czech Republic

Fuel

Coal/Biomass

AES EquityInterest

100%

MW

50


Hu

ng

ary

Re

gu

lato

ry O

verv

iew

Hu

ng

ary

The 2001 Electricity Act, which became effective inJanuary 2003, brought the Hungarian electricity marketinto accord with EU directives in terms of third partyaccess to the electricity grid and removal of subsidies, anddefines a market structure that includes electricity genera-tion companies, electricity distributors, power traders, and an electricity grid operator.

A company owned by Magyar Villamos Müvek Rt (MVM)operates the electricity grid and is the dominant exporter,importer and wholesaler of electricity. MVM owns andoperates the high voltage transmission grid and dispatchcenter. MVM purchases power from electricity generatingcompanies and sells it to smaller distribution companies. A gradual introduction of competition in the electricitymarket started in 2004, when the industrial users, constitutingabout 70% of total consumption, were allowed to choose theirelectricity suppliers. Independent power suppliers started towheel power through the grid, though the grid operatorwas allowed to add a transport/access tariff.

As a member state of the EU, the Hungarian government notified the European Commission (EC) of arrangements concerning compensation to the state owned electricity whole-saler, MVM. The EC opened a formal investigation in 2005 todetermine whether or not any government subsidies were provided by MVM to its suppliers. Although the EC has notcompleted its investigation, the Commissioner for Competitionhas indicated informally that she considers the long-term powerpurchase agreements (PPAs), including the contract with AES Tisza II to be contrary to applicable EU laws and hasencouraged the Hungarian government to terminate the PPAs.In December 2006 the Hungarian government carried outnegotiations with the EC on this issue. If the Hungarian authorities execute the Commission’s decision, they may seekto revise the contracts and /or require the repayment of certainfunds received by generators pursuant to the contracts.

Cheap electricity imports, focus on renewable sources ofenergy, new Large Combustion Plant Directive requirements,and a growing open market will be the main drivers that willimpact the near future of the Hungarian elec tricity sector.

Capital BudapestLargest city BudapestPopulation 10.0 million (7/06 est.)GDP $173 billion (2006 est.)GDP per capita $17,300 (2006 est.)

Economic drivers Services (telecommunications, banking, utilities),industries (manufacturing, construction mining,processed food, textiles)

Currency forint (HUF)Sovereign credit Fitch – BBB+, Negativerating Moody’s – A2, Stable

S&P – BBB+, Stable

COUNTRY FACTS


Generation sources Energy consumption

growth rate



(HUF:USD)




0%Other

2002 4.3%4.1%2.5%

2.6%

0.4%

20034.9%2004

200220032004

4.5%20054.3%2006

0 100 0 3 0 5 0 3000 7

2002 5.3%4.7%20036.8%2004

3.6%20053.9%2006

2002 257.89224.312003202.752004199.582005215.112006

8 2 A E S 2 0 0 6 FA C T B O O K

AES’s presence in Hungary consists of three plants: Tisza II, a 900 MW multiple fuel plant

located in northeast Hungary about 200 km from Budapest that primarily burns natural gas;

Tiszapalkonya, a 116 MW multi-fuel plant located in the northeast region of Hungary that

primarily uses coal; and Borsod, a 96 MW biomass and coal-fired facility in Kazincbarcika.

Tisza II is the third largest plant in Hungary, providing 7% of Hungary’s electricity generation. Tisza II is fully contracted

through 2016. Tiszapalkonya sells into the liberalized market and to a local distribution company, while Borsod

sells power under a short-term agreement. As of December 31, 2006, the plants employed a total of 488 people.


During the privatization of the Hungarian electricity sec-tor in the mid-1990s, AES acquired a controlling interest inthe three plants and a deep coal mine, through the purchasein 1996 of a 94% share of Tisza Eromu Rt., an electric generation company in Hungary. AES now owns 100% ofeach Hungarian business, having acquired the remainingshares between 1997 and 1999 from employees and localgovernment holders. The coal mine was sold in 2004.

Tisza II commenced commercial operation between 1977and 1978. In 2004, Tisza II completed a retrofit project,which extended the life of the station, reduced emissionsand allowed the four units to continue to sell power underthe PPA. Tisza’s environmental license expires in 2016, andits operation license from the Hungarian Energy Officeexpires in 2025.

Commercial operation of Tiszapalkonya started between1957 and 1959. Tiszapalkonya was originally designed andcommissioned as a 250 MW pulverized coal-fired plant toburn locally mined lower calorific value lignite. Followingthe completion of a biomass retrofit project in 2005,Tiszapalkonya is now a condensing and cogeneration powerplant of 116 MW.

Commercial operation at Borsod commenced in 1954;Borsod was originally a 180 MW coal-fired plant. InFebruary 2003, Borsod was the first power plant inHungary to enter the liberalized market, which had openeda month before. The favorable geographical location of theplant makes it possible to generate electricity from therenewable resource of firewood produced by the forestrycompanies in the area. The plant was converted into a96 MW biomass facility over the period of 2003 to 2005.The operation license of the facility expires in 2014.

PHYSICAL ASSETS

Tisza II consists of four units. The plant uses natural gasand light, sulfur-free fuel oil. The modern instrumentationsand control systems of the units ensure direct control forthe national electricity system operator. Between 2002 and2004, significant environmental modifications and lifeextension refurbishments were carried out.

Tiszapalkonya can burn coal, gas and biomass. The primaryfuel is coal. Tiszapalkonya has eight boilers, each with125 tons per hour nominal capacity. A continuous emissionsmonitoring system was installed in 1996.

Like Tiszapalkonya, Borsod can burn biomass, coal and gas.Woodchips are the primarily fuel, but other biomasssources include sawdust, sunflower seed shells, and otheragricultural byproducts and waste. The existing boilerswere refurbished between 1978 and 1985. Two boilers wererefurbished in 2003 and 2004, changing the fuel technologyto biomass (woodchips) and the fuel structure from theoriginal pulverized coal to a bubbling fluidized bed (BFB)boiler design. In 2004 and 2005, two more boilers werepartly refurbished and the fuel was changed from lignite tolow sulfur coal in order to meet environmental limits. Theprimary function of these boilers is to provide steam forBorsodChem Rt.

Hu

ng

ary

Ge

ne

rati

on


Co

mm

ence

men

t/A

cqu

isit

ion

19

96

Seg

men

t

Gen

erat

ion

Co

un

try

Hu

nga

ry

Fuel

Var

iou

s

AES

Eq

uit

yIn

tere

st

10

0%

MW

1,11

2


Electricity and Cogeneration SalesTisza II sells electricity to MVM under a 20-year PPA thatwill expire in December 2015 for the first two units and inDecember 2016 for the third and fourth units. The pricepaid by MVM includes both capacity and energy payments.As the variable cost of power generation is a pass-through,Tisza II bears neither fuel price nor volume risk. Basecapacity fees are set in Hungarian forints for the duration of the PPA, with yearly adjustments for local inflation.

Tiszapalkonya sells coal-based electricity to the liberalizedHungarian energy market. By the end of 2006, the biomassgeneration was reduced to the minimum and coal-basedelectricity sales to the liberalized market became the mainfocus. The plant also sells steam to the neighboring oil refineryMagyar Olaj es Gazipari Rt (MOL) under an agreementwhich will expire by the end of 2007. Tiszapalkonya alsosells steam to Tisza II.

Until September 2005, renewable electricity fell under acompulsory off-take requirement. Borsod had signed a five-year PPA with MVM through 2007, but that contractwas terminated by an amendment to the HungarianElectricity Act (HEA). As a result, Borsod entered into anelectricity supply agreement with the local distributioncompany EMASZ until December 2005, and this agreement

was extended also for 2006 and for 2007. The price ofelectricity supplied to EMASZ is subject to administrativepricing. Both biomass based and cogeneration-based electricity are sold at a premium price to EMASZ. Borsodalso has a long-term steam supply and a demineralizedwater supply agreement with the chemical companyBorsodChem Rt.

Fuel SupplyTisza II has a long-term fuel supply agreement with E.ONfor natural gas and with MOL for fuel oil, both of whichwill expire in 2016. Fuel costs at Tisza II are a pass-throughreflected in the energy payments received, providing thebusiness a natural hedge on its commodity risk.

Natural gas for Borsod and Tiszapalkonya is purchasedfrom the public utility wholesaler through annual contractsat regulated prices.

Borsod has 10-year renewable fuel supply agreements,where the fuel price is indexed to the electricity price, market fuel price and the Hungarian inflation index. Theadditional fuel suppliers are selected based on a competitivetendering process. Borsod uses black coal and brown coal,mainly from Russia, with low ash and low sulfur contentand a high calorific value.

Hu

ng

ary

Ge

ne

rati

on

SALES & OPERATIONS

In February 2006, the Hungarian government enacted legislation to amend the Hungarian Electricity Act (Act 110of 2001) to enable, among other things, the application ofregulatory pricing to the sale of electricity by generators tothe state owned utility wholesaler, MVM. In November 2006,the decree was signed and prices were issued. These priceswere subsequently revised upwards by a January 2007decree. The regulated price is lower than that specified in

the PPA between Tisza II and MVM. Tisza II is in theprocess of assessing the implications of this legislation,including the impact on its current power purchase andfinancing arrangements, and its ability to challenge there-introduction of administrative pricing. In January 2007,the Hungarian government issued a new decree raising thecapacity figure to 12,075 kHUF/MW/year and an energyfee cap of 21,250 HUF/MWh for Tisza II.

RECENT EVENTS

8 4 A E S 2 0 0 6 FA C T B O O K


Ka

zakh

sta

n R

eg

ula

tory

Ove

rvie

w

Under the present regulatory structure, the electricity gen-eration and supply sector in Kazakhstan is mainly regulatedby the government. The power market infrastructure iscurrently evolving into a functioning centralized tradingsystem. The government is planning to introduce a real-timebalancing market by 2008.

The primary wholesale market participants include generators,Kazakhstan Electricity Grid Operating Company (KEGOC),centralized power trading market operator KOREM, regionaldistribution companies (the RECs), Electricity SupplyOrganizations (ESOs), and a number of large end users whoare able to take electricity directly from a generator or theNational Power Grid and trading companies.

Since 2004, power producers, guaranteed suppliers andwholesale traders have been required to purchase and sellpart of their electricity volumes on the electronic centralizedpower trading market.

KEGOC owns and operates the national power grid. RECs provide electricity distribution from the high-voltage lines toend users, and like KEGOC, purchase power from generators to cover distribution losses. ESOs purchase electricity from

generators, pay transmission and distribution tariffs to KEGOCand the local REC, and resell electricity to retail customers.

Retail tariffs are regulated due to a lack of ESOs (retailcompanies). At the same time, certain generators and largeindustrial customers formed the Pool REM to providereserve capacity to smooth out power imbalances.

The Agency for Regulation of Natural Monopolies(Agency) approves and regulates all tariffs for power trans -mission and distribution. It sets actual price tariffs ratherthan a formula that would allow automatic tariff increases.

The Committee for Protection of Competition (Committee)approves tariffs of entities which are “dominant entities” in a particular commodity market. Ust Kamenogorsk CHP,owned by AES, and Ust-Kamenogorsk and Shulbinsk, hydroplants operated by AES on a concession basis, are currentlylisted as dominant entities. These businesses must seekapproval from the Committee to increase the tariffs for powersupplied to customers in East Kazakhstan. NurenergoserviceLLP and DostykEnergo LLP are two AES trading companiesthat participate in the Kazakhstan power markets.

Capital AstanaLargest city AlmatyPopulation 15.2 million (7/06 est.)GDP $139 billion (2006 est.)GDP per capita $9,100 (2006 est.)

Economic drivers Industrial products (crude oil, minerals and metals,equipment manufacturing), services

Currency tenge (KZT)Sovereign credit Fitch – BBB, Positiverating Moody’s – Baa2, Stable

S&P – BB, Stable

COUNTRY FACTS



growth rate



(KZT:USD)




2002 9.8%9.3%4.7%

1.5%

8.5%

20039.4%2004

200220032004

9.7%200510.6%2006

0 100 0 9 0 11 0 1600 9

2002 6.0%6.5%20036.9%20047.6%20058.6%2006

2002 153.28149.582003136.042004132.882005125.562006

Ka

zakh

sta

n


Co

mm

ence

men

t/A

cqu

isit

ion

19

96

–20

01

Seg

men

t

Gen

erat

ion

Co

un

try

Kaz

akh

stan

Fuel

Co

al/H

ydro

AES

Eq

uit

yIn

tere

st

10

0%

MW

6,68

8*A

ES K

aza

khst

an

AES’s portfolio includes one coal-fired plant, two coal-fired cogeneration plants, one coal

mine and the concessions for two hydroelectric plants.

AES also manages one heat distribution network company, an electricity distribution company and an electricity

retail company owned by the state. With a total capacity of 6,688 MW* (including owned or operated assets), AES

is the largest generator in Kazakhstan, generating 18% of all electricity in the country. Additionally, AES represents

approximately 55% of the merchant market. The heat distribution network serves 95,000 customers. The distribution and

retail companies serve 460,000 customers. The businesses owned and managed by AES in Kazakhstan employed

over 6,200 people as of December 31, 2006.


In August 1996, AES purchased Ekibastuz from the govern-ment of Kazakhstan. Initially AES owned a 70% interestwith minority shares held by a third party. In September 1999AES purchased the remaining 30% interest.

In 1997, AES acquired 100% ownership of the cogenerationheating plants (CHP), Ust-Kamenogorsk CHP and SogrinskCHP, and a 20-year concession for two hydroelectric powerplants (HPP), Ust-Kamenogorsk HPP and Shulbinsk HPP in the Eastern Kazakhstan region. In order to have direct

access to the ultimate customers, AES obtained long-termmanagement control of the state-owned Ust-KamenogorskHeat Nets system in 1998. In addition, in 1999AES negotiateda long-term management agreement for control of a distribution company, East Kazakhstan Regional ElectricityDistribution Company (REC). This control provides a reliable customer base for the generation assets and enablesdirect control of end-user collections. AES acquired 100%interest in Maikuben West coal mine in September 2001 froma local private company in a bankruptcy proceeding.

PHYSICAL ASSETS

AES’s primary assets in Kazakhstan include Ekibastuz, theAltai group of businesses (Altai Group), and Maikuben West.

Ekibastuz is a nameplate 4,000 MW coal-fired plant locatedin the Pavlodar region. The plant is composed of eight500 MW turbines that were originally commissionedbetween April 1980 and December 1984. As of December 31,2006, the plant was operational with a total available genera-tion capacity of 2,020 MW. Ekibastuz’s five operational gen-erating units are in the process of rehabilitation which willbring the plant to approximately 2,500 MW by 2013 at thetotal investment cost of around $200–250 million. The otherthree cold blocks (1,500 MW) can be returned to servicedepending upon continued demand growth in the market,price regulation, continuation of price increases in thewholesale market and the ability to execute long term powersupply contracts.

Altai Group in Eastern Kazakhstan is a combined businessthat has thermal and electrical capacity of approximately

2,688 MW. Altai Group consists of the following businesses:two AES-owned cogeneration plants, Sogrinsk CHP andUst-Kamenogorsk CHP; two hydro electric plants on theIrtish River, Ust-Kamenogorsk HPP and Shulbinsk HPP, for which AES has 20-year concessions, expiring in 2017;Ust-Kamenogorsk Heat Nets, a heating company that ismanaged by AES; a distribution company, East KazakhstanREC and a Retail Business, Shigyz Enezgo Tzade that aremanaged by AES.

Sogrinsk CHP is a coal-fired cogeneration plant with 301 MWthermal capacity that uses heavy oil as a back-up fuel. SogrinskCHP originally commenced operations in 1961. Ust-Kamenogorsk CHP is a pulverized coal-fired cogenerationplant with 1,354 MW of thermal capacity. It began operationsin 1947.

Ust-Kamenogorsk HPP is a 331 MW hydro plant on theIrtish River commissioned in the 1950s. Shulbinsk HPP is a702 MW hydro plant on the Irtish River, 70 km upstream


* MW number provided includes gross generating capacity of Ekibastuz, Shulbinsk HPP and Ust-Kamenogorsk HPP, and thermal capacity of the cogeneration plants Sogrinsk CHP and Ust-Kamenogorsk CHP.

8 6 A E S 2 0 0 6 FA C T B O O K

from the town of Semipalatinsk that was commissionedbetween 1987 and 1994. The reservoir of Shulbinsk HPP isdesigned for compensatory regulation of the Irtish Riverwater flow, and storage of side inflows from the Ulba and Uba tributaries to be used for electricity generation, as well as spring irrigational flooding and water supply to towns andsettlements. The concessions for Shulbinsk HPP and Ust-Kamenogorsk HPP were recently modified such that theKazakh government is entitled to a flat $750,000 annual royalty for each plant. This arrangement replaced the previ-ous requirement to pay one-third of the plants’ “clear profits.”AES does not currently expect to renew its concessions forthese plants in 2017.

Ust-Kamenogorsk Heat Nets provides transmission and distribution of heat. It has six boiler plants with a total heatgenerating capacity of 224 GCal, and heat distribution network of 337 km.

Maikuben West is an open-pit coal mine located approxi-mately 66 km from the Ekibastuz power plant. As ofDecember 31, 2006, the mine’s estimated reserves werenearly 800 million tons. AES plans to invest $20 million overthe next five years to increase production by approximately15% each year.

AES

Ka

zakh

sta

n

SALES & OPERATIONS

Electricity SalesEkibastuz sells electricity under contracts that typically rangein duration from one month to one year. Approxi mately 75%of sales are to local customers and distribution companies,with about 25% of sales to Russia. The sales strategy of Ekibastuzis to focus on long-term contracts, enabling prudent investmentsto improve reliability, environmental safety, and increasecapacity. Ekibastuz has recently signed a 10-year agreementto supply 45 MW to a new silicon plant. A memorandum ofunder standing was also signed with SUAL Group inAugust 2006 on a future 1,000 MW power supply for anew aluminum smelter in Kazakhstan. If the final terms are acceptable to AES, such long-term contracts willrequire rehabilitation of one or two currently cold blocks at the plant.

Sogrinsk CHP sells electricity through annually renewedcontracts, negotiated with counterparties. The primary cus-tomer is JSC Ust-Kamenogorsk Titanium and MagnesiumPlant. Ust-Kamenogorsk CHP also sells electricity throughannually renewed contracts. Contracts with state-ownedentities are typically obtained through open bids, while contracts with industrial customers are negotiated. State-ownedcustomers include UMZ JSC, EK REK JSC, and ShygysenergoTrade LLP. Kazzinc JSC is a main industrial customer.

Ust-Kamenogorsk HPP and Shulbinsk HPP sell nearly all of their electricity to AES’s 100% owned trading company,Nurenergo Services. Nurenergo resells most of this power toindustrial customers and to Shygyzenergo Trade, a retail com-pany managed by AES in Eastern Kazakhstan.

Heat SalesThe majority of the electricity at Sogrinsk CHP and Ust-Kamenogorsk CHP is generated in combined cycle. The main heat consumers include UMZ JSC, Kazzinc JSC,TMK JSC and Ust-Kamenogorsk Heat Nets JSC.

Coal SalesMaikuben West extracts and sells coal to AES entities inKazakhstan, and to third parties in Kazakhstan, Kyrgystan,and Russia. Domestic sales represent approximately 93% ofrevenues. In 2006, Maikuben West sold 1.2 million tons tothe Ekibastuz power plant, 0.75 million tons to other AESplants, and 1.95 million tons to other customers. The coal issold under annual and seasonal contracts. All coal contracts,except for intercompany contracts and the sales contractwith Mittal Steel, at present require prepayment. Whilethere is no current forward coal market in Kazakhstan, AEShas received indications of interest for long-term coal supplyagreements from certain combined heat and power plantsseeking to match their fuel costs with their tariffs.

Water RightsUst-Kamenogorsk HPP and Shulbinsk HPP use waterresources from the Irtish river based on licenses of theMinistry of Agriculture of the Republic of Kazakhstan issuedin 2005, and expiring in 2017. The fee for utilization of waterresources is 0.0115 Kazakhstan tenge (KZT) per kWh.

Fuel SupplyEkibastuz purchases coal from Bogatyr and Maikuben Westcoal mines. Maikuben West supplies approximately 30% ofthe coal required for Ekibastuz. Maikuben West is furtheraway, and the coal has higher transportation costs. Ekibastuzintends to continue to source the majority of its coal fromBogatyr, and expects to use Maikuben coal as a fuel costhedge for its long-term power purchase agreements, or insummer months, when power demand is lower.

Major coal suppliers for Sogrinsk CHP and Ust-KamenogorskCHP include Energoresurs Ltd and Maikuben West.


Elst

aN

eth

erl

an

ds

Elsta* is a gas-fired 460 MW/1,350 metric tons/hr steamcombined cycle, combined heat and power facility withtotal thermal capacity of 630 MW located in Terneuzen,The Netherlands.

Elsta is a fully contracted business with three offtakers:Dow Benelux under a 20-year steam and electric powersales agreement (SEPSA), and Delta and PNEM (EssentEnergy) under 20-year electric sales agreements. The con-tracts expire in September 2018 and are capacity based,indexed to inflation, and structured as tolling arrangements,by which the offtakers supply all fuel required. The contractsmay be extended for two five-year periods. The plant provides Dow with a considerable proportion of its steamrequirements and so runs continuously. The overall loadfactor of the plant is around 80%.

AES acquired its interest in Elsta in June 1997 as part of theDestec acquisition. Elsta is a joint venture, 50% owned byAES. Essent and Delta each own 25% of the business. Theplant commenced operations in September 1998. Two whollyowned AES subsidiaries operate and manage the plantunder 20-year agreements with the partnership. Elstaemployed 41 people as of December 31, 2006.

The plant consists of three gas turbines, three heat recov-ery steam generators and a single steam turbine. The tur-bines are fitted with dry low NOx combustors that arerequired to maintain NOx emissions below current andforeseeable permit levels in the Netherlands.


4 5 6


1997

Segment

Generation

Country

Netherlands

Fuel

Gas

AES EquityInterest

50%

MW

630*



Capital AmsterdamLargest city AmsterdamPopulation 16.5 million (7/06 est.)GDP $512 billion (2006 est.)GDP per capita $31,700 (2006 est.)

Economic drivers Services (commercial services include trade, finan-cial services), industrial products (food processing,chemicals, petroleum refining)

Currency euro (EUR)Sovereign credit Fitch – AAA, Stablerating Moody’s – Aaa, Stable

S&P – AAA, Stable

COUNTRY FACTS



growth rate



(EUR:USD)

Thermal 93%0%

2%

HydroNuclear

5%Other

2002 0.1%0.3%1.2%

1.1%

0.7%

20032.0%2004

200220032004

1.5%20052.9%2006

0 100 1 2 0 3 0 20 4

2002 3.3%2.1%2003

1.3%20041.7%20051.2%2006

2002 1.060.8920030.8120040.800.80

20052006

* AES’s investment in Elsta is accounted for using the equity method; consequently, only management fees are included in consolidated revenues.

8 8 A E S 2 0 0 6 FA C T B O O K

Nig

eri

aEb

ute

Ebute is a 304 MW natural gas-fired generation plant locatedon barges in Egbin, Lagos, Nigeria. These units furnishapproximately 8% of the nation’s electricity to Nigeria’snational electrical distribution company through a linkwith the nearby Egbin Thermal Station. As of December 31,2006, Ebute employed 80 people.

Ebute was originally developed to provide emergencypower to Lagos State. However, due to the insufficientenergy supply within Nigeria, the plant became a base-loaded power generation station operating under a PPAwith the Power Holdings Company of Nigeria (PHCN).AES purchased Ebute from Enron in 2000. Constructionbegan in October 2000 and commercial operationcommenced in June 2001. AES owns 95% of Ebute; theremainder is owned by Yinka Folawiyo Power, a privatelyheld conglomerate in Nigeria with investments in oil andgas exploration and production, shipping, banking, andproperty development.

Ebute is composed of nine barge-mounted gas turbine unitswith a nominal capacity of approximately 30+ MW each.

Ebute sells electricity to PHCN under a 13-year PPA that became effective in October 2001 and expires inNovember 2014. Under the PPA, following any privatizationof PHCN, Lagos State will become the power purchaser.The Federal Government of Nigeria is the guarantor of allthe payment obligations of PHCN and Lagos State. Thebusiness also benefits from a $60 million letter of credit,which is in place to back the purchaser’s payment obligations under the PPA. Ebute receives a fixed capacity payment in U.S. dollars under the PPA.

Fuel is supplied at no cost by PHCN under the PPA untilprivatization. Under the PPA, following privatization ofPHCN, a fuel supply contract will need to be arrangedunder which all energy costs will be passed through to thepurchaser. In either case, Ebute takes no fuel price risk.

Ebute also has a long-term service contract with MasaoodJohn Brown and a long-term parts agreement with ETSTechnical Services. The project benefits from OPIC politicalrisk insurance for the equity invested in the project, whichcovers the risks of inconvertibility, expropriation, andpolitical violence.



Capital AbujaLargest city LagosPopulation 131.9 million (7/06 est.)GDP $189 billion (2006 est.)GDP per capita $1,400 (2006 est.)

Economic drivers Crude oil, agriculture (livestock, forestry and fishing), services

Currency naira (NGN)Sovereign credit Fitch – BB–, Stablerating Moody’s – N/A, N/A

S&P – BB–, Stable

COUNTRY FACTS



growth rate



(NGN:USD)

Thermal 67%33%

0%

HydroNuclear

0%Other

2002 3.8%10.4%(6.4)%

39.3%

(1.4)%

20036.4%2004

200220032004

6.2%20054.2%2006

0 100 –7 40 0 11 0 1350 18

2002 13.0%14.1%200315.0%200417.9%2005

9.8%2006

2002 120.48129.222003132.892004132.59127.57

20052006


66 68 63


2001

Segment

Generation

Country

Nigeria

Fuel

Gas

AES EquityInterest

95%

MW

304


Sp

ain



Capital MadridLargest city MadridPopulation 40.4 million (7/06 est.)GDP $1,070 billion (2006 est.)GDP per capita $27,000 (2006 est.)

Economic drivers Services (tourism, retailing, and telecommunications),industries (vehicle manufacturing and construction),agriculture (wine, produce)

Currency euro (EUR)Sovereign credit Fitch – AAA, Stablerating Moody’s – Aaa, Stable

S&P – AAA, Stable

COUNTRY FACTS



growth rate



(EUR:USD)

Thermal 52%25%

12%

HydroNuclear

10%Other

2002 2.7%3.0%5.0%

4.0%

5.5%

20033.3%2004

200220032004

3.5%20053.4%2006

0 100 1 6 0 4 0 20 4

2002 3.5%3.0%20033.0%20043.4%20053.5%2006

2002 1.060.8920030.8120040.800.80

20052006


2 8 11


2006

Segment

Generation

Country

Spain

Fuel

Gas

AES EquityInterest

71%

MW

1,200

Cartagena* is a 1,200 MW combined cycle gas-fired facility at Escombreras, Puerto de

Escombreras, Cartagena, in Murcia province, on the southeastern coast of Spain.

Cartagena is located in the vicinity of an LNG import terminal. The output of the plant is sold into the Spanish whole-

sale electricity market (OMEL). However, Cartagena has hedged all electricity and gas market risk via a 21-year energy

conversion agreement with GDF International (GDFI). The plant employed 58 people as of December 31, 2006.


The project was financed using approximately 80% non-recourse debt and 20% equity. Financial close underCartagena’s long-term non-recourse debt facility occurredin August 2003, with construction beginning the samemonth. Non-recourse financing for the project was providedby a syndicate of European banks including Société Générale,Calyon and ABN AMRO BANK NV as lead arrangers, as

well as a subordinated debt facility provided by SociétéGénérale and Calyon. The financing structure was recognizedregionally by Euromoney as “European IPP of the Year 2003.”Also in 2003, GDFI and Mitsubishi Heavy Industries(MHI) exercised their options to purchase 26% and 3% ofCartagena, respectively. AES owns 71%. Commercial opera-tion started in November 2006. The total cash funded proj-

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* AES’s investment in Cartagena is accounted for using the equity method, only management fees are included in consolidated revenues.

9 0 A E S 2 0 0 6 FA C T B O O K

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PHYSICAL ASSETS

Cartagena consists of three power blocks, each block includ-ing a gas turbine, heat recovery steam generator and threeindividual steam turbines. The plant will normally operate

on natural gas but has the capability to be commissioned tooperate on oil as a back-up fuel.

SALES & OPERATIONS

Electricity SalesCartagena has an energy conversion agreement with GDFIwhose parent, Gaz de France (GDF), was rated AA– byS&P as of December 31, 2006. Under the terms of theAgreement, GDFI will supply gas to Cartagena for conver-sion into electricity and sale into the electricity market.This agreement commenced at commercial operation andwill terminate in November 2028. Cartagena must forwardto GDFI all revenues received for the sale of electricalcapacity, energy and ancillary services from OMEL. Inreturn, GDFI will make payments to Cartagena. Thecapacity payment is a fixed monthly payment that com-prises approximately 95% of Cartagena’s revenue. Otherpayments include a yearly capacity payment adjustmentand a variable O&M payment. The agreement also providesfor reliability and heat rate bonuses/penalties, which arecapped both ways at €4 million each.

The National Allocation Plan for CO2 allowances has been finalized by the Spanish government. Under the termsof the energy agreement with GDFI, all cost and benefitsderiving from CO2 are passed on to GDFI.

Fuel SupplyLNG is supplied under the terms of the previously mentionedenergy agreement with GDFI.

Other Commercial AgreementsA long-term service agreement with Mitsubishi has beenentered into for six years, with the possibility for an extensionof the same period.

Since start-up the plant has met the expected availabilityratios. Currently it is operating at a 20% capacity factorand an average 97.9% availability factor. On average theplant’s combined heat rate is 6,500 kJ/kWh.

ect cost was approximately $940 million (excludes letters ofcredit to GDFI and guarantees to the market and system

operator). All key contracts run in accordance with the siteconcession, which terminates in 2028.


AES acquired a 51% stake in two hydroelectric powerplants and a 390 MW development pipeline in Turkey inMay 2007, through its acquisition of a controlling interestin IC Ictas Energy Group. The plants are both located inthe province of Erzincan in Turkey.

The Girlevik II-Mercan hydroelectric plant consists oftwo run-of-the-river type power plants, both situated inone building at an altitude of 1,220 meters above sea level.The total installed capacity of Girlevik II-Mercan is 12 MWand its annual generation output is approximately

40 GWh. The Yukari Mercan hydroelectric plant is a run-of-the-river plant situated at an altitude of 1,467 metersabove sea level. The installed capacity of Yukari Mercan is 14 MW, producing an annual generation output ofapproximately 44 GWh.

The development pipeline is composed of 18 greenfieldhydro projects with an aggregate capacity of 390 MW. AES expects to commence construction on certain projectsin the pipeline in late 2007.

Turk

eyTu

rkey

Ge

ne

rati

on

Capital AnkaraLargest city IstanbulPopulation 71.2 millionGDP $636 billion (2006 est.)GDP per capita $9,000 (2006 est.)

Economic drivers Services, industries (textiles and clothing, auto -mobiles, electronics), agriculture

Currency Turkish lira (TRY)Sovereign credit Fitch – BB–, Stablerating Moody’s – Ba3, Stable

S&P – BB–, Stable

COUNTRY FACTS



growth rate



(TRY:USD)

Thermal 65%35%Hydro

0%Nuclear0%Other

2002 7.9%5.8%6.2%

4.7%

6.0%

20038.9%

7.4%2004

200220032004

6.1%

20052006

0 100 0 7 0 9 0 20 50

2002 45.0%25.3%

8.6%20032004

8.2%20059.5%2006

20021.501.51

20031.4320041.3420051.432006


n/a n/a n/a


May 2007

Segment

Generation

Country

Turkey

Fuel

Hydro

AES EquityInterest

51%

MW

26



* Business acquired in May 2007.

9 2 A E S 2 0 0 6 FA C T B O O K

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Capital LondonLargest city LondonPopulation 60.6 million (7/06 est.)GDP $1,903 billion (2006 est.)GDP per capita $31,400 (2006 est.)

Economic drivers Services (financial and business services, communications); industry production, construction

Currency British pound (GBP)Sovereign credit Fitch – AAA, Stablerating Moody’s – Aaa, Stable

S&P – AAA, Stable

COUNTRY FACTS



growth rate



(GBP:USD)

Thermal 80%2%

16%

HydroNuclear

2%Other

2002 2.1%2.7%0.9%

0.1%

(1.1)%

20033.3%2004

200220032004

1.9%20052.6%2006

0 100 –2 1 0 4 0 10 3

2002 1.3%1.4%20031.3%20042.0%20052.3%2006

2002 0.670.6120030.5520040.550.54

20052006


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Kil

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Kilroot is a 520 MW dual oil/coal-fired generation plant located in Carrickfergus, Northern

Ireland, approximately 20 km from Belfast.

Kilroot employed 100 people as of December 31, 2006. The plant is fully contracted to Northern Ireland Electricity

(NIE). Kilroot is the second largest plant in Northern Ireland.


Kilroot began operations in 1981 as a purely oil-fired facility, but was converted to coal fueling in 1986 to 1989.It was acquired by AES in a privatization purchase in 1992.

Kilroot is 97.5% owned by AES; the remaining 2.5% isowned by present and past employees.

SALES & OPERATIONS

Electricity SalesKilroot sells electricity to NIE under a power stationagreement (PSA) and associated generating unit agreements(GUA). The PSA and GUA run to 2024. Under the GUA,certain payments are made to Kilroot in UK pounds.Availability payments are payments for available capacity,and are indexed to the UK retail price index. These pay-ments are intended to cover debt service, provide a returnon equity invested, and cover the project’s non-fuel opera-tion and maintenance costs. Energy payments are pay-ments to cover fuel costs and are based on a market indexprice and a contractual heat rate.

Fuel SupplyCoal is purchased on an annual basis. Price and volume arehedged against the requirements of NIE. Coal is largelysourced in South Africa and delivered to Hunterstown, adeep-water port in Scotland. It is then transshipped insmaller vessels to Kilroot. Heavy fuel oil is bought on thespot market as required and delivered to Kilroot’s oil terminal,Cloghan Point, which is located about 3 km from the plant.During 2005 and 2006, biomass fuel trials were pursued,but stopped due to changes in the UK government’s incentives for co-fired renewables in the short term.

RECENT EVENTS

Kilroot is required to comply with the requirements of theRevised European Large Combustion Plant Directive byJanuary 1, 2008. This will require a reduction in the emissionlevels of SO2 and NOx. To achieve this Kilroot is investingheavily to install seawater process flue gas desulfurizationand carry out primary NOx modifications to the furnace.The design work began in the first quarter of 2006, and site

work started in September 2006. The project completionis expected in early 2008. Approximately $48 million inrelated capital expenditures were made in 2006. Thesecapital expenditures and any incremental related O&Mcosts will be recoverable via increased capacity payments inthe PPA with the offtaker, NIE.

PHYSICAL ASSETS

The facility utilizes two 260 MW turbines and two 930 tons per hour steam boilers. The plant operates primarily on coalat base load.


9 4 A E S 2 0 0 6 FA C T B O O K


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The electricity sector in Ukraine is regulated by theNational Energy Regulatory Commission (NERC). TheNERC is composed of five commissioners appointed by the President of Ukraine for terms of six years. Other stakeholders in the regulatory process include the Ministry of Fuel and Energy, Parliament, the AntimonopolyCommittee, the Cabinet of Ministers and the EnergyCompany of Ukraine (ECU).

Electricity costs to end users in the Ukraine consist ofthree main components. The wholesale market tariff is theprice at which a distributor purchases electricity in thewholesale electricity market. The distribution tariff coversthe cost of transporting electricity over the distributionnetwork. The supply tariff covers the cost of supplyingelectricity to an end user. The distribution and supply tariffsfor the six privatized distribution companies in Ukraine areestablished by the NERC based on a five-year tariff structure.However, the tariffs are adjusted on an annual basis forinflation, for the amount of capital that was invested inthat year, and the amount of energy that was distributed.

Ukraine’s wholesale energy market is structured as a singlebuyer market model. Generators sell power to the wholesaleenergy market either via a competitive price bid process,bidding no lower than actual fuel cost (thermal generators)or at tariffs set by the NERC that include fuel cost (nuclear,CHPs) or water usage fees (hydro). Suppliers purchase from thewholesale energy market at the weighted average wholesaleprice, which has a generation fuel cost in it. Thus, generationfuel cost is fully passed through to the end users, which protectssuppliers from generation fuel cost fluctuation. There are nomechanisms in place for mitigating generation fuel pricevolatility borne by the end users.

Due to Parliamentary elections in 2006, significant staffchanges occurred in the key regulatory agencies. In particular,a new Minister of Energy and a new Chairman of the NERCwere appointed. Since then NERC twice authorized 25%increases in end user tariffs for residential customers. Suchtariffs had been fixed since 1999. A further increase expectedin 2007 will reach the actual cost of service to residentialcustomers, and will allow cross subsidization betweenresidential and industrial customers to decrease.



Capital KievLargest city KievPopulation 46.7 million (7/06 est.)GDP $356 billion (2006 est.)GDP per capita $7,600 (2006 est.)

Economic drivers Industry (heavy industry, metals, chemicals, food-processing), services

Currency hryvnia (UAH)Sovereign credit Fitch – BB-, Positiverating Moody’s – B1, Positive

S&P – BB-, N/A

COUNTRY FACTS



growth rate



(UAH:USD)

Thermal 69%8%

23%

HydroNuclear

0%Other

2002 5.2%9.6%2.4%

0.3%

3.9%

200312.1%2004

200220032004

2.6%20056.8%2006

0 100 1 4 0 13 0 60 14

2002 0.7%5.2%20039.0%2004

13.5%20059.0%2006

2002 5.335.3320035.3220045.125.05

20052006


Ukr

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ibu

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AES owns two distribution companies in the Ukraine that serve approximately 1,236,000

customers with 5,586 GWh of electricity delivered in 2006.

Kievoblenergo serves approximately 833,000 customers in a service area of 28,100 km2 surrounding Kiev, the

capital of Ukraine. Rivneenergo serves approximately 403,000 customers in a service area of 20,100 km2 in the

Rivne region in eastern Ukraine. Together, the two companies employed 4,332 people as of December 31, 2006.


AES acquired 75% of Kievoblenergo and Rivneenergo inMay 2001 through a privatization sale from the State PropertyFund of Ukraine for approximately $46 million and $23 million,

respectively. AES has since increased its ownership to 89%and 81%, respectively; the remaining shares are dispersedamong numerous institutions and individuals.

SALES & OPERATIONS

Electricity SalesWhile effectively 100% of the regional consumption intheir respective service territories is supplied by Kievoblenergoand Rivneenergo, their licenses to operate are not exclusive.Customers can elect to purchase electricity from independentelectricity suppliers, who then pay a distribution fee to Kievoblenergo or Rivneenergo for using their distribution networks.

Kievoblenergo’s 2006 GWh sold consisted of approximately23% residential, 26% commercial, 25% industrial, 7% government and 19% other customers. Rivneenergo’s 2006GWh sold consisted of approximately 20% residential, 6%commercial, 60% industrial, 4% government and 9%other customers.

Kievoblenergo and Rivneenergo sell at regulated tariffs, asdescribed on page 94. AES expects that the methodologyapplied for the calculation of tariffs for Kievoblenergo andRivneenergo will evolve in 2007 according to methodologyprovisions approved in 2001: the rate of return on newinvestments will decrease from 17% after tax to about 14%,and technical and commercial loss allowances will decrease.

In 2008, it is expected that the rate of return on initialinvestment will be revised with a floor of 11% and that commercial losses will not be allowed in the tariff. The regulatory treatment of operational expenses in the tariff is expected to be revised as well.

In October 2006, Kievoblenergo and Rivneenergo submittedtheir 2007 Investment Programs for review to the NERC.The Investment Program for Rivneenergo was approved inthe amount of $9 million (including 20% VAT) and forKievoblenergo in the amount of $18.1 million (including20% VAT) as of January 1, 2007.

Energy SupplyKievoblenergo purchases 99.9% of its electricity in thewholesale electricity market. The other 0.1% is purchasedfrom embedded generation sources, including 2 MWhydroelectric capacity. Rivneenergo purchases 100% of its electricity in the wholesale electricity market.


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6

AES

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GW

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5,58

6

9 6 A E S 2 0 0 6 FA C T B O O K

HIGHLIGHTS

■ Seven countries: China, India, Jordan, Oman, Pakistan, Qatar and Sri Lanka






■ Key drivers: economic growth and electricity demand; new legislation and regulations; greenfield development opportunities; privatization of state-owned electricity businesses

AES’s operations in Asia and the Middle East stretch from the

Persian Gulf, to the Hindustan Peninsula and the East China Sea.

This region has tremendous potential for growth, and AES plans

to remain a key active player in this growing market.

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9 73 : B U S I N E S S D E S C R I P T I O N S – A S I A A N D M I D D L E E A S T

CONTENTS

ASIA & MIDDLE EAST

CHINA 98

China Regulatory Overview 98

Chigen 99

INDIA 103

OPGC 103

JORDAN 104

Amman East 104

OMAN 105

Oman Regulatory Overview 105

Barka 106

PAKISTAN 107

Pakistan Regulatory Overview 107

Pakistan Generation 108

QATAR 109

Qatar Regulatory Overview 109

Ras Laffan 110

SRI LANKA 111

Kelanitissa 111

Stretching from the Red Sea to the East China Sea, the

disparate markets across this expansive region share one

thing in common: exciting potential for growth. AES had

the foresight to get into these markets early and to build for

the long term. AES started developing projects in India and

Pakistan in 1992 and entered the China market in 1994.

In 1996, AES joined with Chinese partners to build Yancheng,

the country’s first “coal by wire” power plant. Today

Yancheng sends 2,100 MW of power to the densely populated

coast. In India, AES successfully participated in the country’s

first generation privatization in 1998. In the Middle East,

AES owns and operates two power and water desalination

plants – the first independent water and power facilities of

their kind in Oman and Qatar. In Pakistan, where AES has

been active for more than a decade, the Lal Pir/Pak Gen

facility is one of the largest independent power producers

in the country. In April 2007, AES expanded into Jordan,

where it is constructing the first independent power project,

a 370 MW combined cycle gas-fired power plant outside

of Amman.

Asi

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9 8 A E S 2 0 0 6 FA C T B O O K


Ch

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In 2002 a new industry regulator, China’s NationalElectricity Regulatory Commission (CERC) was estab-lished to promulgate the rules, supervise the operation ofthe electric power industry and administer electric powerservice licenses. Over the last two years, a large amount ofnew electric capacity was added to the system. As a result,electricity supply and demand in China reached equilibriumin 2006, and it is expected that some regional power gridswill experience supply surplus in 2007 and 2008.

In April 2005, with a view to implementing power industry reform, the National Development and ReformCommission (NDRC) released Interim Regulations governing on-grid, transmission and retail tariffs. Pursuantto the Interim Regulations, prior to adoption of a poolingsystem, the on-grid tariffs shall be appraised and ratified bythe pricing authorities and shall allow independent powerproducers to recover reasonable costs and obtain reasonablereturns. Such costs shall be comparable with average industrycosts. Reasonable returns shall be formulated on the basisof the interest rates of China’s long-term treasury bonds. At this stage it is uncertain when these provisions will be

implemented, and what effect they might have on Chigen’sbusinesses. In the long-term, foreign investors might beunder pressure to renegotiate their PPAs. China’s centralgovernment allowed the on-grid tariffs to be pegged to the fuel price in the case of significant fluctuations in fuelprice. Seventy percent of the increase in fuel costs may bepassed to the tariff. Subsequently, the tariffs of Chigen’scoal-fired facilities were increased in 2005 and 2006 toalleviate the escalation of fuel prices.

In January 2007, NDRC issued a regulation requiring inefficient conventional fossil-fired power plants, andplants with unit capacity below 50 MW to be shut down in order to achieve energy efficiency and environmental protection objectives. This ruling may have an adverseimpact on Chigen’s small businesses in China. However,this regulation also contains a provision stipulating thatforeign investment projects approved before 1999 mayapply for a reprieve from the shutdown. Such reprieve issubject to annual review. Some of Chigen’s smaller projectsare likely to fall into this category.

Capital BeijingLargest city ShanghaiPopulation 1,314.0 million (7/06 est.)GDP $10,000 billion (2005 est.)GDP per capita $7,600 (2005 est.)

Economic drivers Industrial products, especially secondary and terti-ary industries (including construction); services

Currency yuan (CNY); note – also referred to as the renminbi (RMB)

Sovereign credit Fitch – A, Positiverating Moody’s – A2, Positive

S&P – A, Stable

COUNTRY FACTS



growth rate



(CNY:USD)



Thermal 74%24%Hydro

2%Nuclear0%Other

2002 9.1%10.0%15.2%

11.5%

15.2%

200310.1%2004

200220032004

10.2%200510.5%2006

0 100 0 16 0 11 0 9-1 4

2002 (0.7)%1.2%2003

3.8%20041.8%20051.4%2006

2002 8.288.2820038.2820048.1920057.972006

Ch

ina

9 93 : B U S I N E S S D E S C R I P T I O N S – A S I A A N D M I D D L E E A S T

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AES China Generating Co. Ltd (Chigen), a wholly-owned subsidiary of AES, currently has

equity interests in seven projects in mainland China, with total gross capacity of 2,842 MW, or

approximately 910 MW when adjusted for ownership.

These projects include four coal-fired base-load plants, one hydro base-load plant, one oil-fired and one natural

gas-fired peaking plants. They are located in six different provinces and municipalities in China. The two largest

projects, Jiaozuo and Yangcheng, together account for more than 75% of Chigen’s capacity as adjusted for ownership.

Aixi, Cili, Hefei, and Jiaozuo are the controlled subsidiaries of Chigen; Chengdu, Wuhu and Yangcheng are accounted

for using the equity method, since Chigen owns less than 50% interest in these businesses. Chigen is one of the

largest foreign IPPs in China. In addition to the seven operating plants, it has offices in Beijing and Hong Kong. As of

December 31, 2006, Chigen’s controlled subsidiaries employed 381 people, its other affiliates employed 535 people

and Chigen employed 23 people who are involved in the operation, development and administration of Chigen.


Chigen was established in December 1993 by AES to serveas a vehicle to develop, acquire, finance, construct, own andoperate electric power generation facilities principally inChina. In early 1994, Chigen completed an initial publicoffering and subsequently became a wholly owned subsidiaryof AES in May 1997. Chigen currently owns 25% to 71%equity interest in seven power plants. All power plants areowned by joint ventures.

The joint venture contracts for Aixi, Chengdu, and Wuhuprovide for the liquidation of the project assets at the endof the terms of the respective joint venture. The joint venturecontracts relating to Cili, Hefei, Jiaozuo, and Yangchengprovide for the transfer of all of the fixed assets of the jointventures to the Chinese partners without charge at the endof the joint ventures’ respective terms. In exchange for that,Chigen has the right to either priority dividends (Yangcheng)or recovery of its equity investment during the terms of thejoint ventures (Cili, Hefei and Jiaozuo). Chigen has cooper-ated with ministry level companies and provincial and localgovernment-owned companies as partners in its joint ventures.

Chigen’s first investment was in Cili, which was establishedin 1994 as a cooperative joint venture between Hunan CiliElectric Power Company (Cili Electric Power) and Chigenwith a term of 25 years expiring in 2019. Chigen has a 51%interest. Hunan Cili County Chengguan Power GeneratingCompany replaced Cili Electric Power as the Chineseshareholder of the joint venture in 2000, with a 49% interest.Pursuant to the joint venture contract, Chigen is entitled

to recover its registered capital (equity) during the term ofthe joint venture. Chigen fully recovered its equity invest-ment in the joint venture in 2003.

In March 1996, Wuhu was formed as a 20-year equity jointventure by China Power International Holdings Limited(CPI, 45%), Anhui Liyuan Electric Power DevelopmentCompany Limited (Anhui Liyuan, 20%), Wuhu EnergyDevelopment Company Limited (Wuhu Energy, 10%) andChigen (25%). Wuhu’s two units commenced commercialoperation in September 1996 and March 1997.

Chengdu is a cooperative joint venture formed inDecember 1995 by Chigen (35%), Chengdu Huaxi ElectricPower (Group) Shareholding Co. Ltd. (Chengdu Huaxi,25%), Huachuan Petroleum & Natural Gas Exploration Co. (Huachuan, 10%) and China National Aero-EngineCorporation (30%). Construction of the power plant beganin October 1996 and commercial operation commenced in July 1997. In April 2005, Chengdu Huaxi sold all itsshareholding to China National Aero-Engine Corporation.In May 2005, Chengdu extended its joint venture termfrom 2011 to 2016.

The three generating units of Hefei are owned by twocooperative joint ventures formed by Chigen (70%), HefeiMunicipal Construction and Investment Company (HefeiConstruction, 10%) and Anhui Liyuan (20%). Both jointventures have terms of 16 years and began in March 1996.Construction of the Hefei power plant commenced in

Revenue* (In millions) 2004 2005 200683 84 93

1 0 0 A E S 2 0 0 6 FA C T B O O K

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November 1996. Commercial operation began in twostages in August 1997 and December 1998. Chigen recov-ered $5.8 million of its equity investment in Hefei in 2006.

In April 1996, Jiaozuo was established as a cooperativejoint venture, with a contract term of 23 years expiring inApril 2019. Chigen holds a 70% interest in the joint ventureand Jiaozuo Wan Fang Aluminum Co. Ltd (Jiaozuo Mill)holds the remaining 30% interest. Pursuant to the jointventure contract, Chigen is entitled to recover its regis-tered capital (equity) during the term of the joint venture.Construction started in the first quarter of 1995 andJiaozuo’s two units commenced commercial operation inAugust 1997 and July 1998.

Aixi was established in 1995 as a cooperative joint venturewith a term of 30 years expiring in September 2025. Thejoint venture contract was signed between ChongqingNanchuan Banxi Colliery (Banxi Colliery) and Chigen. InJune 2001, Banxi Colliery filed for bankruptcy and subse-quently its interests in the joint venture were transferred toNanchuan Banxi Liquidation Team and Nanchuan CreditBank. Following the transfer, Chigen owns approximately71%, Nanchuan Banxi Liquidation Team holds approximately26%, and Nanchuan Credit Bank holds approximately 3%.Construction began in 1996 and operations commenced inDecember 1998.

Yangcheng was formed as a 20-year cooperative joint venture formed in October 1996 by North China Electric

Power Group Corporation, Jiangsu Province InvestmentCorporation, Shanxi Energy Enterprise (Group) Company,Jiangsu Provincial Power Company and Chigen. In 2004, asa result of the restructuring of the electricity industry in China,the new shareholding structure of the joint venture became:China Datang Corporation (29%), Chigen (25%), JiangsuGuoxin Investment Limited (20%), Shanxi InternationalElectricity Group Co. Ltd (16%) and Shanxi ProvincialElectric Power Company (10%). In February 2007, as partof the reform of the power industry in China, ShanxiProvincial Electric Power Company was requested to divestits 10% shareholding in Yangcheng. Shanxi InternationalElectricity Group Co. Ltd. (SIE) won the 10% stakethrough a competitive bidding process presided over by theState Electricity Regulatory commission. SIE’s shareholdingin Yangcheng will increase from 16% to 26% after all neces-sary approvals and filings are obtained and completed. Theshareholdings of other investors will remain unchanged.Pursuant to the joint venture contract, Chigen is entitled toa priority return of approximately $12 million per year out ofdistributable profits commencing from 2002. Surplus prof-its after distribution of the priority return are distributedamong the joint venture parties in proportion to their con-tribution to the registered capital; in the case of Chigen, up toa maximum predetermined internal rate of return. However,there can be no assurance that this return will in fact beachieved. Construction began in 1997. The first four unitsentered commercial operation in 2001 and the remainingtwo entered commercial operation in 2002.

PHYSICAL ASSETS

Controlled SubsidiariesAixi is a 51 MW coal-fired circulating fluidized bed plantlocated in Nanchuan, Chongqing Municipality. Theinstalled environmental control system includes a 4-fieldESP, a limestone system and on-line emission monitoringdevice for CO2, SO2, NOx and O2. Cili is a 26 MW run-of-the-river hydropower facility, located in Cili County,Hunan Province. Cili consists of two power stations. Thefirst station is made up of eight 0.65 MW generating unitsand has been in full commercial operation since 1976. Thesecond station has 2x10.5 MW capacity and began fullcommercial operation in February 1997. Hefei is a 115 MWoil-fired combined cycle plant located in Hefei, AnhuiProvince. The plant consists of two gas turbine generatingunits and one heat recovery steam turbine generating unit.Jiaozuo is a 2x125 MW pulverized coal-fired power plantlocated adjacent to Jiaozuo Mill in Jiaozuo, Henan

Province. ESPs were installed during construction of theplant and one of the two ESP units was upgraded in 2005.Due to the more stringent environmental requirement inChina, Jiaozuo was required to install a flue gas desulfuriza-tion system (FGD) for both units. The contract for theFGD project was awarded in November 2006 and the proj-ect will be completed at the end of 2007.

Equity Method Affiliates*

Chengdu is a 50 MW gas-fired plant located in Chengdu,Sichuan Province. Chengdu consists of two 25 MW naturalgas-fired (simple-cycle) units. Wuhu is a 2x125 MW coal-fired, base load power plant located near Wuhu, AnhuiProvince. ESPs were installed during construction. Yangchengis a 2,100 MW mine-mouth power plant located nearYangcheng, Shanxi Province. Electric power from the plantis transmitted over a 755 km 500 kv transmission line to

* Reflects only the revenues of Chigen’s controlled subsidiaries (Aixi, Cili, Hefei, and Jiaozuo). AES’s investments in Chengdu, Wuhu, and Yangcheng are accounted forusing the equity method; consequently, their revenues are not consolidated. Starting in the second quarter 2007, Cili will be accounted for using the equity method and,consequently, its revenues will no longer be consolidated. Cili will continue to be controlled by AES through its 51% ownership stake.

1 0 13 : B U S I N E S S D E S C R I P T I O N S – A S I A A N D M I D D L E E A S T

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SALES & OPERATIONS

Electricity SalesChigen’s early market entry in mainland China in 1993enabled it to obtain favorable terms on its power projectinvestments. Most of Chigen’s PPAs are structured torecover fixed capital costs and to pass on increases in fuel,operating and maintenance, and foreign exchange conversioncosts to the offtakers, usually provincial power companies.Those contracts typically include yearly minimum off-takehours, which provide a basis for determining the tariff ratein accordance with the return requirement. The durationof the PPAs generally coincides with the length of thejoint venture.

Under most of the agreements, the tariff charged for electricity produced is calculated according to an agreedtariff formula. Such tariff has to be approved by the regulator on a periodic basis. Generally the tariff is in termsof fen/kWh and is based on the amount of energy actuallysold. As there are no capacity payments, some PPAs protectagainst dispatch risk by incorporating minimum take obligations on the offtakers. However, there can be noassurance that the relevant pricing bureaus will calculateand adjust tariffs in accordance with these tariff formulae,or that offtakers will make payments for electricity pur-chased based on the tariff formulae. In addition, there canbe no assurance that the minimum take obligations underthe PPAs will be honored or enforced.

Aixi has a PPA with Chongqing Fuling Power EnterpriseCompany Ltd (Fuling Power) for 25 years, expiring inDecember 2023. The PPA requires Fuling Power to purchasenot less than 270 GWh of electricity per calendar year.Fuling Power is obligated by the PPA to make payment forany shortfall at the then applicable power price less the fuel cost. The tariff formula is based on a cost-plus structurethat intends to pass through increased fuel costs and operation costs to the offtaker. The actual applicable tariffis subject to government approval from time to time.

Since 2000, Chengdu has sold its electricity to Chengdu PowerBureau under a 13-year PPA, expiring in December 2012. ThePPA requires Chengdu Power Bureau to purchase for eachcalendar year no less than the allocated generation quantityas set out in the annual generation plan issued by the

provincial Economic and Trade Commission. Pursuant tothe procedures of tariff approval and the PPA, Chengdusubmits the tariff application to the provincial pricingauthority for review and approval. Chengdu calculates the tariff based on the estimated costs of generating theminimum amount in the following year.

Since 1998, Cili has sold its power to Zhangjiajie ElectricityPower Bureau (Zhangjiajie Power), the parent of CiliElectric Power, and has since then effectively integratedinto the Hunan provincial grid. Under the annually renew-able PPA, which expires in September 2007, ZhangjiajiePower purchases power from Cili at a tariff rate set annu-ally by the relevant pricing authority to cover the costs andprovide a reasonable equity return.

Hefei’s power is purchased by Anhui Provincial ElectricPower Corporation (Anhui Power) pursuant to a 16-yearoperation and off-take contract (OOC), expiring inMarch 2012. Under the OOC, Anhui Power agrees to purchase a minimum amount of electricity at an agreed-upon tariff or to compensate the sellers for any shortfall ofthe purchases. The compensation is determined based onthe approved tariff less the approved generation costs. The tariff formula is structured to recover fixed costs andto pass through all the variable operating and maintenanceand foreign exchange conversion costs to the offtaker. The tariff is subject to the approval of the provincialPricing Bureau. Pursuant to the OOC, Anhui Power is alsoresponsible for the operation and maintenance of thepower plant and for all the operating costs. In return,Anhui Power is entitled to be compensated for its servicesand to be reimbursed for the agreed-upon production costs.Anhui Power is responsible for ensuring the generation ofthe power plant is not less than the minimum contractedamount and is required to compensate the joint venturesfor any shortfall of the minimum amount, unless the shortfall is caused by force majeure or the failure of the jointventures to perform their obligations under the OOC. InMarch 2007 Anhui Development and Reform Commissionissued a notification to Hefei that it has been included inthe list of small units to be closed. Negotiations on the termination payment are on-going.

Jiangsu Power Grid in Jiangsu Province, on the eastern coastof China. Yangcheng consists of six 350 MW anthracitecoal-fired units. ESPs were installed to remove particulate

matters in flue gas. There are plans to install FGD for six unitsof the plant . The first two FDG units are expected to beoperational in 2008.

1 0 2 A E S 2 0 0 6 FA C T B O O K

Ch

ige

n

Jiaozuo has two separate 23-year PPAs with Jiaozuo Milland Henan Electric Power Corporation (Henan Power),both expiring in April 2019. Jiaozuo Mill is required to pur-chase at least 5,500 hours at 117 MW from the joint ven-ture and Henan Power is required to purchase 5,500 hoursat 113 MW. Both power purchase contracts have the sametariff formula based on a cost-plus structure that passesthrough the operating costs and financing costs of the proj-ect to the offtakers, and to enable the shareholders of thejoint venture to realize a return on their investments.

Wuhu’s power is purchased by Anhui Power pursuant to a20-year OOC, expiring in March 2016. Under the OOC,Anhui Power has agreed to purchase a minimum amount ofelectricity at a price based upon an agreed tariff formula orto compensate the seller for any shortfall of the purchases.The compensation is determined based on the approvedtariff less the approved generation costs. The tariff formulais structured to recover fixed costs and to pass through allthe variable operating and maintenance, and foreignexchange conversion costs to the offtaker. The tariff is subject to the approval of the provincial Pricing Bureau.Pursuant to the OOC, Anhui Power is also responsible forthe operation and maintenance of the power plant and isresponsible for satisfying all operating costs of the powerplant, in a structure similar to that of its OOC with Hefei.

Yangchang sells its power to Jiangsu Power under a 20-yearPPA, expiring in September 2016. Under the PPA, JiangsuPower has agreed to purchase at least the equivalent of5,500 operating hours of generation by the project for eachcalendar year prior to the year 2011, at least 5,386 hours forthe calendar year 2011 and at least 5,000 hours for each yearthereafter. In the event that Jiangsu Power fails in any calen-dar year to purchase such minimum amount, it is requiredto make payment for any shortfall at the then currentpower price less fuel costs. The tariff formula is based oncost-plus structure. However, actual applicable tariff is sub-ject to government approval from time to time.

Fuel SupplyAixi has a fuel supply agreement (FSA) with NanchuanHong Neng Coal Co, Ltd. The FSA does not have a fixedterm. The coal delivery price is negotiated quarterly basedon the local coal market prices. Most of the coal is trans-ported by truck. Since 2004, the coal price has increasedsignificantly. As a result of the coal price increases, theChinese government issued a coal price and power tariffindexation policy to allow recovery of 70% coal priceincrease in the power tariff. However, such recovery, whichis subject to government approval, may only represent apercentage of the coal price increase.

Chengdu has a 15-year gas supply contract with one of thejoint venture shareholders, Huachuan, expiring 2012.Huachuan must supply a minimum quantity of natural gasannually to Chengdu in conformity with certain prescribedspecifications and at a price approved by the NationalDevelopment and Reform Commission. Gas is transportedto the power plant via a dedicated pipeline that is managedand owned by Huachuan.

As part of its obligations under the respective OOCs forHefei and Wuhu, Anhui Power is required to supply suchfuel as may be necessary to allow the power plant to gener-ate electricity to be purchased under the OOC.

Jiaozuo obtains fuel under short-term contracts for thepurchase of anthracite coal from mines in Shanxi, locatedapproximately 120 km from the plant. The price for coal is negotiated periodically with coal suppliers. The coal suppliers arrange for the transportation of the coal by truckto the power plant.

Yangcheng currently procures approximately two-thirds ofits coal from Jincheng Coal Group Corporation and JinchengMunicipal Power Fuel Supply Company under annuallyrenewable contracts. The rest of its coal is procured on thespot market.


OPGC* is a base-load pulverized coal-fired plant with420 MW gross installed capacity. It is located 400 kmfrom Bhubaneshwar, the capital of Orissa. OPGC’s generationis committed to GRIDCO, the state-owned utility andtrans mission company in Orissa, through a 30-year PPA.OPGC provides approximately 12% of the generation capacity of the state of Orissa.

AES acquired 49% of OPGC from the government ofOrissa in 1998. The government of Orissa continues tohold the remaining shares. As of December 31, 2006,OPGC employed 607 people.

OPGC consists of two units with a gross capacity of 210 MWeach; Unit 1 was commissioned in December 1994 andUnit 2 in June 1996. Installed environmental controlsinclude ESPs, a 100% ash water recycling system, and aContinuous Online Emission Monitoring System for monitoring SO2, NOx, CO and SPM emissions.

OPGC supplies 100% of its generation to GRIDCO undera PPA through June 2026, which is further extendable basedon mutual agreement of OPGC and GRIDCO. The tariff forsupply of electricity consists of fixed and variable components.The fixed component includes a return on equity and thevariable component includes an incentive payment on generation above a target capacity factor. Payment fromGRIDCO is secured through a letter of credit and escrowmechanism. The tariff is not indexed to U.S. dollars.

Coal is supplied from a mine in the Ib Valley coalfields ofMahanadi Coalfields Limited (MCL), which is a govern-ment enterprise. The mine is located approximately 15 kmfrom the plant. The supply of coal from MCL is based on along-term coal linkage granted by the Government of Indiaover the term of the PPA. The coal is transported from themines through a rail network owned by OPGC. Fuel cost ispassed through contractually under the PPA.

OP

GC

Capital New DelhiLargest city Mumbai (Bombay)Population 1,095.4 million (7/06 est.)GDP $4,042 billion (2006 est.)GDP per capita $3,700 (2006 est.)

Economic drivers Services (telecommunications, information technology), industries (manufacturing, especially consumer goods, cars, consumer electronics)

Currency Indian rupee (INR)Sovereign credit Fitch – BBB–, Stablerating Moody’s – Baa3, Stable

S&P – BBB–, Stable

COUNTRY FACTS



growth rate



(INR:USD)



Thermal 73%22%Hydro

2%Nuclear2%Other

2002 3.6%8.3%6.3%

2.9%

5.3%

20038.5%2004

200220032004

8.5%20058.7%2006

0 100 0 7 0 9 0 500 7

2002 4.3%3.8%20033.8%20044.2%20056.1%2006

2002 48.6146.58200345.32200444.10200545.502006

Ind

ia


n/a n/a n/a


1998

Segment

Generation

Country

India

Fuel

Coal

AES EquityInterest

49%

MW

420

* AES’s investment in OPGC is accounted for using the equity method; consequently, OPGC’s revenues are not consolidated.

1 0 4 A E S 2 0 0 6 FA C T B O O K

Capital AmmanLargest city AmmanPopulation 6.1 million GDP $30 billion (2006 est.)GDP per capita $5,100 (2006 est.)

Economic drivers Services (telecommunications), industries (manu-facturing esp. pharmaceuticals, light manufacturing)

Currency Jordanian dinar (JOD)Sovereign credit Fitch – N/A, N/Arating Moody’s – Ba2, Stable

S&P – BB, Stable

COUNTRY FACTS



growth rate



(JOD:USD)


2002 5.7%4.1%(1.6)%

7.7%

14.7%

20037.7%7.7%

2004

200220032004

6.4%

20052006

0 100 –2 15 0 8 0 10 7

2002 1.8%1.6%3.4%

20032004

3.5%20056.2%2006

2002.71.71

2003.712004.712005.712006

Amman East is a 370 MW gas-fired/distillate fuel oil plantcurrently under construction at a site leased from theGovernment of Jordan at Almanakher, approximately 15 kmeast of Amman, Jordan.

AES’s net equity interest in the project is 36.66%, however,it will control the development and operations of AmmanEast. Construction began in April 2007, and commercialoperation is expected to commence in two stages inJuly 2008 and July 2009. The total cost of the project is$300 million, with 25% funded by equity contributions byAES, the Islamic Development Bank Infrastructure Fundand Mitsui & Co. of Japan. The remaining $225 million will be provided by long-term non-recourse debt facilitiesprovided by a consortium of lenders.

Amman East is a gas/oil-fired combined cycle electric generation facility designed by Doosan of Korea. It will utilize two 116 MW gas turbines and a 137 MW steam turbine. Natural gas from the operating Arab Gas pipelinefrom Egypt will be the primary fuel for the plant. Fuel oilwill serve as a backup fuel.

The plant will sell its electricity output to the NationalElectric Power Company of Jordan (NEPCO) under a25-year power purchase agreement (PPA). Payments underthe PPA will be for tested capacity, and will be made inJordanian dinar at the prevailing U.S. dollar to Jordaniandinar exchange rate. The Government of Jordan will guarantee the NEPCO obligations under the PPA. ThePPA is structured as a tolling agreement. Gas and fuel distillate oil will be supplied by NEPCO. The project willbe the first IPP facility in Jordan.

* Construction commenced in 2007.

Jord

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n/a n/a n/a


July 2008–2009

Segment

Generation

Country

Jordan

AES EquityInterest

36.66%

MW

370

Fuel

Gas/distillatefuel oil





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Prior to May 2005, the Ministry of Housing, Electricityand Water (MHEW) owned all electricity and related water infrastructure in Oman, with the exception of a fewindependent power producers and independent power andwater producers. MHEW was responsible for the operationand maintenance of the government owned generationplants and the entire transmission and distribution system.Following the promulgation of a Sector Law in July 2004(effective August 2004), the electricity sector was unbundledand divided into newly created corporate entities. A newRegulatory Authority was formed to oversee the Power sector. The Authority was to promulgate rules and subsequentlygrant generation licenses to all the generating companies in

Oman. Barka was granted its generation license in May 2005after complying with all the requirements of the regulator.Furthermore, an Electricity Holding Company was alsoincorporated to hold the Government’s stake in its generation assets and newly unbundled companies. As a result of the unbundling, nine other companies wereformed, composed of one offtaker for all the electricity andwater production in Oman, one transmission company,three generation companies for the government ownedplants, and four distribution companies. The existing marketcontinues to be composed of fully contracted entities and no change in this structure is envisioned, especially forpresently contracted facilities, at this time.



Capital MuscatLargest city MuscatPopulation 3.1 million (7/06 est.)GDP $44 billion (2006 est.)GDP per capita $14,100 (2006 est.)

Economic drivers Crude oil, natural and liquified natural gas (LNG), services

Currency Omani rial (OMR)Sovereign credit Fitch – N/A, N/Arating Moody’s – A3, Positive

S&P – A, Stable

COUNTRY FACTS



growth rate



(OMR:USD)

Thermal 100%0%

0%

HydroNuclear

0%Other

2002 2.3%2.3%3.2%

45.4%

4.3%

20035.6%2004

200220032004

5.6%20056.6%2006

0 100 1 50 0 7 0 1–1 4

2002 (0.6)%(0.4)%20030.3%20041.2%2005

4.0%2006

2002 0.380.3820030.3820040.380.38

20052006

1 0 6 A E S 2 0 0 6 FA C T B O O K

Barka is a 456 MW natural gas-fired, combined cycle gas turbine power and 20 MIGD water

desalination facility, located on the coast approximately 60 km northwest of Muscat, the

capital city of the Sultanate of Oman.

Barka is the first independent power and water producer in Oman. Barka provides power and desalinated water to

the Omani Power and Water Procurement Company S.A.O.C. (OPWPC) under a 15-year power and water purchase

agreement (PWPA). The plant provides over 15% of the country’s peak system capacity. As of December 31, 2006,

approximately 53 people managed, operated and maintained the facility.


The Ministry of National Economy of Oman awarded theproject to AES Oasis Ltd, a wholly owned subsidiary ofAES, and Multitech LLC, a 15% minority partner, in a competitive bidding process in 2000. Construction beganin June 2001 and operations commenced in June 2003. InDecember 2003, a 39% interest in AES Oasis was sold tothe IDB Infrastructure Fund. This reduced AES’s ultimate

share holding in Barka from 85% to approximately 52%.Pursuant to the terms of the PWPA, an IPO of 35% of theshares of Barka was completed on the Muscat SecuritiesMarket in December 2004 thus reducing the AES’s owner-ship further from 52% to 35%. AES retains managementcontrol of the business.

PHYSICAL ASSETS

Barka primarily burns natural gas, but can also burn fueldiesel oil as a back-up. The facility includes two heat recoverysteam generators with fresh air firing capability, as well astwo gas turbines of 117 MW each and one steam turbine of 222 MW. The facility also uses two gas and one steamturbine generators. The desalinated water is produced

using three multi-stage flash evaporators. Installed environmental controls include dry low NOx burners onthe gas turbines, a continuous emission monitoring systemfor flue gases, smoke density monitoring equipment, a seawater discharge residual chlorine monitoring system,and a chlorine gas purging and neutralization system.

SALES & OPERATIONS

Electricity and Water SalesBarka’s full power and water output capacity is fully contractually obligated to the OPWPC under the PWPAthrough April 2018. The payments under the PWPA areguaranteed by the government of Oman. Under thePWPA, payments are made in local currency, Omani rial(RO), but all payments are indexed to the fixed RO/USDexchange rate. Contractually, power payment obligationsare for available capacity, fixed operations and maintenance,and variable operations and maintenance, with all amountsscheduled and indexed in accordance with contract terms.Under the contract terms, Barka has heat rate risk but notfuel price risk.

Fuel SupplyThe Ministry of Gas is obligated to deliver 100% of the dispatchrequirements of natural gas at a fixed price per MMBTU toBarka for the same period as the PWPA under a Natural GasSupply Agreement (NGSA). The NGSA does not impose anytake-or-pay obligation on the project company. The gas is supplied through underground pipelines. Gas charges are paidas a fuel charge component of electrical energy charges.

Diesel is procured from Oman Oil SAOG on an as requiredprocurement basis. 100% contractual reserve capacity ismaintained at all times. Storage volume capacity is equivalentto three days of full load usage.


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456

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Paki

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The electricity sector in Pakistan is regulated by three mainentities, namely the WAPDA, the National Electric PowerRegulatory Authority (NEPRA) and the Private PowerInfrastructure Board (PPIB).

WAPDA acts as a power offtaker. NEPRA’s main responsi-bilities are to: issue licenses for generation, transmissionand distribution of electric power; establish and enforcestandards to ensure quality and safety of operation and supply of electric power to consumers; approve investmentand power acquisition programs of the utility companies;and determine tariffs for generation, transmission and dis-tribution of electric power.

NEPRA regulates the electricity sector to promote a competitive structure for the industry and to ensure thecoordination of a reliable and adequate supply of electricpower in the future.

PPIB offers support by the government of Pakistan to theprivate sector in implementing power projects by acting as aone stop organization on behalf of all ministries, departmentsand agencies of the government of Pakistan. PPIB’s functionsinclude the following: to negotiate the inter connectionagreements and provide support in negotiating power purchase agreements, fuel supply agreements and water use licenses; to provide guarantees to independent power producers for the performance of government of Pakistanentities; to prepare, conduct and monitor litigation andinternational arbitration for, and on behalf of Pakistan forprivate power projects and proposals; and to assist NEPRAin determining and approving tariffs for new private powerprojects. The government’s policy remains aimed at promoting market-based, private sector-led growth.



Capital IslamabadLargest city KarachiPopulation 165.8 million (7/06 est.)GDP $427 billion (2006 est.)GDP per capita $2,600 (2006 est.)

Economic drivers Services (textiles, apparel, food processing), agricul-ture (cotton production)

Currency Pakistani rupee (PKR)Sovereign credit Fitch – N/A, N/Arating Moody’s – B1, Stable

S&P – B+, Positive

COUNTRY FACTS



growth rate



(PKR:USD)

Thermal 66%32%

2%

HydroNuclear

0%Other

2002 4.2%4.9%7.0%

5.2%

3.6%

20037.4%2004

200220032004

8.0%20056.2%2006

0 100 1 7 0 8 0 650 10

2002 3.3%2.9%2003

7.4%20049.1%20057.7%2006

2002 59.7257.75200358.26200459.5260.50

20052006

1 0 8 A E S 2 0 0 6 FA C T B O O K

Lal Pir and Pak Gen are 362 MW and 365 MW oil-fired conventional steam power plants, located

next to each other at a well-secured site near Multan in the southern part of Punjab, Pakistan.

Lal Pir and Pak Gen are mid-merit plants that sell electricity to the Pakistan Water and Power Development Authority

(WAPDA), the state-owned utility, under 30-year PPAs. As of December 31, 2006, Lal Pir and Pak Gen employed 107 people.


AES entered Pakistan under the government of Pakistan’sprivate power policy of 1994. The PPA for Lal Pir wassigned in November 1994 and construction started in thefirst quarter of 1995. For Pak Gen the PPA was signed inSeptember 1995 and the construction work started in thefirst quarter of 1996. The businesses were developed on abuild-own-operate basis. Lal Pir commenced commercial

operation in November 1997 and Pak Gen came on line inFebruary 1998.

AES initially owned 90% of each business, with the remaining10% held by the International Finance Corporation. InDecember 2003, AES sold approximately 39% of its interestin both the businesses to the IDB Infrastructure Fund.AES now owns 55% of each business.

PHYSICAL ASSETS

Lal Pir utilizes a single steam turbine-generator set with a gross nameplate rating of 362 MW. The capacity of theboiler is 1,200 tons/hour. The water is supplied fromMuzaffargarh canal with back-up supply from wells. Lal Pirhas three heavy fuel oil tanks with 30,000 tons capacity each. The main power block consists of a residual fuel oil-fired, forced draft boiler and a 362 MW reheat, condensing,two casing, double flow type steam turbine generator.

Pak Gen has a similar configuration with a gross nameplaterating of 365 MW. The turbine generators are arranged in

the turbine house, which is connected to the control andelectrical switch yard. Pak Gen has two heavy fuel oil tankswith 30,000 tons capacity each.

Both plants comply with all local and related World Bankenvironmental guidelines and are ISO 14001 andOHSAS 18001 certified. Pak Gen, following the environ-mental guidelines of the World Bank, was the first powerplant in Pakistan to install a flue gas desulfurization unit.

SALES & OPERATIONS

Electricity SalesThe 30-year PPAs with WAPDA expire in 2027 and 2028for Lal Pir and Pak Gen, respectively. All payments fromWAPDA are guaranteed by the government of Pakistanthrough Implementation Agreements (IA) for each business.Elements in the tariffs are indexed to compensate for inflation, changes in the U.S. dollar and Japanese yen exchangerate, and the price of fuel. The rights and obligations of theparties to the IA are governed by the laws of England.WAPDA has issued a letter of credit for two months payment.

Fuel SupplyPakistan State Oil (PSO) supplies heavy fuel oil under a30-year fuel supply agreement (FSA), with terms matchingthe PPAs, and is delivered by pipeline. Fuel is a pass-throughunder the PPA at a specified heat rate. The PPA enables

each company to recover certain sums from WAPDA tooffset damages payable by the company to PSO under the FSA, caused by a default by WAPDA under the PPA.Liquidated damages for failure to provide fuel are payableby PSO to the project equal to lost capacity payments and liquidated damages payable by the project to WAPDA.

Other Commercial AgreementsThe IA was signed between the government of Pakistan andLal Pir and Pak Gen. The IA will remain in effect for the lifeof each PPA. The government of Pakistan has also givenguarantees for the obligations of WAPDA, PSO, and theState Bank of Pakistan (SBP) to Lal Pir and Pak Gen. Projectincome is exempt from income tax. A withholding tax of7.5% is deducted at the time of the payment of dividends.


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AES

Eq

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MW

727

Paki

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Qa

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Re

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Qa

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In the State of Qatar there is no regulatory authority.Generation licenses are granted by the State of Qatar. Thegovernment is moving steadily away from the former patternof electricity supply being seen as the function of a StateMinistry. The creation of Qatar Electricity and WaterCompany (QEWC) in 1998 was the first key step in thisprocess. More recently, the former Ministry of Electricity

and Water has been transformed into a state-owned corpo-ration, KAHRAMAA. It is envisaged that KAHRAMAAwill continue to be responsible for the bulk purchase ofpower from QEWC and other generators, while also managing the control and dispatch of the national grid and local water distribution systems.



Capital DohaLargest city DohaPopulation 0.9 million (7/06 est.)GDP $26 billion (2006 est.)GDP per capita $29,400 (2006 est.)

Economic drivers Crude oil, natural gas and liquified natural gas(LNG), and gas-based industrial products and condensates

Currency Qatari rial (QAR)Sovereign credit Fitch – N/A, N/Arating Moody’s – Aa3, Stable

S&P – A+, Stable

COUNTRY FACTS



growth rate



(QAR:USD)

Thermal 100%0%

0%

HydroNuclear

0%Other

2002 7.1%3.5%9.8%

9.9%

9.8%

200320.8%2004

200220032004

6.1%20057.1%2006

0 100 1 10 0 21 0 40 11

2002 1.0%2.3%2003

6.8%20048.8%200510.5%2006

2002 3.643.6420033.6420043.643.64

20052006

1 1 0 A E S 2 0 0 6 FA C T B O O K

Ras Laffan is a 756 MW natural gas fired combined cycle power and 40 MIGD desalinated

water plant, located approximately 80 km north of Doha.

Ras Laffan was the first independent power and desalination plant in the State of Qatar. The plant was built on a

build-own-operate-transfer basis under a 25-year power and water purchase agreement (PWPA) with the Qatar

General Electricity and Water Corporation (KAHRAMAA), a government entity. The plant generates over 25% of the

Qatar grid peak system capacity. As of December 31, 2006, Ras Laffan employed 86 people.


The plant was awarded to Ras Laffan Power Company(RLPC) through a competitive bidding process. RLPC is aconsortium with AES the largest shareholder (55%) and theremaining ownership split among the Qatar Electricity andWater Company (QEWC, 25%), Qatar Petroleum (QP, 10%),and the Gulf Investment Company (GIC, 10%). The AESRas Laffan Operating Company (AES ROC) is a jointventure between AES (70%) and QEWC (30%). AES ROCoperates and maintains the plant on behalf of RLPC.

The PWPA was signed in October 2001 and constructionbegan in January 2002. The plant commenced open cycleoperation of 300 MW in April 2003 and began full combinedcycle operation in May 2004. The total project cost wasapproximately $720 million.

PHYSICAL ASSETS

Ras Laffan is a dispatched plant. It consists of four gas turbines with air-cooled generators. There are four heatrecovery steam generators with supplementary duct firing,and two steam turbines with air-cooled generators. The

desalination plant has four 10 MIGD multi-stage flashevaporators. Installed environmental controls include drylow NOx burners on the gas turbines and a continuousemission monitoring system of flue gases.

SALES & OPERATIONS

Electricity and Water SalesAll power and water output is sold to KAHRAMAA, with payment guaranteed by the State of Qatar. As per thePWPA, KAHRAMAA commits to the payment of acapacity charge, output charge, other charges, and pass-through items for both power and water. The capacitycharge is composed of three items: a capital recovery charge;fixed operations and maintenance charge; and fixed seawatercharge. The capacity charge for a billing period is calculatedfor each operating interval on the basis of the actual capac-ity made available to KAHRAMAA. The tariff is payable inU.S. dollars. Upon expiration of the PWPA the facility willbe transferred to KAHRAMAA.

Fuel SupplyNatural gas for the power plant is supplied by QatarPetroleum (QP) under a fuel supply agreement (FSA),which has the same term as the PWPA. There is a take orpay obligation for 70% of the contract quantity. The fuelprice is $0.80 per MMBTU subject to adjustments inaccordance with the FSA, payable in U.S. dollars.

Seawater SupplyUnder the sea water supply agreement (SSA), seawater is supplied and return water is accepted by QP for and from the desalination plant. This contract has the same term as thePWPA. The connection charge is fixed annually and is payableannually, irrespective of usage, in U.S. dollars. There is alsoa monthly usage charge based on delivered seawater quantity.


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Kelanitissa is a 168 MW diesel-fuel-based combined cycle power plant located in northern Colombo, Sri Lanka’s capital.

The plant has a 20-year PPA with the Ceylon ElectricityBoard (CEB). AES developed Kelanitissa as a greenfieldproject; construction began in June 2001. Commercialoperation began on open cycle in February 2003 and oncombined cycle in October 2003. The plant is designed tooperate on base load mode and provides approximately 7%to 10% of Sri Lanka’s annual power demand. AES owns90% of Kelanitissa; the remaining 10% is owned byHayleys, a local partner. As of December 31, 2006,Kelanitissa employed 46 people.

The facility has a 1x1x1 configuration with one combustionturbine, one heat recovery steam generator, one steam turbine, and one generator. Electricity payments from CEBare guaranteed by the Government of Sri Lanka. The PPAhas a two-tier tariff, including capacity and energy payments.The payments are denominated in U.S. dollars (debt service,

return on equity, and certain fixed and variable O&M costs)and rupees (fuel costs, certain fixed and variable O&Mcosts) and indexed to U.S. CPI and the Greater ColomboConsumer Price Index. The PPA also includes availability-based performance incentives. Upon expiration of the PPAterm in October 2023, the facility shall be transferred toCEB, unless extension of the term is mutually agreed uponon or before October 2020.

Kelanitissa has a fuel supply agreement (FSA) with theCeylon Petroleum Corporation (CPC), a Governmentowned entity. The fuel price charged by CPC is passed throughto CEB. The FSA has the same term as the PPA and can be extended if the PPA is extended. Fuel is transported tothe plant by pipeline from CPC storage tanks, which arelocated less than five km from the plant. A March 2004fire severely damaged the steam turbine facility. The steam turbine was recommissioned in October 2004. A September 2005 outage rectified additional problems with the steam turbine.

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Capital ColomboLargest city ColomboPopulation 20.2 million (7/06 est.)GDP $93 billion (2006 est.)GDP per capita $4,600 (2006 est.)

Economic drivers Services (import/export trade, telecommunications,financial services, manufacturing, especially textilesand chemical/rubber goods)

Currency Sri Lankan rupee (LKR)Sovereign credit Fitch – BB-, Negativerating Moody’s – N/A, N/A

S&P – B-, Negative

COUNTRY FACTS



growth rate



(LKR:USD)

Thermal 60%40%

0%

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2002 4.0%6.0%12.0%

4.0%

5.4%

20035.4%2004

200220032004

6.0%20057.3%2006

0 100 1 12 0 8 0 1050 14

2002 9.5%6.3%20037.6%200411.6%200513.6%2006

2002 95.6696.522003101.192004100.50102.99

20052006

1 1 2 A E S 2 0 0 6 FA C T B O O K

HIGHLIGHTS

■ We currently operate over 1,000 MW of wind generation throughout the world, primarily in the United States, andhave 4,000 MW of wind projects in development worldwide.

■ We are pursuing select LNG regasification projects in the United States that will provide clean natural gas to highdemand, supply constrained markets.

■ We are developing projects and technologies that reduce or offset greenhouse gas emissions, primarily through (i)energy efficiency projects targeting our 44,000 MW portfolio of generation assets as well as our 13 power deliverybusinesses, (ii) the expansion of our renewable generation businesses, and (iii) by capturing and destroying or recyclingmethane in a variety of forms before it reaches the atmosphere.

Over the next decade, world energy demand is expected to increase

at an unprecedented rate. At the same time, businesses and govern-

ments are recognizing that meeting this increase in demand with

conventional energy sources will be extremely difficult, especially

when taking into account environmental impacts and energy

security concerns. For instance, there is an urgent need to lessen the

impact of greenhouse gases on the environment. As demand for

more sustainable sources of energy grows, we are expanding our

capabilities to provide alternative solutions.

Through our Alternative Energy group, we are committed to rapidly

expanding our wind generation business worldwide and have set

aggressive targets to produce greenhouse gas emissions offset cred-

its. We believe the market for these credits will grow significantly as

a result of increasingly stringent environmental regulations and a

growing political consensus on the problems of global warming.

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CONTENTS

ALTERNATIVE ENERGY

Climate Change 114

Wind Generation 115

We believe alternative energy represents a significant

growth opportunity for AES. We are operating, constructing

or developing business in wind generation, liquefied natural

gas (LNG) regasification terminals and greenhouse gas

emission reduction projects.

Longer term, we see additional growth opportunities in

areas such as energy efficiency, power management, energy

storage technologies and biomass. We are actively evaluating

investments in solar and geothermal power as well as

non-electric business lines such as ethanol, biodiesel,

synthetic fuels and new technologies to reduce greenhouse

gas emissions.

We expect that alternatives to traditional fuels will become

more economically competitive and more in demand over

time, and we are poised to take advantage of this opportunity.

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Taking a leadership role in the emerging climate change business and helping to develop

the market for greenhouse gas offset credits, AES seeks solutions that are both good for the

environment and good for business.

AES has entered into two alliances to produce greenhouse gas emissions offset credits. AES Agriverde, AES’s first

significant investment in greenhouse gas emissions offsets, was formed in 2006 as a joint venture between AES and

AgCert International Ltd (AgCert). In 2007, AES created a partnership with GE Energy Financial Services, a unit of

General Electric, to produce and sell voluntary greenhouse gas emissions offset credits in the United States.

AES AGRIVERDE

AES Agriverde creates greenhouse gas offsets by reducingemissions at livestock farms and palm oil mills, installingbio-digester technology on animal waste management systems and improving lagoon management systems. AESAgriverde is targeting investments in ten or more countriesand expects to generate 20 million tonnes* of emissionsoffsets annually by 2010. It commenced construction of itsfirst project in Malaysia in December 2006. AES has an

equity interest of 80% in AES Agriverde. AES’s strategicalliance with AgCert, a leading developer of greenhouse gasemission reduction projects in the agricultural and farmwaste sectors worldwide, also includes a minority investmentin AgCert. AES Agriverde is based in Bermuda with officesin Melbourne, Florida, Singapore, Kuala Lampar, Malaysia,Jakarta, Indonesia, Beijing, China and Russia.

GE AES GREENHOUSE GAS SERVICES

AES and GE created a joint venture in 2007 through whichit will seek to create 10 million tonnes* of greenhouse gasoffset credits by 2010, primarily through the reduction ofmethane – a potent greenhouse gas with a warming potential21 times greater than carbon dioxide. Emissions reductionprojects are expected to include agricultural waste, landfills,

coal mines and wastewater treatment. The partnership isexpected to sell carbon credits from projects to commercialand industrial customers seeking to reduce the environmentalimpact of their operations or to provide climate-friendlyproducts or services to their customers.

A NOTE ABOUT GREENHOUSE GAS OFFSETS

Under the Kyoto Protocol, investment in developing coun-tries in projects that generate offset credits is encouraged.In order to qualify, projects must be located in developingcountries that are signatories to the Kyoto Protocol. AES iswell established in 18 such countries. These projects requirea wide range of skills and experiences that are establishedstrengths of AES – local expertise on a global scale, a long

history of successful projects in the developing world, andexceptional operational and technical skills.

Unlike the power generation business, which typicallyrequires large investments, carbon credit projects will typically be relatively small in size, with capital costs ranging from $100,000 to as much as $5 million.

* metric tons

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AES Wind Generation (AES Wind) operates approximately 1,015 MW of installed capacity of

wind assets.

AES Wind has ownership interests in 717 MW of operating wind farms in the U.S. AES additionally owns 4 MW in

France, through AES’s investment in InnoVent. AES Wind also has contracts to operate and maintain 298 MW of

wind assets in three states. AES Wind employed 202 people at the end of 2006.


AES operates its wind generation facilities and conducts itswind development activities through its AES Wind group,which acquired SeaWest Holdings Inc., in March 2005 forapproximately $60 million. Full commercial operation ofBuffalo Gap Wind Farm (Buffalo Gap) commenced in

April 2006. AES owns 100% of the Altamont, Santa Clara,Tehachapi and Palm Springs projects. AES owns Condonand Buffalo Gap together with third party equity partnerswith variable equity ownership interests.

PHYSICAL ASSETS

Buffalo Gap I, located near Abilene, Texas, consists of67 wind turbines totaling 121 MW of installed capacity.The project is an Exempt Wholesale Generator (EWG),and the generation is purchased by Direct Energy.

The Altamont, California assets consist of 426 turbines ofvarious technologies totaling 24 MW of installed capacity.The project is considered a QF under PURPA and sells powerto Pacific Gas & Electric (PG&E). In addition, the 200 tur-bine, 18 MW, Santa Clara project was purchased in Septemberfrom Enron, and has a PPA with the City of Santa Clara.

Tehachapi assets totaling 54 MW of installed capacity arelocated in California and include two wind farm projectsencompassing 667 turbines constructed in the mid-1980s.

The Palm Springs, California assets, called Altech III andSan Jacinto, consist of 307 wind turbines of various technologiestotaling 30 MW of installed capacity. These projects are

considered a QF and the generation is purchased bySouthern California Edison (SCE).

Condon Wind Power, located in Oregon, operates 83 windturbines totaling 50 MW of installed capacity. The project isan EWG, and the generation is purchased by BonnevillePower Administration.

In May 2007, we acquired Lake Benton I, a 106.5 MWfarm in southwestern Minnesota, and Storm Lake II, a79.5 MW wind facility in northwestern Iowa, from GEEnergy Financial Services.

In July 2006, AES began construction of the 233 MWBuffalo Gap II project, an expansion of the company’s121 MW Buffalo Gap wind farm. AES purchased 155 GE1.5 sle wind turbine generators for this project with a nameplate rating of 1.5 MW each. Commercial operationcommenced in second quarter 2007.

SALES & OPERATIONS

Electricity SalesAES Wind sells electricity under several PPAs. The PPAsfor the Altamont assets are with PG&E and have terms of30 years, expiring in 2015. The PPA for the Condon projectis with Bonneville Power Administration and has a term of20 years, expiring in 2022. The PPAs for the Palm Springsassets are with SCE and have a term of 30 years, expiring in

2015. The PPA for Santa Clara is with the City of Santa Clara,expiring in 2011. The PPA for Buffalo Gap is with DirectEnergy and has a term of 15 years, expiring in 2021. Tehachapiassets have PPAs with SCE, expiring in 2014 and 2016. ThePPA for Lake Benton I expires in 2028. Storm Lake II hastwo PPAs, expiring in 2019. The PPA for Buffalo Gap IIwas signed with Direct Energy, LP, a subsidiary of Centrica,plc. It has a term of 10 years, expiring in 2017.

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Recent EventsAES is pursuing 4,000 MW of active development of wind projects worldwide. AES is currently exploring windpower projects in Europe, China, India, Central and SouthAmerica, with an emphasis on countries with existing AES businesses.

In July 2006, AES acquired a majority control of the Wind Energy Ltd. (WEL) group companies, a UK-baseddevelopment company, with 640 MW of wind generationprojects under development in Scotland. If successfullydeveloped, these projects will start commercial operationas early as 2008, extending through 2014.

In October 2006, AES purchased a minority interest inInnoVent SAS, a French wind farm developer with morethan 600 MW of wind projects in development. AES hasthe option to acquire majority control of a significant

portion of InnoVent projects during the next five years.The company expects to begin construction of 40 MW ofprojects in 2007 and anticipates adding at least 50 MW to100 MW each year during the next 5 years.

In October 2006, AES additionally acquired a minoritystake in the 120 MW Geo Energy wind project located innortheastern Bulgaria around the city of Varna. Geo Energywill sell power to NEK, the national Bulgarian grid ownerand operator, which provides preferential connection sta-tus for wind projects. Kavarna is being developed in part-nership with Geo Power Ltd., a Bulgarian-Germanrenewable energy development company.

In December 2006, AES sold its equity stake in U.S. WindForce, a Pennsylvania-based developer of wind projects,back to the company.

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HOLDING COMPANY STRUCTURE

AES, a Delaware corporation, is organized in a holdingcompany structure. Our operating assets are held as whollyor partially owned subsidiaries or controlled affiliates thatgenerally have no financial recourse to the parent company.The parent invests in its subsidiaries primarily in the formof equity investments and, to a lesser extent, through inter-company loans. The consolidated financial statements ofthe company include the accounts of the parent, its sub-sidiaries and its controlled affiliates on a consolidated basis.Investments in which the parent has the ability to exercise

significant influence but not control (generally, investmentsless than 50% owned) are accounted for using the equitymethod. As of December 31, 2006, the entities in whichAES had the ability to exercise significant influence but didnot control, and that were accounted for using the equitymethod included: Guacolda in Chile; Chengdu, Wuhu, and Yangcheng in China; OPGC in India; Elsta in theNetherlands; an affiliate of EDC in Venezuela; Innovent, a developer of wind energy projects in Scotland; andCartagena in Spain.

NON-RECOURSE FINANCING

AES has, to the extent practicable, used non-recourse debtand operating cash flows at the subsidiary level to fund asignificant portion of the development, construction andacquisition activity at its subsidiaries. Non-recourse borrowings at the subsidiaries are substantially non-recourseto other subsidiaries and to the parent, and are generallysecured by the capital stock, physical assets, contracts andcash flow of the related subsidiary. For certain subsidiaries,

the parent provides financial guarantees or other creditsupport for the benefit of lenders or other counterpartiesat the subsidiary level. If a subsidiary was to default on adebt payment or other counterparty obligation, the parentwould be responsible for the subsidiary’s obligation only up to the amount provided for in a relevant parent guarantyor credit support agreement.

PARENT CASH FLOWS AND CAPITALIZATION

In addition to non-recourse financing noted above, invest-ments by the parent in its subsidiaries provide a portion of the remaining long-term financing or credit required tofund development, construction and acquisition activity atthe subsidiary level. The funds for these parent investmentshave been and generally are provided by cash flows remittedto the parent by the subsidiaries and by the proceeds from

the issuance of recourse debt, common stock and othersecurities by the parent. Cash flows remitted to the parentby the subsidiaries (typically in the form of dividends, fees, interest payments and returns of capital) in turn service the cash needs of the parent, including parent interest expense, debt principal payments, taxes, and other parent operating expenses.

CAPITAL STRUCTURE DIAGRAM

To the extent practicable, we have included a diagram of the AES Consolidated Capital Structure on pages 130–131.

BALANCE SHEET STRENGTHENING

We have continued to make progress in strengthening our financial position in a number of ways. AES reducedoverall recourse debt at the parent level by approximately$780 million during 2004, $250 million in 2005, and$115 million in 2006 to approximately $4.8 billion at yearend 2006.

In June 2005, AES redeemed all outstanding 8.5% SeniorSubordinated Notes due 2007, at an aggregate principalamount of approximately $112 million. The notes wereredeemed at a redemption price of 101.417% of the principalamount, plus accrued and unpaid interest to the redemptiondate. In June 2005, AES amended its $450 million credit

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RECENT NON-RECOURSE DEBT FINANCING TRANSACTIONS

At the subsidiary level, AES refinanced or restructuredmore than $3.1 billion of non-recourse debt in 2006 andadded approximately $2.3 billion of new financing. Most ofthese efforts resulted in reduced interest rates and morefavorable amortization schedules and maturity dates. Thefollowing transactions include all material financings andrefinancings over $7.5 million.

In February 2006, AES El Salvador Trust issued $300 mil-lion of 6.75% Senior Guaranteed Notes due 2016. Proceedswere used to repay existing debt at the operating distributioncompanies CAESS, EEO, and Clesa, to pay a special dividendto shareholders, and for general corporate purposes.

In March 2006, Ekibastuz, in Kazakhstan, extended thetenor of its approximately $8 million loan with AllianceBank one year and entered into a new $8 million 5-year loanwith Bank Turan Alem. In December 2006, Ekibastuzsigned a $200 million credit agreement with Fortis torepay inter-company obligations.

In April 2006, Maritza, in Bulgaria, entered into anapproximately $989 million credit agreement with Calyon,BNP Paribas, and ING to fund construction of a new coalplant in Bulgaria. Proceeds were also to be used to fund aDSRA letter of credit facility and a working capital facility.COFACE, EBRD, MIGA, and Hermes have guaranteed a portion of the loan.

In April 2006, Buffalo Gap I, in Texas, entered into anagreement with JP Morgan, Prudential, New York Life,Union Bank of California, and Northwestern Mutual torefinance its construction loan with $117 million of taxequity. In September 2006, another wind generation proj-ect, Buffalo Gap II, also in Texas, secured a $320 millionconstruction loan and raised $321 million in tax equity fromDexia, Bayerische Hypo-und Vereinsbank AG, and Bayern LB.

In May 2006, Sul, in Brazil, entered into a $305 millioncredit agreement with Unibanco. The proceeds were usedto repay shorter maturity U.S. Dollar-denominated debt,repay Brazilian Reais-denominated debt, and extinguishinter-company loans.

facilities. The interest rate on the $450 million revolvingcredit facility was reduced to the London InterbankOffered Rate (LIBOR) plus 175 basis points. Previously, therate was LIBOR plus 250 basis points. In addition, the revolvingcredit facility maturity date was extended from 2007 to 2010.The interest rate on the term loan facility also was reducedto LIBOR plus 175, from LIBOR plus 225, while its matu-rity in 2011 remains unchanged.

In August 2005, AES redeemed all outstanding 4.5% JuniorConvertible Notes due 2005, at an aggregate principalamount of approximately $142 million. The Notes wereredeemed at par.

In September 2005, AES amended its $450 million revolv-ing credit facility by increasing the facility by $200 millionto $650 million. All other terms and conditions of the facil-ity remain unchanged.

In March 2006, the Company redeemed all of its outstanding8.875% Senior Subordinated Debentures due 2027(approximately $115 million aggregate principal amount).The redemption was made pursuant to the optionalredemption provisions of the indenture governing theDebentures. The Debentures were redeemed at aredemption price equal to 100% of the principal amount

thereof, plus a make-whole premium determined in accordance with the terms of the indenture, plus accruedand unpaid interest up to the redemption date.

The Company entered into a $500 million senior unse-cured credit facility agreement effective March 31, 2006. In May 2006, the Company exercised its option to extendthe total amount of the senior unsecured credit facility by an additional $100 million to a total of $600 million. As of December 31, 2006, the Company had no outstanding borrowings under the senior unsecured credit facility. The Company had $373 million of letters of credit out-standing against the senior unsecured credit facility as ofDecember 31, 2006. The credit facility is being used tosupport our ongoing share of construction obligations for AES Maritza East I and for general corporate purposes.AES Maritza East I is a coal-fired generation project thatbegan construction in the second quarter of 2006.

In December 2006, the Company exercised its right toincrease the secured revolving credit facility by $100 millionto a total of $750 million. As of December 31, 2006, therewere no outstanding borrowings against the revolving creditfacility. The Company had $88 million of letters of creditoutstanding against the secured revolving credit facility,and $662 million was available as of December 31, 2006.

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In May 2006, Itabo Finance S.A., a subsidiary of the Itabooperating company in the Dominican Republic, completedthe issuance of $125 million of 10.875% Senior Notes due2013. The Note proceeds were used to acquire an additional25% participation in Itabo. Proceeds were also used to repayexisting lenders, fund a capEx reserve, pay a special dividendto Itabo shareholders, and for general corporate purposes.

In May 2006, Cartagena, in Spain, secured a $78 millionbridge loan from Société Générale and Calyon. The proceedswere used to provide EPC incentive payments, fund delayliquidated damages, cover the cost of commissioning gas, cover financing costs and other costs related to theconstruction of Cartagena.

In May 2006, Eletropaulo, in Brazil, closed a syndicatedbank loan for approximately $141 million and used the pro-ceeds to retire short-term debt with a higher interest rate.

In May 2006, IPALCO, in Indiana, entered into a$120.6 million revolving credit facility with a consortium of banks led by LaSalle Bank (ABN Amro) and NationalCity Bank. In August, IPALCO increased the facility sizeto $150 million.

In May 2006, AES Eastern Energy, in New York, refinancedits $75 million working capital facility led by Calyon toextend the tenor and reduce the interest rate.

In August 2006, AES New York Surety, in New York,entered into a $350 million letter of credit facility withUnion Bank of California and Calyon. The facility providesperformance letters of credit to trading counterparties of AES Eastern Energy. Approximately $36 million of thefacility is used to provide additional liquidity at AESEastern Energy.

In September 2006, IPALCO, in Indiana, issued $60 millionof IFA Environmental Revenue Bonds Series 2006A and$40 million of 4.55% Pollution Control Bonds Series 2006B.The proceeds were used to retire IPALCO’s $40 million6.625% Pollution Control Bonds Series 1995A inDecember 2006.

In September 2006, Edelap, in Argentina, entered into anagreement with Bank Galicia and HSBC to restructureapproximately $17 million of local currency debt.

In October 2006, Brasiliana, in Brazil, prepaid approximately$568 million of BNDES debt and completed the issuanceof approximately $378 million of its 3rd Series Debentures.

In October 2006, Tietê, in Brazil, liquidated approximately$87 million of its Energia Paulista 2nd Series Debentures.In November 2006, Tietê repaid the Tietê IHB Cayman11.5% bonds in an amount of $286 million.

In October 2006, Gener, in Chile, refinanced $30 millionin bonds reducing the interest rate from 8% to 6.95% andextending the tenor by three years.

In October 2006, IPALCO, in Indiana, issued $158.8 millionof 6.05% first mortgage bonds due 2036. The net proceedsfrom this offering, together with other available cash, wereused to repay IPALCO’s 8% Series first mortgage bonds,due October 2006, in the principal amount of $58.8 millionand to prepay IPALCO’s 7.05% Series first mortgagebonds, due 2024, in the principal amount of $100 million.This transaction reduced interest expense by approximately1.0% and extended the maturity by 12 years.

In October 2006, Shady Point refinanced its outstanding$118 million of debt.

In October 2006, Barka, in Oman, entered into a $291 millioncredit agreement with a consortium led by Calyon, StandardChartered, and Arab Banking Corporation. Proceeds wereused to refinance existing debt, and pay a special dividend.

In December 2006, AES Panama completed the issuanceof $300 million of 6.35% Bonds due 2016 and used the proceeds to repay existing debt, to pay a special dividend,and for general corporate purposes.

In December 2006, Guacolda, in Chile, entered into anagreement with Calyon to refinance $390 million of debt.

In December 2006, SONEL entered into an approximately$340 million credit agreement with several multilateraland bilateral development banks. Proceeds will be used tofund new capital expenditures.


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in millions, except percentages, as of December 31, 2006Security Principal Balance Interest Rate Maturity Amortization Ratings(1)

SENIOR SECURED CREDIT FACILITIES Moody's/S&P/Fitch

Senior Secured Revolving Credit Facility due 2010(2) $ 750 Libor + 1.50% 6/23/10 No Ba1/NR/BB+Senior Secured Term Loan Facility due 2011 200 Libor + 1.75% 8/10/11 No Ba1/NR/BB+Total Senior Secured Credit Facilities(2) 950

SECOND PRIORITY SENIOR SECURED NOTES8.75% Second Priority Senior Secured Notes due 2013 1,200 8.750% 5/15/13 No Ba3/BB-/BB+9% Second Priority Senior Secured Notes due 2015 600 9.000% 5/15/15 No Ba3/BB-/BB+Total Second Priority Senior Secured Notes 1,800

SENIOR UNSECURED CREDIT FACILITIESSenior Unsecured Credit Facility due 2010(3) 600 Libor + Margin 3/31/10 No NRTotal Senior Unsecured Credit Facilities(3) 600

SENIOR UNSECURED NOTES8.75% Senior Notes due 2008 202 8.750% 6/15/08 No B1/B/BB9.50% Senior Notes due 2009 467 9.500% 6/1/09 No B1/B/BB9.375% Senior Notes due 2010 423 9.375% 9/15/10 No B1/B/BB8.375% Senior Notes due 2011(4) 167 8.375% 3/1/11 No B1/B/BB8.875% Senior Notes due 2011 307 8.875% 2/15/11 No B1/B/BB7.75% Senior Notes due 2014 500 7.750% 3/1/14 No B1/B/BBTotal Senior Unsecured Notes 2,066

TRUST PREFERREDS(5)

6.75% Trust Preferred III due 2029 517 6.750% 10/15/29 No B3/B-/B6.00% Trust Preferred VII due 2008 213 6.000% 5/15/08 No B3/B-/BTotal Trust Preferreds 730 Total Recourse Debt(2)(3)(6) 6,146

in millions, except per share data AverageSecurity Book Market Diluted Shares Closing Price

Equity $3,036 14,811 672 $22.04

(1) Ratings as of January 31, 2007

(2) Table assumes fully drawn Senior Secured Revolving Credit Facility. As of December 31, 2006, there were no outstanding borrowings and$88 million letters of credit outstanding under the Senior Secured Revolving Credit Facility.

(3) Table assumes fully drawn Senior Unsecured Credit Facility. As of December 31, 2006, there were no outstanding borrowings and $373 millionletters of credit outstanding under the Senior Unsecured Credit Facility. The margin on drawings under the Senior Unsecured Credit Facility isbased on the spread of the unsecured notes due 2010 and 2011 and was in the approximate range of 2.0–2.5% during 2006.

(4) Assumes an exchange rate of 1.9591/£ for the 8.375% Senior Sterling Notes due 2011. At December 31, 2006, £85 million remained outstanding.

(5) In accordance with the Statement of Financial Accounting Standards No. 150, the company reclassified its company-obligated convertiblemandatory redeemable preferred securities of subsidiary trusts holding solely junior subordinated debentures of the company to a liabilityaccounting beginning July 1, 2003.

(6) Recourse debt total does not include roughly $7 million of unamortized discount. Certain amounts may vary slightly from other presentationsdue to rounding.

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In July 2003, the parent entered into senior secured creditfacilities (the “Bank Facilities”) provided by a syndicate of financial institutions. The terms, maturities and com-mitment amounts of these facilities have been amended several times. The Bank Facilities are composed of: (i) a $750 million revolving credit facility (the “Revolver”)maturing on June 23, 2010, and (ii) a $200 million term loanfacility (the “Term Loan”) maturing on August 10, 2011. The interest rate margin on the Revolver is based on amatrix of ratings assigned to the Bank Facilities by Moody’sand Standard & Poor’s rating services. The interest rate onthe Term Loan is LIBOR + 1.75%. Currently, the Revolverbears an interest rate of LIBOR + 1.50% on drawn amounts,50 basis points on the unused portion of the facility, and1.50% on outstanding and undrawn letters of credit. Otherterms and conditions of the Bank Facilities are as follows:

Ranking, Security and Guarantees The Bank Facilitiesare senior obligations of the parent and benefit from a first priority perfected security interest in (i) all of the capitalstock of each of the material domestic subsidiaries owneddirectly by the parent and 65% of the capital stock of eachmaterial foreign subsidiary owned directly by the parentwith certain exceptions, and (ii) all material inter-companyreceivables, notes and tax sharing agreements owed to the parent by the subsidiaries. The bank facilities also benefit from upstream guarantees from the following four

inter mediate subsidiary holding companies: (i) AES HawaiiManagement Company, Inc., (ii) AES Oklahoma HoldingsLLC, (iii) AES Warrior Run Funding LLC, and (iv) AESNew York Funding, LLC (together, the “Guarantors”).

Amortization and Mandatory Redemption The BankFacilities have no fixed amortization requirements prior tomaturity, other than the primary mandatory redemptionsapplying to the Term Loan under the following circumstances:

■ Asset Sales Proceeds. With respect to net cash proceedsfrom sales of assets of or equity interests in IPALCO, a Guarantor, or any of their subsidiaries, the Term Loanshall be prepaid in an amount equal to 60% (the “Creditor’sPortion”) of net cash proceeds, provided that the 60%shall be reduced to 50% when and if the parent’s recoursedebt to cash flow ratio is less than 5:1. Lenders shall havethe option to accept or refuse such prepayment. In thecase of sales of assets of or equity interests in IPALCO or any of its subsidiaries, asset sale net cash proceedsremaining after application to the Term Loan facility shallbe used to reduce commitments under the Revolver,unless the supermajority banks otherwise agree or unlessthe facilities are rated at least Ba1 from Moody’s andAES’s corporate credit rating is at least BB– from S&P.

■ Debt Offering Proceeds. 100% of the net cash proceedsfrom the issuance of bridge debt by the parent must be

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PARENT DEBT MATURITIES SCHEDULEUS$ in millions

The chart above sets forth scheduled maturities with respect to outstanding recourse indebtedness and trust preferred securities. The table does not include obligationsof AES Corporation with respect to which there is no direct recourse to AES. In addition, the table does not include unscheduled maturities. The amounts above do not reflect unamortized discounts totaling $7 million that are used to calculate the book value of the debt. Total excludes letters of credit and other debt guarantees.Please see AES's SEC filings for further information.

■ Senior Secured Credit Facilities ■ Second priority Senior Secured Notes ■ Senior Unsecured Notes & Credit Facilities ■ Trust Preferreds

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offered to repay the Term Loan. With respect to the netcash proceeds from (i) the issuance of debt by IPALCO orany Guarantor (other than up to $200,000,000 of addi-tional debt of IPALCO and the Guarantors incurred afterJune 23, 2005) and (ii) the issuance of debt by any AES subsidiary the proceeds of which are not used for specified purposes, the Creditor’s Portion of such net cash proceeds shall be offered to the lenders under theTerm Loan facility to be applied to ratably prepay the Term Loan facility. Lenders shall have the option toaccept or refuse such prepayment.

Certain Covenants The Bank Facilities contain the following primary covenants:

■ Limitation on Debt. The parent may raise additional debtso long as (1) no default exists before or after giving effectto the new debt, and (2) if the additional debt is securedby the same collateral as the Bank Facilities, it has a matu-rity longer than the Term Loan and has no amortizationprior to the Term Loan maturity in an aggregate amountin excess of 10% of the initial amount of such debt. ■

Exceptions to this limitation are letters of credit, guaran-tees and other credit support permitted to be provided tothe subsidiaries that are permitted under the Investmentscovenant. Total first lien debt may not exceed 1,750,000,000including the existing Bank Facilities. New debt incurredby the subsidiaries is generally limited to permitted refinancing, debt incurred to finance development, construction and operation of a power supply business, and other issuances of debt provided the proceeds are distributed to the parent or a passive subsidiary of theparent and applied in accordance with the mandatoryredemption provisions described above.

■ Limitations on Restricted Payments. There is a generalrestricted payment basket exception equal to $25,000,000plus 5% (or less 100% if negative) of cumulative adjustedparent operating cash flow less corporate charges. Afterconsideration of this basket, the parent may not declareor pay any dividends or otherwise acquire for value any ofits equity interests other than dividends on and acquisi-tion or refinancing of the Trust Preferred securities.

■ Negative Pledge. The parent may not secure additionaldebt with the security provided to the Bank Facilitiesunless total first lien debt does not exceed $1,750,000,000including the existing Bank Facilities, except for (i) thesecond liens on the security provided to the SecondPriority Notes (as defined below) and (ii) any debt thatrefinances the Bank Facilities. Other liens are generallyprohibited with exceptions including for letters of credit

secured by cash in an amount not to exceed $300 million,and other existing secured obligations and certain customary exceptions.

■ Maximum Recourse Debt to Cash Flow Ratio. The parentmust maintain a recourse debt to cash flow ratio (definedas recourse debt divided by adjusted parent operatingcash flow for the last four quarters) less than 7.0:1 for thefourth quarter of 2006, declining over time to 6.0:1by 2010.

■ Minimum Cash Flow Coverage Ratio. The parent mustmaintain a cash flow coverage ratio (defined as adjustedparent operating cash flow divided by all-in parent financecharges for the last four quarters) greater than 1.4:1 for thefourth quarter of 2006, increasing over time to 1.5:1 byyear end 2007.

■ Limitation on Investments. The parent may not make anyinvestments in any excluded subsidiaries (as defined in theCredit Agreement) in an amount greater than $250 millionin the aggregate beginning June 23, 2005, unless at thetime of such investment the recourse debt to cash flowratio is less than to 4.0:1.

Events of Default In addition to customary covenant orpayment defaults uncured within the relevant grace period,the following parent and subsidiary events of bankruptcyor other defaults constitute events of default under the parent’s Bank Facilities:

■ Bankruptcy of the parent, any Guarantor, AES BVI II orany other subsidiary (other than Excluded Subsidiaries)that constitutes 10% or more of parent operating cashflow (“POCF”) for the last four quarters or 10% of consolidated assets on the date of determination. As of December 31, 2006, Eastern Energy, EDC andIPALCO meet this definition based on POCF.

■ Acceleration of any debt maturity or financing com -mitment greater than $50 million of the parent or anysubsidiary or subsidiaries which in the aggregate accountfor 15% or more of POCF for the last four quarters. As ofDecember 31, 2006, Eastern Energy meets this definition.

■ Default under debt of the parent in excess of $50 millionif the effect would be to accelerate or permit accelerationof that debt.

■ Judgment defaults greater than $25 million of the parentor any subsidiary which accounts for 10% or more ofPOCF for the last four quarters or subsidiaries which inthe aggregate account for 15% or more of POCF for thelast four quarters. As of December 31, 2006, EasternEnergy, EDC and IPALCO meet this threshold.

■ Certain ERISA and change of control defaults.

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The Company entered into a $500 million senior unsecuredcredit facility agreement effective March 31, 2006. InMay 2006, the Company exercised its option to extend thetotal amount of the senior unsecured credit facility by anadditional $100 million to a total of $600 million. The senior unsecured facility matures on March 31, 2010 andAES has right to terminate at its option, either all or inpart, at any time without any penalty.

Other terms of the unsecured facility are as follows.

Ranking, Security and Guarantees The obligationsunder the unsecured facility rank pari passu with all otherunsecured and unsubordinated obligations of the parent.

Amortization and Mandatory Redemption The obliga-tions under the unsecured credit facility have no fixedamortization requirements prior to maturity.

Certain Covenants The senior unsecured facility containsthe following primary covenants:

■ Restrictions on Secured Debt. The unsecured facility mustbe equally and ratably secured with any issuances of parent debt secured by a lien on any principal propertyowned by the parent (the parent does not currently ownany principal properties) or the capital stock or indebted-ness of any subsidiaries held by the parent, if to the extent

such secured debt (including debt attributable to sale andleaseback transactions) exceeds the sum of: (i) 15% of consolidated net assets, defined as total assets less currentliabilities as shown in the most recent annual report, and(ii) liens under any credit facilities in an amount not toexceed $900 million. Such restrictions shall not apply toliens on any property of any subsidiary of the parent, aswell as certain other exceptions.

■ Restrictions on Sales and Leasebacks. Sale and leasebacktransactions by the parent involving a principal property(the parent does not currently own any principal properties)more than 180 days after the acquisition or constructionthereof must either: (i) be permissible under the terms ofthe Restrictions on Secured Debt covenant describedabove, or (ii) the proceeds or fair market value of thetransaction must be used to retire debt.

Events of Default In addition to customary covenant andpayment defaults uncured within the relevant grace periods,certain events of bankruptcy or insolvency (either voluntaryor involuntary) by AES or any Significant AES Entity, aswell as, payment default or cross-acceleration of at least$50 million of parent debt constitute an event of defaultunder the Senior Unsecured Credit Facility. SignificantAES Entity includes a subsidiary contributing 10% or moreof the last twelve months parent operating cash flow or hold-ing 10% or more of the consolidated total assets of the par-ent and its subsidiaries.

SENIOR UNSECURED CREDIT FACILITY DUE 2010

In May 2003, the parent issued $1.2 billion 8.75% SecondPriority Senior Secured Notes due May 15, 2013, and$600 million 9% Second Priority Senior Secured Notes dueMay 15, 2015 (together, the “Second Lien Notes”). Proceedsfrom the offering of the Second Lien Notes were used to fundthe cash tender of other parent notes, repay bank facilities,and fund working capital, fees and expenses. The SecondLien Notes pay interest semiannually and are redeemable atthe Company’s option at a Treasuries + 100 basis pointsmake-whole premium prior to May 15, 2008, and thereafterare callable at a premium initially equal to half the coupondeclining to par by May 15, 2011. Other terms and conditionsof the Second Lien Notes are as follows:

Ranking, Security and Guarantees The Second LienNotes are secured by second-priority liens on the collateralsecuring the other Bank Facilities and first lien debt. Theparent may amend the provisions of the security documentsrelating to the collateral with the consent of the requisitelenders under the Bank Facilities and without the consent of

the Second Lien Notes, provided that any such amendmentor release which would amend or release all, or substantiallyall, of the collateral will require the majority consent of theSecond Lien Notes.

Amortization and Mandatory Redemption The SecondLien notes have no fixed amortization requirements priorto maturity, other than any mandatory redemptionrequired pursuant to asset sales, if applicable (see below).

Certain Covenants The Second Priority Notes have thesame covenants as the Senior Unsecured Notes and contain additional covenants, including, but not limited to, the following:

■ Negative Pledge. New first or second priority debt securedby the collateral may only be incurred, subject to certainexceptions if, pro forma for such issuance, total first orsecond priority debt secured by the collateral does notexceed 2.75 times POCF (as defined) for the last four

SECOND PRIORITY SENIOR SECURED NOTES DUE 2013 AND 2015


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quarters. Notwithstanding the foregoing, the parent may incur certain debt, including (i) first or second priority debt in an amount not to exceed $3.0 billion lessthe amount of such debt permanently repaid or repur-chased with the proceeds of assets dispositions and(ii) obligations under interest rate and foreign currencyhedging agreements. The preceding limitation shall notapply to permitted refinancings of secured debt.

■ Limitation on Restricted Payments. Subject to certain excep-tions, the parent may not make any restricted payments if after giving effect to such payment: (i) a defaultor an event of default (as defined in the indenture) isoccurring, (ii) consolidated fixed charge coverage wouldbe less than 1.75:1, or (iii) the aggregate amount ofrestricted payments subsequent to May 8, 2003 wouldexceed the sum of 50% of cumulative Net Income fromApril 1, 2003, to the last day of the immediately proceedingfiscal quarter prior to the date of such calculation (100%of a loss), plus net proceeds from equity issuances by theparent subsequent to May 8, 2003, less optional redemp-tions of any parent debt other than the first-lien debt, anyrevolving credit facility or second priority debt.

■ Limitations on Asset Dispositions. Subject to certain exceptions, consideration received for asset sales must be for fair market value and at least 75% cash or propertyor assets used in a power supply business. Further, the netcash proceeds from such asset sale must be applied either

to (i) reduce first secured debt, or (ii) to the extent suchreduction is not required by the first priority debt, thenreinvested in the business or used to repay second prioritydebt of the parent or any debt of a subsidiary, or (iii) usedto offer to purchase the Second Lien Notes.

■ Subsidiary Guarantees. If the parent pledges any asset tosecure, or if any subsidiary shall guarantee certain speci-fied unsecured notes of AES, then the same pledge andguarantee shall apply equally and ratably to the SecondLien Notes.

Change of Control Holders have the right to require theparent to repurchase the Second Lien Notes at 101% upona change of control.

Events of Default In addition to customary covenant andpayment defaults uncured within the relevant grace periods,certain events of bankruptcy or insolvency (either voluntaryor involuntary) by AES or any material subsidiary, as well as, payment default or cross-acceleration by AES of at least$50 million of parent debt constitute an event of defaultunder the Second Lien Notes. Material subsidiary is definedto mean, as of any date, any subsidiary of which AES’s proportionate share of such subsidiary’s total assets (afterinter-company eliminations) exceeds 15% of the total assetsof AES on a consolidated basis.

Multiple issues due 2008, 2009, 2010, 2011 and 2014The parent has outstanding six different issues of SeniorUnsecured Notes (together, the “Senior Notes”) aggregatingapproximately $2.1 billion face amount due between 2008and 2014. All of these notes pay interest semi-annually and,with the exception of the 7.75% Senior Notes due 2014, areredeemable at the company’s option at a Treasuries + 50 basispoints plus a make-whole premium to each issue’s maturitydate. The 7.75% Senior Notes due 2014 are redeemable at thecompany’s option at a Treasuries + 75 basis points make-wholepremium. Other terms of the Senior Notes are as follows:

Ranking, Security and Guarantees The Senior Notes are unsecured and unsubordinated obligations of the parent ranking pari passu with all other unsecured andunsub ordinated obligations of the parent.

Amortization and Mandatory Redemption The SeniorNotes have no fixed amortization requirements prior tomaturity.

Certain Covenants The Senior Notes contain the follow-ing primary covenants:

■ Restrictions on Secured Debt. The Senior Notes must beequally and ratably secured with any issuances of parentdebt secured by a lien on any principal property owned bythe parent (the parent does not currently own any princi-pal properties) or the capital stock or indebtedness of any subsidiaries held by the parent, if to the extent suchsecured debt (including debt attributable to sale and lease-back transactions) exceeds the sum of: (i) 15% of consoli-dated net assets, defined as total assets less currentliabilities as shown in the most recent annual report, and(ii) liens under any credit facilities in an amount not toexceed $900 million. Such restrictions shall not apply toliens on any property of any subsidiary of the parent, as wellas certain other exceptions.

■ Restrictions on Sales and Leasebacks. Sale and leasebacktransactions by the parent involving a principal property(the parent does not currently own any principal proper-ties) within 180 days of the acquisition or constructionthereof must either: (i) be permissible under the terms of the Restrictions on Secured Debt covenant describedabove, or (ii) the proceeds or fair market value of thetransaction must be used to retire debt.

SENIOR UNSECURED NOTES

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Events of Default In addition to customary covenant andpayment defaults uncured within the relevant grace periods,certain events of bankruptcy or insolvency (either voluntaryor involuntary) by AES or any Material Subsidiary, as wellas, payment default or cross-acceleration of at least $50 millionof parent debt constitute an event of default under the SeniorNotes. Material subsidiary is defined to mean, as of any date,

any subsidiary of which AES’s proportionate share of suchsubsidiary’s total assets (after inter-company eliminations)exceeds 15% of the total assets of AES on a consolidatedbasis. This material subsidiary definition became effectivepursuant to the consent solicitation which was completedon April 3, 2003, and as a result was changed from the definition which originally applied to the Senior Notes.

In 1999 and 2000, AES Trust III and AES Trust VII (bothDelaware business trusts and wholly-owned subsidiaries ofthe parent) issued Trust Convertible Preferred Securities(the “Trust Preferreds”) in the amounts of $517 million and$460 million, respectively. The current amount outstandingas of December 31, 2006 was $517 million and $213 million,respectively. The only assets of the respective trusts consistof Junior Subordinated Convertible Debentures (the“Debentures”) of equal principal amounts issued by theparent to the Trust simultaneously with the issuance of theTrust Preferreds. The Debentures pay a quarterly couponequal to the quarterly distributions paid by the Trust Preferredsto the holders of the securities. The Trust Preferreds areconvertible into the common stock of the parent at anytime prior to maturity at the conversion prices listed below.In addition, the parent has the option to defer cash interestpayments on the Debentures for up to 20 consecutive quartersduring the tenor of the Debentures, provided that suchdeferrals will continue to accrue interest. The Debenturesare unsecured obligations of the parent and are subordinateto all other senior and subordinated debt of the parent.

6.75% Trust III due 2029 The Trust IIIs were issued inOctober 1999 in the amount of 10.35 million securities at aface amount of $50 per security ($517.5 million of proceeds),paying an annual dividend of $3.375 per security (6.75% perannum) payable quarterly. The associated Debenturesmature on October 15, 2029, and are currently callable at apremium of 100.844%, declining to par on October 15,2007. The Trust IIIs are convertible at the option of theholder to 1.4216 common shares at any time prior to matu-rity or redemption at a conversion price of $35.17. TheTrust IIIs are listed on the NYSE.

6.00% Trust VII due 2008 The Trust VIIs were issued inMay 2000 in the amount of 9.2 million securities at a faceamount of $50 per security ($460 million of proceeds),paying an annual dividend of $3.00 per security (6.00% perannum) payable quarterly. The associated Debenturesmature on May 15, 2008, and are currently callable at apremium of 100.75%, declining to par at maturity. TheTrust VIIs are convertible at the option of the holder to1.0811 common shares at any time prior to maturity orredemption at a conversion price of $46.25.

The common stock of the parent is traded on the NewYork Stock Exchange (NYSE) under the symbol “AES.”The number of shares of common stock outstanding onDecember 31, 2006, was 665,127,951 at a par value of$0.01 per share, and the number of authorized shares of common stock was 1,200,000,000.

Description of Common Stock The holders of commonstock are entitled to one vote per share on all matters to bevoted on by the stockholders. If we liquidate our business,the holders of common stock are entitled to share ratablyin all assets after we pay our liabilities and the liquidationpreference of any outstanding preferred stock, of which thereis currently none. The common stock has no preemptive orconversion rights or other subscription rights. There are noredemption or sinking fund provisions applicable to the

common stock. All outstanding shares of common stockare fully paid and non-assessable. The transfer agent for ourcommon stock is Computershare.

Dividends Subject to preferences that may be applicableto any outstanding preferred stock (of which there is currentlynone), the holders of common stock are entitled to ratablyreceive dividends as may be declared from time to time byour board of directors out of funds legally available to paydividends. No cash dividends have been paid on our commonstock since December 22, 1993. Under the terms of thecurrent bank facility, the parent company is not allowed topay cash dividends. In addition, the indentures relating to the second lien notes contain provisions that wouldpotentially preclude or limit the payment of cash dividends.

TRUST CONVERTIBLE PREFERRED SECURITIES

COMMON STOCK


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Options, Deferred Compensation Arrangements andConvertible Securities Our diluted earnings per share calculations include the dilutive effect of potential commonstock pursuant to options, restricted stock and convertiblesecurities, to the extent that these securities were dilutivein a period. The table below outlines the potential commonstock pursuant to these arrangements.

The options represent options granted to employees topurchase shares under four stock option plans – The AES Corporation 2001 Stock Option Plan, The AESCorporation 2001 Non-Officer Stock Option Plan, The AES Corporation 2001 Stock Option Plan for OutsideDirectors and The AES Corporation 2003 Long-TermCompensation Plan. Under the terms of the plans, we mayissue options to purchase shares of AES common stock at a price equal to 100% of the market price of the date theoption is granted. The options become eligible for exerciseunder various schedules. The Trust Preferred securities represent the underlying shares pertaining to those securities at their respective conversion prices.

AES issued restricted stock units under its long-term compensation plan in 2004 and 2005. The restricted stockunits are generally granted based on a percentage of theparticipant’s base salary. The units have a three-year vestingschedule and vest in one-third increments over the three-year

period. The units are then required to be held for an additional two years before they can be redeemed forshares, and thus become transferable. Shares issued to officersare issued at a premium, since the vesting is subject tomeeting specific performance objectives. AES issued1,031,082 restricted stock units in 2005 and 1,847,670in 2004, and recorded $10 million and $5 million in compensation expense related to these amounts in 2005and 2004, respectively.

Basic and diluted earnings per share computations arebased on the weighted average number of shares of commonstock and potential common stock outstanding during theperiod, after giving effect to stock splits. Potential commonstock, for purposes of determining diluted earnings pershare, includes the dilutive effects of stock options, restrictedstock and convertible securities. The effect of such potentialcommon stock is computed using the treasury stockmethod or the if-converted method, in accordance withStatement of Financial Accounting Standards (“SFAS”)No. 128, “Earnings Per Share.”

There were approximately 28,035,227 options outstandingat December 31, 2005 that were omitted from the earningsper share calculation for the year ended December 31, 2005,because they were antidilutive.

The parent periodically provides guarantees, letters ofcredit and other financial commitments to the benefit of itssubsidiaries and its subsidiaries’ counter-parties. As ofDecember 31, 2006, the company had provided outstandingfinancial and performance related guarantees or othercredit support commitments to or for the benefit of itssubsidiaries, which were limited by the terms of the agree-ments, to an aggregate of approximately $533 million(excluding those collateralized by letter-of-credit obligationsdiscussed below).

As of December 31, 2006, the company had $461 millionin letters-of-credit outstanding, which operate to guaranteeperformance relating to certain project development activities and subsidiary operations. The company pays aletter-of-credit fee ranging from 1.63% to 2.64% per annumon the outstanding amounts.

CONTINGENT OBLIGATIONS

POTENTIAL COMMON STOCK AS OF DECEMBER 31, 2006

thousands of shares Options Options Trust Preferred Range of Exercise prices or conversion prices Outstanding Exercisable Securities

$ 0.78– 3.24 3,305 3,230 0$ 3.25– 9.88 1,955 1,249 0$ 9.89–14.40 13,255 13,251 0$14.41–22.85 6,251 2,981 0$22.86–58.00 4,236 4,236 19,326$58.01–80.00 9 9 0Total 29,011 24,956 19,326

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in millions for the year ended December 31 2004 2005 2006

SOURCESTotal Subsidiary Distributions(1) $ 1,004 $ 993 $ 971 Proceeds from Asset Sales, net 13 2 265 Refinancing Proceeds, net 480 – –Increased Credit Facility Commitments 200 200 700 Issuance of Common Stock, net 16 26 80 Total Returns of Capital Distributions and Project Financing Proceeds 127 57 72 Beginning Liquidity(1) 1,071 643 624 Total Sources $ 2,911 $ 1,921 $ 2,712

USESRepayments of Debt $(1,138) $ (259) $ (150)Investments in Subsidiaries, net (477) (233) (577)Cash for Development, Selling, General and Administrative Expenses and Taxes (156) (165) (243)Cash Payments for Interest (473) (426) (424)Other (24) (214) (172)Ending Liquidity(1) (643) (624) (1,146)Total Uses $(2,911) $(1,921) $(2,712)

PARENT SOURCES AND USES OF CASH

AES has historically provided investors with parent-onlycash flow data, unconsolidated from the company’s subsidiaries. This data is considered an important indicatorof the parent’s liquidity due to the non-recourse nature ofmost of the company’s consolidated debt. The parent’s cashflows for 2004, 2005 and 2006 are presented above. Thisdata reflects cash flows at the parent level, unconsolidatedfrom the company’s subsidiaries.

Total Subsidiary Distributions Total subsidiary distribu-tions represent distributions (excluding returns of capital)in cash by the subsidiaries to the parent and to qualifiedholding companies (QHCs) of the parent. Distributions are

primarily comprised of dividends, consulting and manage-ment fees, inter-company interest payments, and tax sharing payments received by the parent in cash from thesubsidiaries, after subsidiaries meet all cash requirementsat the subsidiary-level for operations, capital expenditures,non-recourse debt principal and interest payments and anyother cash needs. QHCs are subsidiaries domiciled outsideof the United States, with no contractual restrictions ontheir ability to send cash to the parent. Cash at QHCs isused for investments and related activities outside the U.S.,including equity investments and loans to other foreignsubsidiaries as well as development and general costs andexpenses incurred outside the U.S.

PARENT CASH FLOWS

CONTINGENT OBLIGATIONS AS OF DECEMBER 31, 2006

dollars in millions Number of Exposure Range for Amount Agreements Term Range each Agreement

Guarantees $533 32 <1–20+ <$1–$100Letters of Credit – under the Revolving Credit Facility 88 12 <1–3 <$1–$ 26Letters of Credit – under the Senior Unsecured Credit Facility 373 8 <1–3 <$1–$333Surety bonds 1 1 1 <$1 )Total $995 53

(1) Non-GAAP financial measure, see page 21.


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Proceeds from Asset Sales, Net Proceeds from asset salesrepresent cash proceeds received by the parent from assetsales, net of transaction fees, expenses and taxes and net ofany non-recourse debt assumed by the purchaser or repaid inconjunction with the sale. In summary, proceeds from assetsales represents the after-tax cash proceeds from the parent’ssale of its equity stake in any business. Asset sales in 2006consisted primarily of the sale of approximately 8% of AESshare in Gener in Chile, and the sale of the Kingston(Canada), Indian Queens (United Kingdom) and Windforce(United States) projects. There were no significant proceedsfrom asset sales in 2005. Asset sales in 2004 include primarily the Mountainview project in California.

Refinancing Proceeds, Net Refinancing proceeds reflectproceeds from issuances by the parent of bank debt anddebt securities, net of transaction costs and expenses. Thisfigure excludes financing conducted at the subsidiary level.Actual results for 2004 reflect the refinancing of the$500 million Term Loan in February.

Increased Revolver Commitments Increased Revolvercommitments reflect increased availability under oursecured and unsecured credit facilities. Actual results for2006 include the addition of the $600 million unsecuredcredit facility in the first half of the year, as well as the$100 million upsize of the secured revolving credit facility inDecember 2006. Actual results for 2005 reflect a $200 mil-lion upsize of the secured revolving credit facility inSeptember 2005. Actual results for 2004 reflect a$200 million upsize of the secured revolving credit facilityin March 2004.

Issuance of Common Stock, Net Issuance of commonstock reflects proceeds from issuances by the parent ofequity securities (including equity associated with the exer-cise of stock options), net of transaction costs and expenses.

Total Returns of Capital and Project Financing ProceedsTotal returns of capital represent cash redemptions of theparent’s investments in subsidiaries, funded partially bynon-recourse financings at the subsidiary level. These subsidiary-level recapitalization proceeds are shown net oftransaction fees, expenses and taxes. Actual results for2006 are primarily comprised of returns of capital fromBuffalo Gap II and Maritza East 1. Actual results for 2005are primarily composed of project financing proceeds atBuffalo Gap I and returns of capital from Barka. Actualresults for 2004 are primarily composed of returns of capital funded by a non-recourse financing at Ebute.

Repayments of Debt Repayments of debt reflect fixed debtamortization requirements at the parent, optional redemptionsof parent debt, as well as any pay-downs pursuant to manda-tory redemption provisions (such as asset sale sweeps) in any parent debt agreements, in each case funded by available parent cash or any proceeds from parent debt or equityfinancings. This figure excludes any scheduled maturities at the subsidiary level. Actual results for 2006 reflect the$115 million optional redemption of the 8.875% SeniorSubordinated Debentures due 2027. Actual results for 2005reflect the redemption of the 8.5% Senior SubordinatedNotes due 2007, at an aggregate principal amount of approxi-mately $112 million and the maturity of $142 million of the4.5% convertible junior subordinated notes in August 2005.

Investments in Subsidiaries, Net Investments in subsidiaries, net reflects cash investments by the parent orQHCs into subsidiaries to finance construction, develop-ment, and acquisitions, and in some cases, operating cashrequirements and legal settlement costs at the subsidiarylevel. Investments are made primarily in the form of equityinvestments and, to a lesser extent, through inter-companyloans. Investments in subsidiaries, net excludes capitalexpenditures at the subsidiary level funded by subsidiary cashflows from operations or financing. Capital expenditures inAES’s consolidated financial statements reflect capital expen-ditures at the subsidiary level regardless of how thoseexpenditures are funded (whether by investments from theparent or by subsidiary cash flow and non-recourse financing).

Cash for Development, Selling, General andAdministrative Expenses and Taxes This line itemreflects parent level cash expenses for parent overhead costs,development costs incurred by the parent, and cash taxespaid by the parent. These costs are incurred primarily byparent headquarters in Arlington and also by regional devel-opment and administrative offices around the world. Thisfigure excludes any SG&A, overhead, development or taxexpenses incurred and paid at the operating subsidiary level.

Cash Payments for Interest This line item reflects cashinterest expense at the parent level on parent debt andTrust Preferred securities. This figure excludes interestexpense at the subsidiary level. In addition, amounts shownare not calculated on an accrued basis but rather when theinterest was paid in cash.

Other Other uses primarily reflect increases in letters of creditoutstanding under our secured and unsecured credit facilities.

Liquidity Liquidity represents unrestricted cash and cashequivalents at the parent and at QHCs, as well as availabilityunder the parent’s credit facilities. This figure excludes cashand availability under credit facilities at the subsidiary level.

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AES CONSOLIDATED DEBT STRUCTURE DIAGRAM AS OF DECEMBER 31, 2006USD in millions $ in color represents subtotal, not actual debt

Recourse debtNon-recourse debt

AES$4,790

TOTAL NON-RECOURSE DEBT$11,555

NORTH AMERICA$4,727

MEXICO$108

MÉRIDA III$108

AES HAWAII$457

AES PUERTO RICO$884

BEAVER VALLEY$2

EASTERN ENERGY$13

IPALCO$750

IRONWOOD$298

RED OAK$358

SHADY POINT$117

SOUTHLAND$548

WARRIOR RUN$304

ARGENTINA$165

EDELAP$21

EDES$111

PARANA$33

BRASILIANAENERGIA

$375

INFOENERGYURUGUAIANA

SUL$344

CACHAGUA$119

NORGENER$17

DOMINICANA$160

ITABO (HOLDCO)$11

EL SALVADOR TRUST$300

AES PANAMA$304

EDC$309

USA$4,619

ELETROPAULO$980

TELECOM$1

TIETÊ$635

GENER$530

CHIVOR$225

ELEC. SANTIAGO$66

IPL$888

BRAZIL$2,335

CHILE/COLOMBIA$957

ANDRES LOS MINA (DDP)

ENERGIA VERDETERMOANDES

DOMINICANREPUBLIC $317

ITABO (OPCO)$146

EL SALVADOR$300

CAESSCLESA

DEUSEMEEO

PANAMA$304

VENEZUELA$309

LATIN AMERICA$4,687

This diagram is intended to complement the descriptionsof our non-recourse and recourse credit facilities includedin this fact book and our other disclosures.

The diagram presents our non-recourse debt facilities on a business or entity level organized regionally, withAlternative Energy in “Other.” These amounts are then


AES

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Entity with recourse debt Entity with non-recourse debt Entity without consolidated debt Shown for organizational context only

Recourse debtNon-recourse debt

AES$4,790

TOTAL NON-RECOURSE DEBT$11,555

BULGARIA$244

MARITZA EAST I$244

SONEL$118

BORSOD$6

TISZA II$91

EKIBASTUZ$17

MAIKUBEN$15

EBUTE$74

KILROOT$391

KIEVOBLENERGO$9

RIVNEENERGO$7

CHINA$194

CHIGEN$175

AIXI$11

HEFEI$4

JIAOZUO$4

CAMEROON$118

CHENGDUCILI

WUHUYANGCHENG

HUNGARY$97

OMAN$278

BARKA$278

LAL PIR$22

PAK GEN$20

RAS LAFFAN$478

KELANITISSA$61

KAZAKHSTAN$32

PAKISTAN$42

NIGERIA$74

QATAR$478

SRI LANKA$61

UNITED KINGDOM$391

UKRAIINE$16

USA$116

BUFFALO GAP 2$116

EUROPE, CIS & AFRICA$972

ASIA & MIDDLE EAST$1,053

OTHER$116

NOTES■ This diagram is unaudited and is for reference purposes only. Certain amounts have been rounded for presentation purposes.

■ This diagram only reflects amounts included on the AES consolidated balance sheet. It does not include, among others, debt of equity method affiliates, debt of entities accounted for as operating leases or committed, but undrawn facilities.

■ AES businesses or entities that do not have material debt (>$1 million) are not shown, unless they support other non-recourse debt.

■ Recourse debt is supported by cash flows to the parent company from additional businesses not shown in this diagram.

■ Graphic does not capture all intermediary holding companies (including QHCs), nor does it attempt to do so.

■ For simplicity and consistency with other sections of this document, full legal names of entities are not used unless necessary to distinguish among entities.

presented summed per country and per segment. The sum of our non-recourse debt per segment equals thetotal consolidated non-recourse debt in our portfolio,

presented at the top of the diagram. The diagram alsoshows the balance of recourse debt at the AES Corp level.

1 3 2 A E S 2 0 0 6 FA C T B O O K

Country/State Business Line of Business 2007 2008 2009 2010 2011 Thereafter TOTAL

NORTH AMERICAMexico Merida III Generation 13 11 12 13 14 45 108

USA – California Southland Generation 41 46 50 50 51 310 548 USA – Hawaii Hawaii Generation 20 17 19 20 22 359 457 USA – Indiana IPALCO Utilities 155 375 – – 375 733 1,638 USA – Maryland Warrior Run Generation 24 26 28 29 32 165 304 USA – New Jersey Red Oak Generation 6 8 13 12 13 306 358 USA – New York Eastern Energy Generation 2 2 2 2 2 3 13 USA – Oklahoma Shady Point Generation – 11 11 11 11 73 117 USA – Pennsylvania Beaver Valley Generation – – – – – 2 2

Ironwood Generation 10 13 11 12 14 238 298 USA – Puerto Rico Puerto Rico Generation 54 33 35 39 42 681 884

Total North America 325 542 181 188 576 2,915 4,727

LATIN AMERICAArgentina Edelap Utilities 2 3 4 4 4 4 21

Edes Utilities 91 2 2 2 3 11 111 Parana Generation 33 – – – – – 33 Brasiliana Energia Utilities – – – – – 375 375

Brazil Eletropaulo Utilities 186 138 135 342 65 115 981 Sul Utilities 18 13 22 28 38 225 344Tietê Generation 75 83 91 101 111 174 635

Chile, Colombia Gener Generation 19 71 88 85 46 648 957

Dominican Republic Dominicana (Andres and Los Mina) Generation – – – – – 160 160 Itabo Generation 14 15 3 – – 125 157

El Salvador El Salvador Utilities – – – – – 300 300

Panama Panama Generation 4 – – – – 300 304

Venezuela EDC Utilities 42 2 2 2 1 260 309 Total Latin America 484 327 347 564 268 2,697 4,687

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Country/State Business Line of Business 2007 2008 2009 2010 2011 Thereafter TOTAL

EUROPE, CIS & AFRICABulgaria Maritza East I Generation – – – 13 14 217 244

Cameroon SONEL Utilities 63 14 12 16 5 8 118

Czech Republic Bohemia Generation – – – – – – –

Hungary Borsod Generation 5 1 – – – – 6 Tisza II Generation 91 – – – – – 91

Kazakhstan Altai Generation – – – – – – – Ekibastuz Generation 10 3 2 2 – – 17 Maikuben Generation 3 3 3 3 3 – 15

Nigeria Ebute Generation 31 31 4 4 4 – 74

UK Kilroot Generation 156 78 78 78 – 1 391

Ukraine Kievoblenergo Utilities 2 1 1 1 1 3 9 Rivneenergo Utilities 1 1 1 1 1 2 7

Total Europe, CIS & Africa 362 132 101 118 28 231 972

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ASIA & MIDDLE EASTChina CHIGEN Generation 11 4 4 175 – – 194

Oman, Pakistan Oasis (Barka, Lal Pir & Pak Gen) Generation 55 31 20 20 23 171 320

Qatar Ras Laffan Generation 39 35 33 33 37 301 478

Sri Lanka Kelanitissa Generation 61 – – – – – 61 Total Asia & Middle East 166 70 57 228 60 472 1,053

OTHERUSA – Texas Buffalo Gap II Generation 116 – – – – – 116

Total Other 116 0 0 0 0 0 116 TOTAL NON-RECOURSE DEBT 1,453 1,071 686 1,098 932 6,315 11,555

Note: The preceding table is unaudited and is for reference purposes only. This table provides debt amortization of the business unit and subsidiary holding company.

Any of these amortization schedules could be revised or accelerated for a number of reasons, including events of default, if any. The maturities shown include

unamortized discounts used to calculate the book value of debt. Certain amounts have been rounded for presentation purposes. For further details on non-

recourse debt, please refer to AES Corporation's SEC filings and press releases made from time to time.

To request a Microsoft® Excel version of this table, please contact Hilary Maxson at [email protected] or 703-682-6597.

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1 3 6 A E S 2 0 0 6 FA C T B O O K

As of June 30, 2007, AES’s Board of Directors was composedof 10 members. Nine members met the standards of inde-pendence established by the NYSE and the Sarbanes OxleyAct, including the Chairman of the Board. Please see ourwebsite for the current list of directors and their biographies.

AES news, quarterly earnings results, and information on AES plants and utilities around the world can beobtained at our website: www.aes.com.

Investors and interested parties can also subscribe to AESe-mail alerts in the Investor Information section to receivenotifications on the news, upcoming events, financialreports, presentations and SEC filings.

Certain hard copies of Investor Publications can also berequested in the section Order Publications or by callingInvestor Relations at (703) 682-6597.

AES’s independent auditor is Deloitte & Touche LLP.

GENERAL INFORMATION

AES became a public company on June 25, 1991, with an initial stock price of $19.00. Since going public, AES stockhas undergone the following stock splits:■ 3 for 2 stock split on January 15, 1994■ 2 for 1 stock split on July 20, 1997■ 2 for 1 stock split on June 1, 2000

AES is listed on the New York Stock Exchange under the tickerAES. The CUSIP for AES common stock is 00130H-10-5.

At December 31, 2006, there were approximately 7,117 AESshareholders of record. Currently AES does not have a dividend reinvestment program, and does not have plans to pay common stock dividends.

AES common stock can be bought or sold through a brokeragefirm. AES Corporation has designated Computershare(formerly EquiServe) as the transfer agent for AES common stock. Computershare can provide assistancewith lost or stolen AES stock certificates, address changes,name changes and stock transfers.

ComputershareP.O. Box 43010Providence, RI 02940-3069Calls inside the US: (781) 575-2879Calls outside the US: (781) 575-2726www.computershare.com

AES COMMON STOCK

AES Trust III

$3.375 Trust Convertible Preferred Securities Series C

Ticker (NYSE): AESPRCCUSIP: 00808N202Issuance size: $517.5 millionStated maturity: October 15, 2029Number of securities issued: 10,350,000Liquidation amount: $50 per securityAnnual dividend: $3.375 (6.75%) per security

paid quarterly

Each $50 security is convertible into 1.4216 commonshares of AES.

AES Trust VII

$3.00 Trust Convertible Preferred Securities

Ticker: NoneCUSIP: 00103V305 and

00103V206Issuance size: $460 millionStated maturity: May 15, 2008Number of securities issued: 9,200,000Liquidation amount: $50Annual dividend: $3.00 (6.0%) per security

paid quarterly

Each $50 security is convertible into 1.0811 shares of AES.

AES PREFERRED CONVERTIBLE SECURITIES

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For information about our convertible securities, please contact the trustee, Wells Fargo Bank, BondholderCommunications: (800) 344-5128.

1 3 75 : A P P E N D I C E S

On March 27, 2001 AES completed the acquisition ofIPALCO. IPALCO became a wholly-owned subsidiary of AES through an exchange of shares where each outstandingshare of IPALCO common stock was exchanged for0.463 shares of AES common stock.

Former shareholders of IPALCO common stock who didnot exchange their IPALCO shares for AES commonstock, or would like to find out the historical cost basis oftheir former IPALCO shareholdings should contactIndianapolis Power & Light at (317) 261-5490 or by e-mailto Myrna Graham at [email protected].

FORMER IPALCO SHAREHOLDINGS

BARKA SAOC

Registered on Muscat Securities Market (MSM); tickerAESB. To view financial filings for BARKA SAOC go towww.msm.gov.om.

CAESS and EEO

Listed on the El Salvador Stock Exchange.

AES China Generating Co. Ltd. (Chigen)

Bonds listed in Singapore.

AES GENER, Inc.

Gener shares are traded on the Bolsa de Comercio deSantiago Bolsa de Valores (Santiago Stock Exchange), theBolsa Electrónica de Chile – Bolsa de Valores (ElectronicStock Exchange), and the Bolsa de Corredores – Bolsa deValores (Valparaiso Stock Exchange), under the symbolGENER. To view Gener’s local earnings releases, go towww.aesgener.cl.

Eletropaulo Metropolitana Eletricidade de São Paulo S.A.

Registered on the BOVESPA; tickers ELPL3, ELPL4, ELPL5 and ELPL6; OTC: ELPSY and EPUMI. To view local financial filings for Eletropaulo go towww.eletropaulo.com.br/ri.

IPALCO Enterprises, Inc

To view SEC filings for IPALCO Enterprises, Inc. go to www.sec.gov, then Search for Company Filings, thenCompanies & Other Filers, then enter IPALCO Enterprisesin Company name.

Kilroot Power Ltd.

Bonds listed on the London Stock Exchange.

AES TIETÊ S.A.

Registered on the BOVESPA; tickers GETI3 and GETI4;OTC: AESAY and AESYY. To view local financial filingsfor AES TIETÊ S.A. go to http://ri.aestiete.com.br.

INFORMATION ON AES SUBSIDIARIES THAT ARE REGISTERED OR HAVE LISTED SECURITIES

The country facts, power industry statistics and macro -economic trends information presented in the 2006 AESFact Book were obtained from external sources. With theexception of largest city and sovereign credit rating infor-mation, the CIA World Factbook (http://www.cia.gov/cia/publications/factbook/), updated January 31, 2007, was thesource of data presented under the heading “country facts.”The CIA World Factbook was also used as the source ofaverage FX rate information presented under the heading“macroeconomic trends.” The Energy Information

Administration’s International Energy Annual 2004 (IEA)was the source for information presented in the PowerIndustry Snapshot and Power Industry Overview sections.The source of information on the largest city and the remaining statistics presented under the heading “macro-economic trends” was the Economist Intelligence Unit(http://www.eiu.com/), updated January 31, 2007. GDP is reflected at purchasing power parity, as opposed to the official exchange rate.

EXTERNAL SOURCES

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1 3 8 A E S 2 0 0 6 FA C T B O O K

ANCILLARY SERVICES Services that are required to run an electrical system, such as operating reserves, frequency control, voltage control, black-start capability and load following.

ANNEX I PARTIES The countries plus the European Economic Community listed in Annex I of the UNFCCC that agreed to try to limit their greenhouse gas emissions: Australia, Austria, Belarus, Belgium,Bulgaria, Canada, Croatia, Czech Republic, Denmark, European Economic Community, Estonia, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Japan, Latvia,Liechtenstein, Lithuania, Luxembourg, Monaco, The Netherlands, New Zealand, Norway,Poland, Portugal, Romania, Russian Federation, Slovakia, Slovenia, Spain, Sweden, Switzerland,Turkey, Ukraine, United Kingdom and the United States.

ASIA REPORTING AES’s Asia region consists of electric generation businesses in China, India, Jordan, Oman, REGION Pakistan, Qatar and Sri Lanka.

BASE LOAD UNIT A power station unit is a base load unit if it is designed to be on-line continuously at full capacityor near full capacity almost all of the time. Because of its operational characteristics, its largeloads cannot be quickly or easily adjusted. Such units are usually much lower in cost than peakingunits which are most likely to be gas turbines, hydro or internal combustion units.

BILATERAL CONTRACT A contract between two named parties. Physical bilateral contract, and its financial equivalent,contract for differences, are the most common forms used in the electricity sector.

BIOMASS FACILITY According to FERC, any primary energy facility using more than 50 percent biomass such as fuelwood, agricultural residues, animal waste, charcoal, and other derived fuels, is considered abiomass facility.

CAPACITY The maximum amount of electricity that a power unit is capable of delivering according to themanufacturer’s rating.

CAPACITY PAYMENT A payment made to a power plant for making generating capacity available to the system.

CAP-AND-TRADE An environmental management policy which establishes aggregate capacity of emissions and ALLOCATION PROGRAM converts it into permits to produce emissions up to that level. Initial permit allocations are then

freely traded on the market.

CERTIFIED EMISSIONS Reductions of greenhouse gases achieved by a Certified Development Mechanism (CDM) REDUCTION (CER) UNIT: project. A CER can be sold or counted toward Annex I countries’ emissions commitments.

Reductions must be additional to any that would otherwise occur.

CIRCULATING FLUIDIZED In a fluidized bed boiler, coal is burnt in a suspended bed of crushed limestone. Limestone BED (CFB) BOILER absorbs a high percentage of sulfur in the coal, and thus helps to reduce sulfur dioxide emissions.

CFB technology allows efficient burning of anthracite and bituminous coal.

CLEAN DEVELOPMENT One of the two project-based mechanisms established by the Kyoto Protocol. The CDM is MECHANISM (CDM) designed to promote sustainable development in developing countries and assist Annex I Parties

in meeting their greenhouse gas emission reduction commitments. It enables industrialized countries to invest in emission reduction projects in developing countries and to receive creditsfor reductions achieved. (See Joint Implementation Mechanism, page 140.)

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CLIMATE CHANGE Statistically significant variation in the state of the climate persisting for an extended period oftime (decades or longer), and often attributed directly or indirectly to human activity.

COGENERATION A plant that produces electricity and steam or heat that can be used for commercial, industrial, PLANT heating or cooling purposes. Cogeneration plants are known for their high thermal efficiency.

COMBINED HEAT AND Also known as cogeneration, CHP is an efficient, clean, and reliable approach to generating POWER (CHP) power and thermal energy from a single fuel source. CHP is not a specific technology, but an

application of technologies to meet an energy user’s needs.

CONCESSION A management service agreement between a government and a corporation to operate specific AGREEMENT assets. The agreement establishes the rules with which the company must comply with regard to

its operations.

DISTRIBUTION SYSTEM Includes substations, transformers, and lines with predominant voltage of 15 kilovolts that allowthe delivery of electricity to the end-users from high-voltage transmission lines.

EUROPE, CIS & AFRICA AES’s Europe & Africa region includes electricity generation and distribution businesses in REPORTING REGION Bulgaria, Cameroon, Czech Republic, Hungary, Kazakhstan, Netherlands, Nigeria, Spain, (EUROPE & AFRICA) Turkey, Ukraine, and the United Kingdom.

FEDERAL ENERGY Independent federal agency in the U.S. that regulates the interstate transmission of electricity, REGULATORY natural gas and oil. FERC also reviews proposals to build LNG terminals and interstate natural COMMISSION (FERC) gas pipelines as well as licenses hydropower projects.

FLUE GAS Equipment used to remove sulfur oxides from the combustion gases of a boiler plant before they DESULFURIZATION (FGD) are emitted into the atmosphere. Also called scrubbers.

FREE CASH FLOW Free cash flow is a non-GAAP financial measure defined as net cash from operating activities lessmaintenance capital expenditures. Maintenance capital expenditures reflect property additionsless growth capital expenditures.

GAS COMBINED An electric generating plant that uses gas to drive two types of turbines: a combustion turbine CYCLE PLANT and a steam turbine.

GREENFIELD A completely new electric power plant.

GREENHOUSE GAS (GHG) Any gas that contributes to the “greenhouse effect.”

GROSS MARGIN Revenues less costs of goods sold, including depreciation and amortization expense.

GROSS MW Total amount of electric energy produced by a generating unit.

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HEAT RATE A measure of efficiency of a power plant. It equals the British thermal units content of the fuelburned divided by the net kilowatt-hours of generated power.

INDEPENDENT POWER Wholesale electricity producers that are not affiliated with utilities in the area.PRODUCER (IPP)

INSTALLED GENERATING The total generating capacity of a power generator, turbine, transformer, transmission circuit, CAPACITY station rated by the equipment manufacturer.

INVESTMENT-GRADE Investment-grade securities are bonds with a rating of AAA to BBB. SECURITIES

JOINT IMPLEMENTATION JI mechanism and Clean Development Mechanism (CDM) are the two project-based mechanisms(JI) MECHANISM of the Kyoto protocol that may be used by Annex I Parties to fulfill their Kyoto targets. Under JI,

an Annex Party may implement an emission-reducing project in the territory of another Annex IParty and count the resulting emission reduction units towards meeting its own Kyoto target.(See Clean Development Mechanism, page 138.)

KV KILOVOLT One thousand volts.

KYOTO PROTOCOL An international agreement adopted in December 1997 in Kyoto, Japan. The Protocol sets binding emission targets for developed countries that would reduce their emissions on an average5.2 percent below 1990 levels.

LATIN AMERICA AES’s Latin America region includes electricity generation and distribution businesses in REPORTING REGION Argentina, Brazil, Chile, Colombia, Dominican Republic, El Salvador and Panama.

LIBOR Rate that the most creditworthy international banks dealing in Eurodollars charge each other forlarge loans. The LIBOR rate serves as the base for other large Eurodollar loans to less creditworthycorporate and government borrowers.

LIQUEFIED NATURAL Natural gas converted to a liquid form as a result of compression and/or cooling to a very GAS (LNG) low temperature.

MEGAWATT (MW) One million watts.

MEGAWATT-HOUR (MWH) One million watt hours.

MERCHANT GENERATOR A power plant selling electricity on a short- and mid-term basis to customers and the spot market.

METHANE (CH4) CH4 is among the six greenhouse gases to be curbed under the Kyoto Protocol. Atmospheric CH4is produced by natural processes, but there are also substantial emissions from human activitiessuch as landfills, livestock and livestock wastes, natural gas and petroleum systems, coalmines, ricefields and wastewater treatment. CH4 has a relatively short atmospheric lifetime of approximately10 years, but its 100-year GWP is currently estimated to be approximately 23 times that of CO2.Methane is also the principal constituent of natural gas.

MID-MERIT MODE Operation of a plant that falls between base load generation and peak load generation.

NET GENERATION Gross generation minus plant use from all electric utility-owned plants.

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NON-RECOURSE Non-recourse debt borrowings are not a direct obligation of AES, the parent corporation, and are DEBT BORROWINGS primarily collateralized by the capital stock of the relevant subsidiary and in certain cases the

physical assets of, and all significant agreements associated with, such business. These non-recoursefinancings include structured project financings, acquisition financings, working capital facilities,and all other consolidated debt of the subsidiaries.

NORTH AMERICA AES’s North America region includes electric generation and distribution businesses in Mexico, REPORTING REGION Puerto Rico, and the United States.

O&M Operations and maintenance.

OFF-PEAK Time when demand for power is low or below average.

ON-PEAK Time when demand for power is high or relatively high.

PEAK-LOAD GENERATION Peak-load generation is used to satisfy short periods of maximum demand. Units that operate inthis mode are typically referred to as peaking plants.

PETROLEUM COKE A solid hydrocarbon residue, high in carbon content and low in hydrogen, that is produced as aresult of oil distillation. Also called pet coke.

POWER POOL Two or more interconnected utilities that plan and operate to supply electricity in the most reliable,economical way to meet their combined load.

POWER PURCHASE Electricity sale by a power plant to a public utility or an industrial customer on a long-term basis.AGREEMENT (PPA)

PUBLIC UTILITY Promotes energy efficiency and usage of alternative energy sources by encouraging companies REGULATORY POLICIES to build cogeneration facilities and renewable energy projects using wind power, solar energy, ACT OF 1978 (PURPA) geothermal energy, hydropower, biomass, and waste fuels.

QUALIFYING FACILITY (QF) A cogenerator or small power producer which, under federal law, has the right to sell energy and capacity to the public utility at the utility’s avoided cost rate (incremental cost of which the utility would generate itself or purchase from another source). To become a QF, the independentpower plant has to produce electricity with a specified fuel type (cogeneration or renewables), and meet certain ownership, size, and efficiency criteria established by the Federal EnergyRegulatory Commission.

RECOURSE DEBT Recourse debt obligations are direct borrowings of the AES parent corporation.

RENEWABLE ENERGY Energy derived from resources that are regenerative or for all practical purposes cannot bedepleted. Types of renewable energy resources include moving water (hydro, tidal and wavepower), thermal gradients in ocean water, biomass, geothermal energy, solar energy and windenergy. Municipal solid waste (MSW) is also considered to be a renewable energy resource.

RENEWABLE FUEL Renewable fuels are naturally replenishable, but flow from limited resources such as biomass,hydro, geothermal, soil and wind.

SELECTIVE CATALYTIC An air pollution control technology that allows significant reduction of emissions of nitrogen REDUCTION (SCR) oxides in coal- or natural gas-fueled power plants.

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SIMPLE CYCLE A plant with a gas turbine that does not recover heat from the gas-turbine exhaust gases to GAS PLANT preheat the inlet combustion air to the gas turbine or which does not recover heat from the

gas-turbine exhaust gases to heat water or generate steam.

SPOT MARKET Market where buying and selling of a commodity is done for immediate or very near-term delivery.

TAKE-OR-PAY A provision in a fuel supply contract where a generation facility is required to pay a fuel supplier AGREEMENT for a certain percentage of the fuel under contract, regardless of whether the facility actually took

possession of the fuel, used it or resold it.

TOLLING AGREEMENT An agreement to put a specified amount of fuel per period through a power plant to generateelectricity.

TRANSMISSION Transportation of wholesale electricity over long distances over high voltage lines.NETWORK

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112 Alternative Energy

96 Asia and Middle East

74 Europe, CIS and Africa

46 Latin America

24 North America

37 AES Hawaii85 AES Kazakhstan72 AES Panama44 AES Puerto Rico99 Aixi50 Alicura85 Altai Group

104 Amman East67 Andres50 Argentina Generation49 Argentina Utilities

106 Barka72 Bayano43 Beaver Valley80 Bohemia82 Borsod54 Brasiliana

70 CAESS90 Cartagena50 Central Dique99 Chengdu99 Chigen72 Chiriqui62 Chivor99 Cili70 Clesa

114 Climate Change50 CTSN

45 Deepwater70 DEUSEM67 Dominican Republic

Generation

85 East Kazakhstan REC40 Eastern Energy88 Ebute49 EDELAP49 EDES

70 EEO85 Ekibastuz70 El Salvador Distribution62 Electrica Santiago55 Eletropaulo87 Elsta62 Energia Verde72 Esti

62 Gener62 Guacolda

99 Hefei33 Hemphill82 Hungary Generation

91 Ictas Energy31 IPALCO 31 IPL39 Ironwood67 Itabo

99 Jiaozuo

111 Kelanitissa95 Kievoblenergo93 Kilroot

72 La Estrella108 Lal Pir

67 Los Mina72 Los Valles

85 Maikuben West76 Maritza East I26 Merida III

62 Norgener

103 OPGC

108 Pak Gen108 Pakistan Generation

50 Parana33 Placerita

110 Ras Laffan39 Red Oak 95 Rivneenergo50 Rio Juramento & San Juan

42 Shady Point85 Shulbinsk HPP85 Sogrinsk CHP79 SONEL34 Southland56 Sul

62 TermoAndes27 Termoelectrica del Golfo

(TEG)27 Termoelectrica del Penoles

(TEP)36 Thames57 Tietê82 Tisza II82 Tiszapalkonya91 Turkey Generation

95 Ukraine Distribution58 Uruguaiana85 Ust-Kamenogorsk CHP85 Ust-Kamenogorsk Heat Nets85 Ust-Kamenogorsk HPP

38 Warrior Run115 Wind Generation

99 Wuhu

99 Yangcheng

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1 4 4 A E S 2 0 0 6 FA C T B O O K

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Cover A glass ball at a market in Chengdu, China

i Ras Laffan power plant, Qatar; Honolulu at night

1 Employees at Las Ventanas power plant, Gener, Chile; Groundbreaking ceremony for a new medical clinic funded by AES, Sri Lanka; Chain Bridge in Budapest

at night, Hungary; Market in Merida, Mexico; AES employees at Bohemia power plant, Czech Republic; Employees in the control room, Elsta power plant,

Netherlands; A girl from a Caracas barrio, which receives electricity from EDC, Venezuela; Buffalo Gap wind farm, Texas

4 Right side: Buffalo Gap wind farm in Texas, USA, at sunset

Left side: The AES Andres LNG facility, Dominican Republic

6 Rose Greenhouse, a commercial customer of AES Kievoblenergo, Ukraine; Lineman from AES Clesa distribution company, El Salvador; Children from a village

in Cameroon

7 Control room at Ras Laffan power plant, Qatar; A member of turbine rebuilding team, Las Ventanas power plant, Chile

9 Control room training at Chengdu power plant, China; Coal conveyer belt at an IPL power plant, Indiana; Members of leadership team, Kievoblenergo,

Ukraine; Barka gas-fired desalination plant, Oman; Commercial customers service center, Kievoblenergo, Ukraine; Portrait of AES employees in the water

intake tunnel, Cartagena, Spain; AES employee at a coal unloading facility, AES Hawaii, Hawaii

23 Locks symbolizing a wish, left by tourists, Yellow Mountains, Jiang Jia Jie, China; Young gaucho on pampas near Alicura power plant, Argentina; A girl

attending AES SONEL Bassa school daycare, Cameroon; Las Ventanas power plant, Chile; A traditional flower shop in Pleven, Bulgaria; A ranch adjacent to

Buffalo Gap wind farm, Texas; São Paulo at night; Plant manager inspecting a turbine during overhaul, CTSN power plant, Argentina; Sand dunes, Qatar

24 Chichen Itza Pyramid, Mexico; IPL line school, Indiana

25 Central plaza in Merida, Mexico; AES employee, Merida III power plant, Mexico; Indianapolis at night

46 Portrait of an employee of Las Ventanas power plant, Chile; El Malecon street on the waterfront, Santo Domingo, Dominican Republic

47 Promissão power plant seeding project, Tietê, Brazil; Traditional flutes, Panama

74 Olive trees, Spain; Villagers from Bafut area, Cameroon

75 Employee of a rubber factory, served by AES SONEL, Cameroon; Detail of Tisza II power plant, Hungary; Students of the Folk Music School, Bulgaria

96 A young girl on the banks of Ganges river, India; Downtown Nanjing,China, at night

97 Central market in Muscat, Oman; Team leaders of Ras Laffan power plant, Qatar

112 Egererdo forest which supplies biomass fuel for Borsod power plant, Hungary; Reforestation project at Promissão power plant, Tietê, Brazil; Buffalo Gap wind

turbine, Texas

113 AES Tietê hydro power plant replanting and seeding program, Promissão, Brazil; Wood chipper team at Tiszapalkonya plant, Hungary; AES Tietê hydro power

plant replanting and seeding program, Promissão, Brazil

117 Chinese caligraphy; AES employee on the dam of Chivor hydroelectric plant, Colombia; Young Mayan girls near Chichen Itza Pyramid, Mexico; Traditional leis

flower necklaces, Hawaii; Muscat at sunset, Oman; Youth baseball team sponsored by AES in Dominican Republic; Mangrove forest near AES Puerto coal

power plant, Puerto Rico; Employees of Bohemia power plant, Czech Republic; The King of Bafut, Cameroon; Decorated elephant at a Buddhist festival, Sri Lanka

135 Students at Jin Tang middle School, China; Traditional painted balls at a market in Yucatan, Mexico; Schoolchildren in Almaty, Kazakhstan; A villager

outside Bafut, Cameroon; A fisherman pulling his boat out of the water, Horcon, Chile; Fishing boat dock, Terneuzen, Netherlands; View of Cesky Krumlov,

Czech Republic; Stilt fishermen on the coast of Sri Lanka; Woman in a traditional Hawaiian red dress

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AES CORPORATION4300 Wilson BoulevardArlington, VA 22203USA703-522-1315

www.aes.com

Date post:	16-Jul-2015
Category:	Economy & Finance
Upload:	finance19
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AES 2006 FactBook

Economy & Finance