UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

COMMISSION FILE NUMBER 0-19281

The AES Corporation

(Exact name of registrant as specified in its charter)

Delaware

54 1163725

(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification No.)

4300 Wilson Boulevard Arlington, Virginia

22203

(Address of principal executive offices)

(Zip Code)

 

Registrant’s telephone number, including area code: (703) 522-1315

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, par value $0.01 per share

 

New York Stock Exchange

AES Trust III, $3.375 Trust Convertible

 

New York Stock Exchange

Preferred Securities

 

 

 

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

None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x   No o

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes o   No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x   No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

Large accelerated filer x      Accelerated filer o      Non-accelerated filer o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2005 (based on the closing sale price of $16.38 of the Registrant’s Common Stock, as reported by the New York Stock Exchange on such date) was approximately $10.7 billion.

The number of shares outstanding of the Registrant’s Common Stock, par value $0.01 per share, on March 3, 2006, was 657,601,448.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information from the registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held on May 11, 2006 is hereby incorporated by reference into Part III hereof.

 




THE AES CORPORATION
FISCAL YEAR 2005 FORM 10-K

TABLE OF CONTENTS TO BE UPDATED

PART I

 

ITEM 1. BUSINESS

 

5

 

Overview

 

5

 

Operating Segments

 

6

 

Facilities

 

9

 

Customers

 

15

 

Employees

 

15

 

How to Contact AES and Sources of Other Information

 

15

 

Executive Officers

 

15

 

Regulatory Matters

 

17

 

ITEM 1A. RISK FACTORS

 

41

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

54

 

ITEM 2. PROPERTIES

 

54

 

ITEM 3. LEGAL PROCEEDINGS

 

54

 

ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

 

62

 

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDERS MATTERS

 

63

 

Market Information

 

63

 

Holders

 

63

 

Dividends

 

63

 

ITEM 6. SELECTED FINANCIAL DATA

 

64

 

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

 

65

 

Restatement of Consolidated Financial Statements

 

65

 

Executive Summary and Overview

 

66

 

Critical Accounting Estimates

 

72

 

New Accounting Pronouncements

 

76

 

Results of Operations

 

78

 

Capital Resource and Liquidity

 

88

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

98

 

Overview Regarding Market Risks

 

98

 

Interest Rate Risks

 

98

 

Foreign Exchange Rate Risk

 

98

 

Commodity Price Risk

 

99

 

Value at Risk

 

99

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

101

 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

161

 

ITEM 9A. CONTROLS AND PROCEDURES

 

161

 

ITEM 9B. OTHER INFORMATION

 

170

 

 

2




 

PART III

 

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT

 

170

 

ITEM 11. EXECUTIVE COMPENSATION

 

170

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

 

170

 

Security Ownership of Certain Beneficial Owners and Management

 

170

 

Security Ownership of Directors and Executive Officers

 

170

 

Changes in Control

 

170

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

170

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

 

171

 

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

 

171

 

PART IV

 

ITEM 15. EXHIBITS FINANCIAL STATEMENT SCHEDULES

 

172

 

Financial Statements and Exhibits

 

172

 

Exhibits

 

172

 

Financial Statement Schedules

 

175

 

SIGNATURES

 

 

 

 

3




PART I

The AES Corporation, including all its subsidiaries and affiliates are collectively referred to herein as “AES” “the Company,” “us” or “we.”

RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to filing its restated annual report on Form 10-K/A with the Securities Exchange Commission on January 19, 2006, the Company discovered its previously issued restated consolidated financial statements included certain errors in accounting for derivative instruments and hedging activities, minority interest expense and income taxes. The errors in accounting for derivative instruments and hedging activities resulted in differences in previously issued consolidated interim financial statements for certain quarterly periods in 2004 sufficient to require restatement of prior period interim results. The errors in accounting for income taxes and minority interest expense required restatement of previously issued consolidated annual financial statements.

As a result of evaluating these adjustments, the Company reduced its stockholders’ equity by $12 million as of January 1, 2003 as the cumulative effect of the correction of errors for all periods proceeding January 1, 2003, and restated its consolidated statements of operations and cash flows for the years ended December 31, 2004 and 2003 and its consolidated balance sheet as of December 31, 2004.

The restatement adjustments resulted in an increase to previously reported net income of $6 million for the year ended December 31, 2004 and in a decrease to previously reported net income of $17 million for the year ended December 31, 2003. There was no impact on gross margin or net cash flow from operating activities of the Company for any years presented. Based upon management’s review it has been determined that these errors were inadvertent and unintentional. The errors relate to the following areas:

A.              Accounting for Derivative Instruments and Hedging Activities

The Company determined that it failed to perform adequate on-going effectiveness testing for three interest rate cash flow hedges and one foreign currency cash flow hedge during 2004 as required by SFAS No. 133. As a result, the Company should have discontinued hedge accounting and recognized changes in the fair value of the derivative instruments in earnings prospectively from the last valid effectiveness assessment until the earlier of either (1) the expiration of the derivative instrument or (2) the re-designation of the derivative instrument as a hedging activity.

The net impact related to the correction of these errors to previously reported net income resulted in a decrease of $4 million and an increase of $2 million for the years ending December 31, 2004 and 2003, respectively.

B.               Income Tax and Minority Interest Adjustments

As a result of the Company’s year end closing review process, the Company discovered certain other errors related to the recording of income tax liabilities and minority interest expense. The adjustments primarily include:

·       An increase in income tax expense related to the recording of certain historical withholding tax liabilities at one of our El Salvador subsidiaries;

·       An increase in minority interest expense related to a correction of the allocation of income tax expense to minority shareholders. This allocation pertained to certain deferred tax adjustments recorded in the original restatement at one of our Brazilian generating companies. In addition, minority interest expense was also corrected at this subsidiary as a result of identifying differences arising from a more comprehensive reconciliation of prior year statutory financial records to U.S. GAAP financial statements;

·       A reduction of 2004 income tax expense related to adjustments derived from 2004 income tax returns filed in 2005.

4




The net impact related to the correction of these errors to previously reported net income resulted in an increase of $10 million and a decrease of $19 million for the years ending December 31, 2004 and 2003, respectively. In addition, the Company restated stockholders’ equity as of January 1, 2003 by $12 million as a correction for these errors in all periods preceding January 1, 2003.

C.               Other Balance Sheet Reclassifications

Certain other balance sheet reclassifications were recorded at December 31, 2004 including a $45 million reclassification which reduced Accounts Receivables and increased Other Current Assets (regulatory assets).

ITEM 1.                 BUSINESS

Overview

AES, a global power company formed in 1981, is a Delaware corporation holding company that through its subsidiaries, operates a portfolio of electricity generation and distribution businesses in 25 countries on five continents.

We operate in two types of businesses within the power sector: first, we generate power for sale to utilities and other wholesale customers; second, we operate utilities that distribute power to retail, commercial, industrial and governmental customers typically through integrated transmission and distribution systems. Each type of business generates approximately one half of the Company’s revenues.

The generation and distribution of electricity are essential services required in all industrialized societies. We are committed to helping meet the world’s need for electricity by supplying power from our existing portfolio, as well as by growing our portfolio through the development and construction of new power plants and through selective acquisitions. We believe that being a large participant in the global power sector gives us the best chance to accomplish our goals. Some of the benefits of being a large organization are the ability to take advantage of scale and to have the resources to develop better operating and management practices to increase overall Company efficiency and productivity. By maintaining a substantial geographic footprint, we are well positioned to pursue opportunities in those markets with favorable characteristics for new investment, namely those having a large and growing need for power. We target specific countries or major geographic regions as areas of primary focus, and seek to build sufficient knowledge and experience in order to increase our ability to successfully compete, and ultimately grow our businesses, in those targeted markets. We believe that this approach also allows us to more efficiently identify and manage the risks inherent in our business.

In addition to our primary business of operating a global power portfolio, we also are engaged in a exploring and promoting a set of related activities that include alternative energy businesses such as wind generation, the supply of liquefied natural gas to certain targeted North American markets, the production of greenhouse gas reduction activities and related industries involving environmental issues and the application of new energy technologies. At present, these initiatives represent growth opportunities for us but currently account for a de minimus amount of revenue and earnings.

Our financial results are reported within three business segments: Contract Generation, Competitive Supply and Regulated Utilities.

Our generation business encompasses our contract generation and competitive supply segments. Performance drivers for our contract generation and competitive supply segments include plant reliability and fuel and fixed cost management. Growth is largely tied to securing new power purchase agreements and expanding capacity. The contract generation and competitive supply segments contributed 37% and 11% of revenues, respectively, for the year 2005.

5




Performance drivers for our regulated utilities segment include providing reliable service, managing working capital, obtaining tariff adjustments and appropriate regulatory treatment for new investments and, in developing countries, reduction of commercial and technical losses. The regulated utilities segment contributed 52% of revenues for the year 2005. The revenues and earnings growth of both our generation and utility businesses vary with changes in electricity demand.

Our management structure is divided into four regions: North America; Latin America; Europe, Middle East and Africa (“EMEA”); and Asia, each led by a regional president who reports directly to the Chief Executive Officer (“CEO”). This structure allows us to place senior leaders and resources closer to our businesses around the world to further improve operating performance and integrate operations and development on a more localized level. This helps us leverage regional market trends to enhance our competitiveness and identify and capitalize on key business development opportunities across our lines of business. The Company also maintains a corporate Business Development group which manages large scale transactions such as mergers and acquisitions, and portfolio management, as well as targeted strategic initiatives such as the creation of an alternative energy business.

Operating Segments

See Note 21 to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional financial information about our business segments as well as information about our geographic operations.

Contract Generation

Our contract generation businesses own and operate plants that sell electricity and related products to utilities or other wholesale customers under long-term contracts. Our contract generation facilities generally limit their exposure to commodity price risks, primarily electricity price volatility and frequently volume risk, by entering into power sales agreements of five years or longer for 75% or more of their output capacity. The remaining terms of these agreements range from 1 to 25 years. These facilities also generally enter into long-term agreements for most of their fuel supply requirements, or they may enter into tolling or “pass through” arrangements in which the counter-party directly assumes the risks associated with providing the necessary fuel and then markets the generated power. Through these types of contractual agreements, our contract generation businesses generally produce more predictable cash flows and earnings. The degree of predictability varies from business to business based on the degree to which their exposure is limited by the contracts they have negotiated with their buyers and fuel suppliers.

Our contract generation segment is comprised of our interests in 76 power generating facilities totaling approximately 23.0 gigawatts of capacity located in 17 countries. This includes minority interests in 28 power generation facilities totaling over 2.0 gigawatts of capacity. In addition, there are three plants under construction in three countries which, when completed, will add a total capacity of approximately 1.4 gigawatts to our contract generation segment. AES also operates, under either management or operations and maintenance agreements, 377 MW of wind generation facilities in the U.S. Of the 23.0 gigawatts of current operating capacity, 50% is derived from gas-fired facilities, 28% from coal-fired facilities, 13% from hydro facilities, 7% from oil-fired facilities, 2% from wind facilities, and less than 1% from biomass facilities.

In most of our contract generating businesses, a single customer contracts for most or all of a particular facility’s generated power. To reduce the resulting counter-party credit risk, we seek to contract with creditworthy customers. We also seek to obtain sovereign government guarantees of the customer’s obligations. However, we do business with many customers in many countries where neither the customer nor the government has investment grade ratings. We believe that locating our plants in different geographic areas helps to mitigate the effects of regional economic downturns, thereby offsetting some of

6




the risks associated with operating in less developed countries. Additionally, in countries in which we own distribution companies, our contract generation businesses seek to contract with the distribution companies that we control.

Certain of our subsidiaries and affiliates are in various stages of developing and constructing new power plants (known as “greenfield power plants” or “greenfield”). Some have signed long-term contracts or made similar arrangements for the sale of electricity. During 2005, the Company made significant progress on important growth projects. Among these plants under construction, the Company’s 120 MW Buffalo Gap wind power project in Texas began commercial operations in 2006. The Company’s 1,200 MW gas-fired power plant in Cartagena, Spain is scheduled for completion in 2006. The Company’s new 120 MW Los Vientos diesel-fired peaking facility which will serve the largest power market in Chile, is expected to be on-line in the second quarter of 2006. We currently believe that our costs related to these projects are recoverable but can provide no assurance that we will complete these projects and/or that these projects will reach commercial operation.

In the contract generation segment, we face most of our competition prior to the execution of a power sales agreement during the development phase of a project. Our competitors in this business include other independent power producers and equipment manufacturers, as well as various utilities and their affiliates. During the operational phase, we traditionally have faced limited competition in this segment due to the long-term nature of the generation contracts. However, since competitive power markets have been introduced and new market participants have been added, we will encounter increased competition in attracting new customers and maintaining our current customers as our existing contracts expire.

Competitive Supply

Our competitive supply businesses own and operate plants that sell electricity to wholesale customers in competitive markets. These plants typically sell into local power pools under short-term (less than one year) contracts or into daily spot markets. Demand can be affected by weather, electricity transmission constraints, fuel prices and competition. This business segment offers more varied sales, earnings and cash flows than our other segments.

In contrast to the contract generation segment discussed above, these facilities generally sell less than 75% of their output under long-term contracts. The prices at which these facilities sell electricity under short-term contracts and in the spot electricity markets are unpredictable and can be volatile. In addition, our operational results in this segment are more sensitive to the impact of market fluctuations in the price of natural gas, coal, oil and other fuels. These businesses also have more significant needs for working capital or credit to support their operations than our businesses in the contract generation segment.

Our competitive supply segment is comprised of 27 power generation facilities totaling approximately 13 gigawatts of capacity located in 7 countries. Of the total 13 gigawatts of current operating capacity, 59% is derived from coal-fired facilities, 8% from gas-fired facilities, 29% from hydro facilities, 2% from oil facilities, 1% from petroleum coke facilities and less than 1% from biomass facilities. In November 2005, we completed an output upgrade of the Alicura facility in Argentina, which resulted in an additional 10 MW of capacity.

The absence of long-term contracts makes future production volumes uncertain, which in turn makes it difficult to forecast the amount of fuel needed to support those volumes. As a result, competitive supply businesses are exposed to volume risk in connection with their purchases of natural gas, coal and other raw materials. Where appropriate, we have hedged a portion of our financial performance against the effects of fluctuations in energy commodity prices using such strategies as commodity forward contracts, futures, swaps and options.

7




Although we maintain credit policies with regard to our counterparties, there can be no assurance that ultimately they will be able to fulfill their contractual obligations. Volatility in electricity markets causes increases in credit risk, a decline in the number and quality of market participants with strong credit ratings and considerably less liquidity in energy markets.

We compete in this segment with numerous other independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers and retail energy suppliers. Competitive factors in this segment include reliability, operational cost and third party credit requirements.

Regulated Utilities

Our regulated utilities business segment consists of 14 distribution companies in seven countries with approximately 11 million customers. Our regulated utilities aggregate approximately 7.0 gigawatts of generation capacity with annual sales of over 82 gigawatt hours. All of these companies maintain a monopoly franchise within a defined service area. This segment is composed of three integrated utilities, one located in the U.S. (Indianapolis Power & Light Company, or “IPL”), one in Venezuela (EDC) and one in Cameroon (AES SONEL) and electricity distribution businesses located in Argentina (EDELAP, EDEN and EDES), Brazil (AES Eletropaulo and AES Sul), El Salvador (CAESS, CLESA, DEUSEM and EEO), and Ukraine (Kievoblenergo and Rivneenergo). These utilities sell electricity under regulated tariff agreements and each has transmission and distribution capabilities; IPL, EDC, and AES SONEL also have generation plants. Our regulated utilities are subject to extensive regulation at multiple governmental levels relating to ownership, marketing, delivery and pricing of electricity and gas, with a focus on protecting customers. Regulated utilities revenues result primarily from retail electricity sales to customers under regulated tariff or concession agreements, long term electricity sale concessions granted by the appropriate governmental authorities and, to a lesser extent, from contractual agreements of varying lengths and provisions. Our three largest regulated utilities businesses (further described below), which account for approximately 67% of the gigawatt-hours distributed by our regulated utilities, are IPALCO Enterprises, Inc., AES Eletropaulo and EDC.

IPALCO Enterprises Inc. (“IPALCO”) is a holding company and its principal subsidiary is IPL. IPL is engaged in generating, transmitting, distributing and selling electric energy to approximately 460,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL owns and operates four generation facilities. Two generating facilities are primarily coal-fired plants. The third facility has a combination of units that use coal (base load capacity) and natural gas and/or oil (peaking capacity). The fourth facility is a small peaking station that uses gas-fired combustion turbine technology. IPL’s net generation winter capability is 3,370 MW and net summer capability is 3,252 MW. We acquired IPALCO in March 2001.

AES Eletropaulo has served the São Paulo, Brazil area for over 100 years and with over five million customers, is the largest electricity distribution company in the Americas in terms of customers. AES Eletropaulo’s concession contract with the Brazilian National Electric Energy Agency (“ANEEL”), the government agency responsible for regulating the Brazilian electric industry, entitles AES Eletropaulo to distribute electricity in its service area for 30 years from the date of our acquisition in 1998. AES Eletropaulo’s service territory consists of 24 municipalities in the greater São Paulo metropolitan area and adjacent regions that account for approximately 15% of Brazil’s GDP, covering more than 5 million customers or 44% of the population in the State of São Paulo, Brazil.

EDC was founded in 1895 and is the largest private-sector electric utility in Venezuela serving approximately one million customers. EDC generates, transmits and distributes electricity to customers in metropolitan Caracas and its surrounding area. EDC’s distribution area covers 5,176 square kilometers. EDC has an installed generating capacity of 2,616 MW. EDC commenced construction of a new 200 MW

8




gas-fired generation plant. This project is expected to start-up in 2007 and will support continued demand growth at this regulated utility.

Electricity sales are made under regulated tariff agreements or under existing regulatory laws and provisions. For utilities located in developing countries, the local business environment also provides for significant opportunities to implement operating improvements that may stimulate growth in earnings and cash flow performance. These growth rates may be greater than those typically achievable in our other business segments and at utilities in more developed countries. Many of these businesses face challenges unique to developing countries including outdated equipment, significant electricity theft-related losses, cultural problems associated with customer safety and non-payment, emerging economies and potentially less stable governments or regulatory regimes.

The regulated utilities face relatively little direct competition due to significant barriers to entry which are present in these markets. In this segment, we primarily face competition in our efforts to acquire businesses. We compete against a number of other participants, some of which have greater financial resources, have been engaged in distribution related businesses for periods longer than we have, and have accumulated more significant portfolios. Relevant competitive factors include financial resources, governmental assistance, and access to non-recourse financing and regulatory restrictions. In certain locations, utilities face increased competition as a result of changes in laws and regulations which allow wholesale and retail services to be provided on a competitive basis. We can provide no assurance that deregulation will not adversely affect our regulated utilities’ future operations, cash flows and financial condition. The results of operations of our utilities business are sensitive to changes in economic growth and regulation (especially in emerging markets), abnormal weather conditions affecting each local market, as well as the success of the operational changes that have been implemented.

Facilities

The following tables present information with respect to the facilities in each of our three business segments. The amounts under “Gross MW” and “Approximate Gigawatt Hours” represent the gross amounts for each facility without regard to our percentage of ownership interest in the facility.

9




Contract Generation
(As of December 31, 2005)

Generation Facilities

 

 

 

Geographic
Location

 

Dominant Fuel

 

Year of
Acquisition or
Commencement
of Commercial
Operations

 

Gross MW

 

AES Equity
Interest
(Percent
Rounded)

 

North America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Altamont

 

USA

 

Wind

 

 

2005

 

 

 

24

 

 

 

100

 

 

Altech III

 

USA

 

Wind

 

 

2005

 

 

 

25

 

 

 

100

 

 

Beaver Valley

 

USA

 

Coal

 

 

1985

 

 

 

125

 

 

 

100

 

 

Central Valley—Delano

 

USA

 

Biomass

 

 

2001

 

 

 

57

 

 

 

100

 

 

Central Valley—Mendota

 

USA

 

Biomass

 

 

2001

 

 

 

25

 

 

 

100

 

 

Condon

 

USA

 

Wind

 

 

2005

 

 

 

25

 

 

 

38

 

 

Hawaii

 

USA

 

Coal

 

 

1992

 

 

 

203

 

 

 

100

 

 

Hemphill

 

USA

 

Biomass

 

 

2001

 

 

 

16

 

 

 

67

 

 

Ironwood

 

USA

 

Gas

 

 

2001

 

 

 

710

 

 

 

100

 

 

Kingston(1)

 

Canada

 

Gas

 

 

1997

 

 

 

110

 

 

 

50

 

 

Mérida III

 

Mexico

 

Gas

 

 

2000

 

 

 

484

 

 

 

55

 

 

Placerita

 

USA

 

Gas

 

 

1989

 

 

 

115

 

 

 

100

 

 

Puerto Rico

 

USA

 

Coal

 

 

2002

 

 

 

454

 

 

 

100

 

 

Red Oak

 

USA

 

Gas

 

 

2002

 

 

 

832

 

 

 

100

 

 

Shady Point

 

USA

 

Coal

 

 

1991

 

 

 

320

 

 

 

100

 

 

Southland—Alamitos

 

USA

 

Gas

 

 

1998

 

 

 

2,047

 

 

 

100

 

 

Southland—Huntington Beach

 

USA

 

Gas

 

 

1998

 

 

 

904

 

 

 

100

 

 

Southland—Redondo Beach

 

USA

 

Gas

 

 

1998

 

 

 

1,376

 

 

 

100

 

 

Thames

 

USA

 

Coal

 

 

1990

 

 

 

208

 

 

 

100

 

 

Warrior Run

 

USA

 

Coal

 

 

2000

 

 

 

205

 

 

 

100

 

 

Wind facilities operated under management or operations and maintenance agreements

 

USA

 

Wind

 

 

2005

 

 

 

377

 

 

 

0

 

 

Latin America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Andres

 

Dom. Republic

 

Gas

 

 

2003

 

 

 

319

 

 

 

100

 

 

Gener—Centrogener (7 plants)(2)

 

Chile

 

Hydro/Coal/Oil

 

 

2000

 

 

 

682

 

 

 

99

 

 

Gener—Electrica de Santiago (2 plants)(3)

 

Chile

 

Gas/Diesel

 

 

2000

 

 

 

479

 

 

 

89

 

 

Gener—Energía Verde (3 plants)(4) 

 

Chile

 

Biomass/Diesel

 

 

2000

 

 

 

42

 

 

 

99

 

 

Gener—Guacolda

 

Chile

 

Coal

 

 

2000

 

 

 

304

 

 

 

49

 

 

Gener—Norgener

 

Chile

 

Coal/Pet Coke

 

 

2000

 

 

 

277

 

 

 

99

 

 

Gener—TermoAndes

 

Argentina

 

Gas

 

 

2000

 

 

 

643

 

 

 

99

 

 

Itabo (5 plants)(5)

 

Dom. Republic

 

Coal/Oil

 

 

2000

 

 

 

586

 

 

 

25

 

 

Los Mina

 

Dom. Republic

 

Gas

 

 

2000

 

 

 

236

 

 

 

100

 

 

Tietê (10 plants)(6)(7)

 

Brazil

 

Hydro

 

 

1999

 

 

 

2,650

 

 

 

24

 

 

Uruguaiana(7)

 

Brazil

 

Gas

 

 

2000

 

 

 

639

 

 

 

46

 

 

 

10




Contract Generation—continued
(As of December 31, 2005)

Generation Facilities

 

 

 

Geographic
Location

 

Dominant Fuel

 

Year of
Acquisition or
Commencement
of Commercial
Operations

 

Gross MW

 

AES Equity
Interest
(Percent
Rounded)

 

Europe/Middle East/Africa

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barka

 

Oman

 

Gas

 

 

2003

 

 

 

456

 

 

 

35

 

 

Bohemia

 

Czech. Rep.

 

Coal/Biomass

 

 

2001

 

 

 

50

 

 

 

100

 

 

Borsod

 

Hungary

 

Biomass/Coal/Gas

 

 

1996

 

 

 

96

 

 

 

100

 

 

Ebute

 

Nigeria

 

Gas

 

 

2001

 

 

 

305

 

 

 

95

 

 

Elsta

 

Netherlands

 

Gas

 

 

1998

 

 

 

630

 

 

 

50

 

 

Kilroot

 

N. Ireland, U.K.

 

Coal/Oil

 

 

1992

 

 

 

520

 

 

 

97

 

 

Lal Pir

 

Pakistan

 

Oil

 

 

1997

 

 

 

362

 

 

 

55

 

 

Pak Gen

 

Pakistan

 

Oil

 

 

1998

 

 

 

365

 

 

 

55

 

 

Ras Laffan

 

Qatar

 

Gas

 

 

2004

 

 

 

756

 

 

 

55

 

 

Tisza II

 

Hungary

 

Oil/Gas

 

 

1996

 

 

 

900

 

 

 

100

 

 

Asia

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Aixi

 

China

 

Coal

 

 

1998

 

 

 

51

 

 

 

71

 

 

Chengdu

 

China

 

Gas

 

 

1997

 

 

 

50

 

 

 

35

 

 

Cili

 

China

 

Hydro

 

 

1994

 

 

 

26

 

 

 

51

 

 

Hefei

 

China

 

Oil

 

 

1997

 

 

 

115

 

 

 

70

 

 

Jiaozuo

 

China

 

Coal

 

 

1997

 

 

 

250

 

 

 

70

 

 

Kelanitissa

 

Sri Lanka

 

Diesel

 

 

2003

 

 

 

168

 

 

 

90

 

 

OPGC

 

India

 

Coal

 

 

1998

 

 

 

420

 

 

 

49

 

 

Wuhu

 

China

 

Coal

 

 

1996

 

 

 

250

 

 

 

25

 

 

Yangcheng

 

China

 

Coal

 

 

2001

 

 

 

2,100

 

 

 

25

 

 

 

 

 

 

 

 

 

Total

 

 

 

23,369

 

 

 

 

 

 

 

Under Construction

Generation Facilities

 

 

 

Geographic
Location

 

Dominant Fuel

 

Commencement
of Commercial
Operations

 

Gross MW

 

AES Equity
Interest
(Percent
Rounded)

 

North America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Buffalo Gap

 

 

USA

 

 

 

Wind

 

 

 

2006

 

 

 

121

 

 

 

100

 

 

Latin America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Los Vientos

 

 

Chile

 

 

 

Diesel

 

 

 

2006

 

 

 

120

 

 

 

99

 

 

Europe/Middle East/Africa

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cartagena

 

 

Spain

 

 

 

Gas

 

 

 

2006

 

 

 

1,200

 

 

 

71

 

 


(1)          As of March 2006, AES sold its direct interest in Kingston Cogeneration Limited Partnership, a 110 MW cogeneration power plant.

(2)          Gener-Centrogener plants: Ventanas, Laguna Verde, Laguna Verde Turbogas, Alfalfal, Maitenas, Queltehues and Volcán.

(3)          Gener-Eletrica de Santiago plants: Nueva Renca and Renca.

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

(5)          Itabo plants: Itabo, Santo Domingo, Timbeque, Los Mina and Higuamo.

(6)          Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mogi-Guaçu, Nova Avanhandava and Promissão.

(7)          As a result of the restructuring between some of our Brazilian holding companies and BNDES which was completed in January 2004, we have a 46% ownership interest in AES Uruguaiana and a 24% interest in AES Tietê. AES retains control of these entities through  the holding company, Brasiliana Energia, S.A.

11




Competitive Supply
(As of December 31, 2005)

Generation Facilities

 

 

 

Geographic
Location

 

Dominant Fuel

 

Year of
Acquisition or
Commencement
of Commercial
Operations

 

Gross MW

 

AES Equity
Interest
(Percent
Rounded)

 

North America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cayuga

 

USA

 

Coal

 

 

1999

 

 

 

306

 

 

 

100

 

 

Deepwater

 

USA

 

Pet Coke

 

 

1986

 

 

 

160

 

 

 

100

 

 

Greenidge

 

USA

 

Coal

 

 

1999

 

 

 

161

 

 

 

100

 

 

Somerset

 

USA

 

Coal

 

 

1999

 

 

 

675

 

 

 

100

 

 

Westover

 

USA

 

Coal

 

 

1999

 

 

 

126

 

 

 

100

 

 

Latin America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Alicura

 

Argentina

 

Hydro

 

 

2000

 

 

 

1,040

 

 

 

96

 

 

Central Dique

 

Argentina

 

Gas/Diesel

 

 

1998

 

 

 

68

 

 

 

51

 

 

Paraná-GT

 

Argentina

 

Gas

 

 

2001

 

 

 

845

 

 

 

100

 

 

Quebrada de Ullum(1)

 

Argentina

 

Hydro

 

 

2004

 

 

 

45

 

 

 

0

 

 

Rio Juramento—Cabra Corral

 

Argentina

 

Hydro

 

 

1995

 

 

 

102

 

 

 

98

 

 

Rio Juramento—El Tunal

 

Argentina

 

Hydro

 

 

1995

 

 

 

10

 

 

 

98

 

 

San Juan—Sarmiento

 

Argentina

 

Gas

 

 

1996

 

 

 

33

 

 

 

98

 

 

San Juan—Ullum

 

Argentina

 

Hydro

 

 

1996

 

 

 

45

 

 

 

98

 

 

San Nicolás

 

Argentina

 

Coal/Gas/Oil

 

 

1993

 

 

 

650

 

 

 

96

 

 

Bayano

 

Panama

 

Hydro

 

 

1999

 

 

 

260

 

 

 

49

 

 

Chiriqui—Esti

 

Panama

 

Hydro

 

 

2003

 

 

 

120

 

 

 

49

 

 

Chiriqui—La Estrella

 

Panama

 

Hydro

 

 

1999

 

 

 

42

 

 

 

49

 

 

Chiriqui—Los Valles

 

Panama

 

Hydro

 

 

1999

 

 

 

48

 

 

 

49

 

 

Chivor

 

Colombia

 

Hydro

 

 

2000

 

 

 

1,000

 

 

 

99

 

 

Panama

 

Panama

 

Oil

 

 

1999

 

 

 

42

 

 

 

49

 

 

Europe/Middle East/Africa

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Indian Queens

 

England, U.K.

 

Oil

 

 

1996

 

 

 

140

 

 

 

100

 

 

Tiszapalkonya

 

Hungary

 

Biomass/Coal

 

 

1996

 

 

 

116

 

 

 

100

 

 

Asia

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ekibastuz(2)

 

Kazakhstan

 

Coal

 

 

1996

 

 

 

4,000

 

 

 

100

 

 

Shulbinsk(3)

 

Kazakhstan

 

Hydro

 

 

1997

 

 

 

702

 

 

 

0

 

 

Sogrinsk CHP

 

Kazakhstan

 

Coal

 

 

1997

 

 

 

301

 

 

 

100

 

 

Ust-Kamenogorsk(3)

 

Kazakhstan

 

Hydro

 

 

1997

 

 

 

331

 

 

 

0

 

 

Ust-Kamenogorsk CHP

 

Kazakhstan

 

Coal

 

 

1997

 

 

 

1,354

 

 

 

100

 

 

Ust-Kamenogorsk Heat Nets(1)

 

Kazakhstan

 

Coal

 

 

1998

 

 

 

270

 

 

 

0

 

 

 

 

 

 

 

 

 

Total

 

 

 

12,992

 

 

 

 

 

 


(1)          Although our equity interest in these businesses is zero, we operate these businesses through a management agreement.

(2)          AES fully owns and operates Maikuben West coal mine in Kazakhstan, which supplies coal to this facility.

(3)          Although our equity interest in these businesses is zero, we operate these businesses through a concession agreement.

12




Regulated Utilities
(As of December 31, 2005)

Generation Facilities

 

 

 

Geographic
Location

 

Dominant Fuel

 

Year of
Acquisition or
Commencement
of Commercial
Operations

 

Gross MW

 

AES Equity
Interest
(Percent
Rounded)

 

North America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPL (4 plants)(1)

 

USA

 

Coal/Gas/Oil

 

 

2001

 

 

 

3,370

 

 

 

100

 

 

Latin America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EDC (5 plants)(2)

 

Venezuela

 

Oil/Gas

 

 

2000

 

 

 

2,616

 

 

 

86

 

 

Europe/Africa/Middle East

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SONEL (12 plants)(3)

 

Cameroon

 

Hydro/Diesel/

 

 

2001

 

 

 

1,014

 

 

 

56

 

 

 

 

 

 

Heavy Fuel Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7,000

 

 

 

 

 

 


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

(2)          EDC plants: Amplicacion Tacoa, Tacoa, Arrecifes, Oscar Augusto Machado and Genevapca.

(3)          SONEL plants: Edéa, Song Loulou, Limbé, Bassa, Bafoussam, Logbaba, Logbaba II, Oyomabang I Oyomabang II, Mefou, Lagdo and Djamboutou.

Under Construction

Generation Facilities

 

 

 

Geographic
Location

 

Dominant Fuel

 

Commencement
of Commercial
Operations

 

Gross MW

 

AES Equity
Interest
(Percent,
Rounded)

 

Latin America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EDC (La Raisa plant)

 

Venezuela

 

 

Gas

 

 

 

2007

 

 

 

200

 

 

 

86

 

 

 

Distribution Facilities

 

 

 

Geographic
Location

 

Approx. Number
of Customers
Served

 

Year of
Acquisition or
Commencement
of Commercial
Operations

 

Approx.
Gigawatt
Hours

 

AES Equity
Interest
(Percent,
Rounded)

 

North America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPL

 

USA

 

 

460,000

 

 

 

2001

 

 

 

16,278

 

 

 

100

 

 

Latin America

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAESS

 

El Salvador

 

 

487,000

 

 

 

2000

 

 

 

1,980

 

 

 

75

 

 

CLESA

 

El Salvador

 

 

272,000

 

 

 

1998

 

 

 

726

 

 

 

64

 

 

DEUSEM

 

El Salvador

 

 

53,000

 

 

 

2000

 

 

 

95

 

 

 

74

 

 

EDE Este(1)

 

Dom. Republic

 

 

331,000

 

 

 

2004

 

 

 

2,136

 

 

 

0

 

 

EDC

 

Venezuela

 

 

1,030,000

 

 

 

2000

 

 

 

10,523

 

 

 

86

 

 

Edelap

 

Argentina

 

 

296,000

 

 

 

1998

 

 

 

2,363

 

 

 

90

 

 

Eden

 

Argentina

 

 

300,000

 

 

 

1997

 

 

 

2,107

 

 

 

90

 

 

Edes

 

Argentina

 

 

154,000

 

 

 

1997

 

 

 

721

 

 

 

90

 

 

EEO

 

El Salvador

 

 

200,000

 

 

 

2000

 

 

 

408

 

 

 

89

 

 

Eletropaulo(2)

 

Brazil

 

 

5,298,000

 

 

 

1998

 

 

 

31,634

 

 

 

34

 

 

Sul(3)

 

Brazil

 

 

1,046,000

 

 

 

1997

 

 

 

6,922

 

 

 

100

 

 

 

13




Regulated Utilities—continued
(As of December 31, 2005)

Distribution Facilities

 

 

 

Geographic
Location

 

Approx.
Number of
Customers
Served

 

Year of
Acquisition or
Commencement
of Commercial
Operations

 

Approx.
Gigawatt
Hours

 

AES Equity
Interest
(Percent,
Rounded)

 

Europe/Middle East/Africa

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Kievoblenergo

 

Ukraine

 

 

800,000

 

 

 

2001

 

 

 

3,332

 

 

 

89

 

 

Rivneenergo

 

Ukraine

 

 

388,000

 

 

 

2001

 

 

 

1,895

 

 

 

80

 

 

SONEL

 

Cameroon

 

 

528,000

 

 

 

2001

 

 

 

3,258

 

 

 

56

 

 

Asia

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Eastern Kazakhstan REC(1)

 

Kazakhstan

 

 

282,000

 

 

 

1999

 

 

 

1,998

 

 

 

0

 

 

Semipalatinsk REC(1)

 

Kazakhstan

 

 

180,000

 

 

 

1999

 

 

 

834

 

 

 

0

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

87,210

 

 

 

 

 

 


(1)          Although our equity interest in these businesses is zero, we operate these businesses through a management agreement. AES previously had a controlling interest in EDE Este from 1999 to 2004.

(2)          As a result of the restructuring between some of our Brazilian holding companies and BNDES which was completed in January 2004, our ownership interest in Eletropaulo is 34%. AES retains control through the holding company, Brasiliana Energia, S.A.

(3)          As a result of the restructuring of certain of our Brazilian holding companies and BNDES that was completed in January 2004, AES Sul may be contributed at the option of BNDES to Brasiliana Energia, S.A. after AES Sul has completed its own debt restructuring.

Growth Opportunities

We continuously consider options to expand our business. In addition to expanding our two primary lines of business, power generation and distribution, we believe we can leverage the skills and experience necessary to be successful in our primary businesses into other businesses that have similar characteristics. We believe these transferable skills include our knowledge and skill in dealing with complex deal structuring and project financing for large capital intensive projects and dynamic local political and regulatory environments. We believe we have an additional advantage in situations where we can leverage our existing businesses. Our existing presence in certain countries can provide the relationships and insight into local rules, regulations, politics and business practices needed to be successful in both power and related non-power sectors. In addition, we seek to expand our businesses into other forms of energy production and delivery. This includes alternative energy businesses such as wind generation, the supply of liquefied natural gas (“LNG”) to certain targeted North American markets, the production of greenhouse gas reduction activities, and new energy technology. For example, we have already begun to implement this strategy in Kazakhstan, where we own and operate a coal mine, the Middle East, where we own and operate water desalination plants, and the Dominican Republic, where we own and operate an LNG regasification terminal, each ancillary to our existing power businesses.

The Company continues to maintain an active development pipeline of potential growth investments. It continues to devote significant resources at both the corporate and business level in support of business development opportunities, which may include expansion at existing locations, new greenfield investments, privatization of government assets, and mergers and acquisitions. It is this funding of development costs in support of new projects and privatization opportunities which could lead to significant new investments in 2006.

14




Customers

We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2005 total revenues.

Employees

As of December 31, 2005, we employed approximately 30,000 people.

How to Contact AES and Sources of Other Information

Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is (703) 522-1315. Our web address is http://www.aes.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 are posted on our website at http://www.aes.com. After the reports are filed with the Securities and Exchange Commission, they are available from the Company free of charge. Material contained on our website is not part of and is not incorporated by reference in this annual report on Form 10-K.

AES’s Code of Business Conduct and Ethics (“Code of Conduct”) and Corporate Governance Guidelines have been adopted by the Board of Directors. The Code of Conduct is intended to govern as a requirement of employment the actions of everyone who works at AES, including employees of AES subsidiaries and affiliates. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on the Company’s web site (www.aes.com). Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203.

Executive Officers of the Registrant

The following individuals listed below are AES’s executive officers:

Paul Hanrahan, 48 years old, is the President and Chief Executive Officer of the Company. Prior to assuming his current position, Mr. Hanrahan was the Chief Operating Officer and Executive Vice President of the Company. In this role, he was responsible for business development activities and the operation of multiple electric utilities and generation facilities in Europe, Asia and Latin America. Mr. Hanrahan was previously the President and CEO of the AES China Generating Company, Ltd., a public company formerly listed on NASDAQ. Mr. Hanrahan also has managed other AES businesses in the United States, Europe and Asia. Prior to joining AES, Mr. Hanrahan served as a line officer on the U.S. fast attack nuclear submarine, USS Parche (SSN-683). Mr. Hanrahan is a graduate of Harvard Business School and the U.S. Naval Academy.

David S. Gee, 51 years old, is an Executive Vice President and the Regional President of North America. Prior to joining the Company in 2004, Mr. Gee was Vice President of Strategic Planning for PG&E in San Francisco, California. Mr. Gee was a principal consultant for McKinsey & Co. from 1985 to 2000 in Houston, Mexico City and London. He was also an Associate for Baker Hughes and Booz Allen & Hamilton in Houston, Texas. Mr. Gee has a Bachelor of Science degree in Chemical Engineering from the University of Virginia and a Master of Science degree in Finance from the Sloan School of Management at the Massachusetts Institute of Technology.

Andres R. Gluski, 48 years old, is an Executive Vice President and the Regional President of Latin America. Mr. Gluski was Senior Vice President for the Caribbean and Central America from 2003 to 2005, was Group Manager and CEO of Electricidad de Caracas (“EDC”) (Venezuela) from 2002 to 2003, served as CEO of Gener (Chile) in 2001 and was Executive Vice President of EDC and Corporacion EDC. Prior to joining the Company in 1997, Mr. Gluski was Executive Vice President of Corporate Banking for Banco

15




de Venezuela and Executive Vice President of Finance of CANTV in Venezuela. Mr. Gluski is a graduate of Wake Forest University and holds a Master of Arts and a Doctorate in Economics from the University of Virginia.

Victoria D. Harker, 41 years old, is an Executive Vice President and the Chief Financial Officer of the Company. Ms. Harker joined the Company as Chief Financial Officer on January 23, 2006. Prior to joining the Company, Ms. Harker held the positions of Acting Chief Financial Officer, Senior Vice President and Treasurer of MCI from November 2002 through January 2006. Prior to that, Ms. Harker served as Chief Financial Officer of MCI Group, a unit of WorldCom Inc., from 1998 to 2002. Prior to 1998, Ms. Harker held several positions at MCI in the areas of finance, information technology and operations. Ms. Harker received her Bachelor of Arts degree in English and Economics from the University of Virginia and a Master’s in Business Administration, Finance from American University.

Robert F. Hemphill, Jr., 62 years old, is an Executive Vice President and has been Executive Vice President since rejoining the Company on February 5, 2004. Mr. Hemphill served as a Director of the Company from June 1996 to February 2004 and was an Executive Vice President from 1982 to June 1996. Prior to this, Mr. Hemphill held various leadership positions since joining the Company in 1982. Mr. Hemphill also serves on the Boards of Reactive Nanotechnologies, Inc. and Trophogen Inc. Mr. Hemphill received a Bachelor of Arts degree in Political Science from Yale University, a Master of Arts in Political Science from the University of California, Los Angeles, and a Master’s in Business Administration, Finance from George Washington University.

Haresh R. Jaisinghani, 39 years old, is an Executive Vice President and the Regional President of Asia and Middle East. Prior to assuming his current position, Mr. Jaisinghani was Vice President of Generation Asia from 2003 to 2005 and was Group Manager of Asia from 2001 to 2003. Mr. Jaisinghani also served as Managing Director and Country Head of Bangladesh from 1997 through 1999. Prior to joining the Company in 1994, Mr. Jaisinghani was Project Director for GM Bijlani Construction Company. Mr. Jaisinghani holds a Bachelor in Civil Engineering from the University of Bombay, India and a Master of Science in Construction Management from the University of Maryland.

Jay L. Kloosterboer, 45 years old, is the Executive Vice President of Business Excellence. Mr. Kloosterboer joined the Company in 2003 as Vice President and Chief Human Resource Officer. Prior to joining the Company, he was Vice President, Human Resources and Communications for Honeywell International’s Automation and Control Solutions business. Mr. Kloosterboer also held management positions at General Electric and Morgan Stanley. He received his Bachelor of Arts degree from Marquette University and holds a Master of Arts degree from the New Mexico State University.

William R. Luraschi, 42 years old, is the Executive Vice President, Business Development and Strategy. Mr. Luraschi joined AES in 1993 and has been an Executive Vice President since July 2003. He was General Counsel of the Company from January 1994 until May 2005. Mr. Luraschi also served as Corporate Secretary from February 1996 until June 2002. Prior to joining the Company, he was an attorney with the law firm of Chadbourne & Parke, LLP. Mr. Luraschi received a Bachelor of Science from the University of Connecticut and holds a Juris Doctorate from Rutgers School of Law.

Brian A. Miller, 40 years old, is an Executive Vice President, General Counsel and Corporate Secretary of the Company. Mr. Miller joined the Company in 2001 and has served as Vice President, Deputy General Counsel, Corporate Secretary, General Counsel for North America and Assistant General Counsel. Prior to joining the Company, he was an attorney with the law firm Chadbourne & Parke, LLP. Mr. Miller received his bachelor’s degree in History and Economics from Boston College and holds a Juris Doctorate from the University of Connecticut School of Law.

16




Shahzad Qasim, 51 years old, is an Executive Vice President and the Regional President of Europe and Africa. Mr. Qasim served as Senior Vice President of Generation Middle East from 2001 to 2005, Vice President of the Middle East and South Asia from 1998 to 2000, Project Director of Pakistan and Central Asia from 1993 to 1998 and Director of New Ventures from 1992 to 1993. Prior to joining the Company, he was an engagement manager for McKinsey & Co. Mr. Qasim has a Bachelor of Science in Mechanical Engineering from NED Engineering University, Pakistan and a Masters in Energy Management and Policy from the University of Pennsylvania.

Regulatory Matters

United States.   Over the past decade, a series of regulatory policies have been adopted in the United States that encourage competition in wholesale and retail electricity markets. These policies have been implemented both at the federal level and, in many states, at the state level. The federal government regulates wholesale power markets and transmission facilities in most of the continental U.S., while each of the fifty states regulates retail electricity markets and distribution.

The Federal Energy Regulatory Commission (“FERC”) has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy under the Federal Power Act (“FPA”) and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act. In 1996, the FERC issued Order # 888, which mandated the functional separation of generation and transmission operations and required utilities to provide open access to their transmission systems. Each utility under the FERC’s jurisdiction was required to file an Open Access Transmission Tariff. In 2000, the FERC issued Order # 2000, which established the functions and characteristics of Regional Transmission Organizations (“RTOs”) as a means to ensure independent administration of the open access policy and to help increase investment in transmission infrastructure. The RTO assumed functions traditionally handled by utilities, such as security, coordination and planning.

Beginning in the fall of 2001, regulatory officials in the United States began to re-examine the nature and pace of deregulation of electricity markets. This re-examination was primarily a result of extreme price volatility and energy shortages in California and portions of the western markets during the period from May 2000 through June 2001. The conclusions reached in this re-examination have not been uniform, but rather have differed from state to state and between the federal government and the states themselves. Thus, a number of states have advocated against restructuring and abandoned any efforts to proceed with deregulation of retail markets, while the FERC has continued its efforts to enhance “open access” electric transmission and enhance competition in bulk power (wholesale) markets, albeit at a somewhat slower pace. This has led to a number of confrontations and legal proceedings between the FERC and the states over jurisdiction. We believe that over the next decade the United States will continue to resemble a “patchwork quilt” of differing regulatory policies at the retail level.

The federal government, through regulations promulgated by the FERC, has primary jurisdiction over wholesale electricity markets and transmission services. Since 1986, the FERC has approved market based rate authority for many providers of wholesale generation, and the mix of market players has shifted toward non-utility entities, referred to as Independent Power Producers (“IPPs”) or Electric Wholesale Generators (“EWGs”), whose rates are negotiated rather than based on costs. The FERC has issued a number of orders that increase the reporting requirements of entities requesting market based rates. The FERC is in the process of issuing a rulemaking concerning the four criteria examined in granting market based rate authority and the resulting regulations may result in a more stringent analysis and therefore the denial of market based rate authority to a number of entities. Recently there has also been a shift back to utilities supplying their own generation, through affiliate contracts, acquisition of distressed assets, and traditional utility construction. These assets are included in ratebase and represent a move back to traditional cost of service ratemaking regulation.

17




On August 8, 2005 the President signed into law the Energy Policy Act of 2005 (“EPAct 2005”). The legislation repealed the Public Utility Holding Company Act (“PUHCA of 1935”) and replaced it with the Public Utility Holding Company Act of 2005 (“PUHCA of 2005”), which became effective on February 8, 2006. The repeal of the PUHCA of 1935 removed utility holding companies from the jurisdiction of the SEC and greatly reduced the financial and governance restrictions imposed on utility holding companies. The PUHCA of 2005 increases federal and state access to books and records, but does not restrict mergers and acquisitions of non-contiguous utilities as did the previous law.

Under Section 203 of the FPA, as amended by EPAct 2005, the FERC has increased authority to review mergers and acquisitions, including acquisitions of foreign utility companies. However, the FERC has issued regulations that give a holding company that owns a transmitting utility or an electric utility company and has captive U.S. customers (such as AES) blanket authority to acquire a foreign utility company upon making a notice filing containing specific certifications with respect to the protection of such customers from the effects of the acquisition.

EPAct 2005 also provides the FERC with new authority to certify an Electric Reliability Organization (“ERO”) that will set mandatory reliability standards for the U.S. grid. The North American Electric Reliability Council (“NERC”) will most likely fill this role and have enforcement authority. NERC recently adopted a set of reliability standards that consist of existing operating and planning standards. Although NERC has not historically had authority to mandate compliance with these standards, utilities generally choose to voluntarily comply with the standards. The new legislation gives NERC the ability to make standards mandatory and would grant them the authority to enforce these standards through the issuance of financial penalties.

Finally, EPAct 2005 amends the Public Utility Regulatory Policies Act of 1978 (“PURPA”) and instructs the FERC to promulgate regulations to implement the amendments. Pursuant to this directive, the FERC has issued a final rule that: (i) prescribes new restrictive criteria that new cogeneration facilities must meet in order to be designated as qualifying facilities (“QFs”) under PURPA; (ii) removes the restrictions on ownership of QFs by an entity that is primarily engaged in the generation or sale of electric power; and (iii) for new QFs eliminates certain regulatory exemptions that QFs previously received. The FERC has also issued a proposed rule that for new power sales contracts would effectively remove the requirement that utilities purchase energy and capacity produced by QFs if the utilities (i) are located within the control areas of the Midwest Independent Transmission System Operator, Inc. (“Midwest ISO”), PJM Interconnection, L.L.C., ISO New England, Inc. or the New York Independent System Operators or (ii) otherwise meet certain criteria relating to market access for QFs. We are evaluating the impact of these rules on our businesses.

There are currently major changes pending in the structure and rules governing the California wholesale energy market. The outcome of any significant market or regulatory changes will affect market conditions for all market participants, including AES. As a result of price volatility during 2000 and 2001, a number of parties, including the State of California and the California Independent System Operator, are seeking refunds from certain entities that supplied power within the state during 2000 and 2001, although our overall exposure to this risk is largely mitigated as a result of our tolling agreement related to the Southland plants. However, a recent Ninth Circuit Court of Appeals Opinion found that the FERC had abused its administrative discretion by declining to order refunds for violations of its reporting requirements and remanded the issue to the FERC. Appeal of that order is currently pending. Separate appeals in the Ninth Circuit Court of Appeals are also pending which could change the timing of the refund period. AES Placerita made sales to the California Power Exchange during this period. Depending on the result of the pending appeals and the time period at issue, as well as the method of calculating refunds, AES Placerita’s exposure could be $23 million. There are no performance bonds or corporate guarantees supporting AES Placerita and no liability has been established in the refund proceedings for

18




other AES entities. In addition, we have been named in a number of lawsuits covering this period and are not certain of their outcome. See Item 3—Legal Proceedings in this Form 10-K.

In addition to the FERC regulation described above, IPL is subject to regulation by the Indiana Utility Regulatory Commission (“IURC”) as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of public utility properties or securities and certain other matters.

IPL’s tariff rates for electric service to retail customers (basic rates and charges) are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve IPL, the staff of the IURC, the Indiana Office of Utility Consumer Counselor, and other interested consumer groups and customers. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all utilities at least once every four years.

The majority of IPL customers are served pursuant to retail tariffs that provide for the monthly billing 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 to certain restrictions on the level of operating income. In addition, IPL’s rate authority provides for a return on IPL’s investment and recovery of the depreciation and operation and maintenance expenses associated with the nitrogen oxide (“NOx”) compliance construction program and its multipollutant plan.

On April 1, 2005, IPL began participation in the restructured wholesale energy market operated by the Midwest ISO. The implementation of this restructured market marks a significant change in the way IPL buys and sells electricity and schedules generation. Prior to the restructured market, IPL dispatched its generation and purchased power resources directly to meet its demands. In the restructured market, IPL offers its generation and bids its demand into the market on an hourly basis. The Midwest ISO settles these hourly offers and bids based on locational marginal prices or LMPs, i.e., pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the Midwest ISO region. The Midwest ISO evaluates the market participants’ energy injections into, and withdrawals from, the system to economically dispatch the entire Midwest ISO system on a five-minute basis. Market participants are able to hedge their exposure to congestion charges, which result from constraints on the transmission system, with certain Financial Transmission Rights, or “FTRs”. Participants are allocated FTRs each year and are permitted to purchase additional FTRs. As anticipated and in keeping with similar market start-ups around the world, LMPs are volatile and there are process, data, and model issues requiring editing and enhancement. IPL and other market participants have raised concerns with certain Midwest ISO transactions and the resolution of these items could impact our results of operations.

Argentina.   In January and February 2002, the Argentine government adopted many new economic measures as a result of the continuing political, social and economic crisis. These economic measures included (i) the abandonment of the country’s fixed dollar-to-peso exchange rate, (ii) the conversion of U.S. dollar-denominated loans into pesos and (iii) the placement of restrictions on the convertibility of the Argentine peso. Since 2003, the political and social situation in Argentina has showed signs of stabilization, the Argentine peso has appreciated against the U.S. dollar, and the economy and electricity demand has started to recover.

The regulations adopted in 2002 and 2003 in the energy sector effectively overturned the U.S. dollar based nature of the electricity sector. In the wholesale power market, electricity generators declared their costs of generation (which reflected their fuel costs) on a semi-annual basis. Under the current regulations, energy prices were partially converted from the original U.S. dollar denomination into Argentine pesos (“pesofied”), following the pesofication of the price of natural gas. However, the authorities permitted the

19




production cost for alternative fuels (fuel oil, coal) to reflect international costs. In order to avoid price increases associated with the use of alternative fuels, market regulations were changed so that the spot price will be set considering only production costs declared with natural gas. Therefore, while generators received remuneration for the use of alternative fuel, this cost is not considered when setting the spot price. Because of this, generation prices still reflect an artificially low fuel price, but because of the gas supply crisis and the subsequent agreement between the government and the gas producers to readapt the prices, as described below, this effect has been almost offset and gas prices will reach the original value in 2006.

During 2004, the Energy Secretariat reached agreements with natural gas and electricity producers to reform the energy markets. The agreement with natural gas producers established a recovery path that increased wellhead prices to 80% of the U.S. dollar price by July, 2005 and a second path that will reach export parity by the end of 2006. In the electricity sector, the Energy Secretariat passed Resolution 826/2004, inviting generators to partially contribute their existing and future credits in the Wholesale Electricity Market (“WEM”) from January 2004 to December 2006, which will fund new capacity to be installed by 2008. In exchange, the Government committed to reform the market rules to match the pre-crisis rules, setting the capacity payment with a U.S. dollar reference and eliminating all regulations fixing an artificially low price in the wholesale market by 2008. The Argentina government reached an agreement on this with more than 90% of the generators by May 2005. On October 7, 2005, the Energy Secretariat passed Resolution 1193/05 that starts the process of re-adaptation through the definitive agreement for the electricity market. This definitive agreement was signed on October 17, 2005. There can be no assurance, however, that the Argentina government will honor its commitment to release restrictive measures that it has placed upon wholesale prices after the new capacity is installed.

Under the previous regulations, distribution companies were granted long-term concessions (up to 99 years) which provided, directly or indirectly, tariffs based upon U.S. dollars and adjusted by the U.S. consumer price index and producer price index. Under the new regulations, tariffs are no longer linked to the U.S. dollar and U.S. inflation indices. The tariffs of all distribution companies were converted to pesos and were frozen at the peso notional rate as of December 31, 2001. In October 2003, the Argentine Congress enacted Law No. 25,790 that established the procedure for renegotiation of the public utilities concessions and extended the period for that process until December 31, 2006. In combination, these circumstances create significant uncertainty surrounding the performance of the electricity industry in Argentina, including the Argentine subsidiaries of AES.

On November 12, 2004, EDELAP, an AES distribution business, signed a Letter of Understanding with the Argentine Government in order to renegotiate its concession contract and to start a tariff reform process, which was ratified by the National Congress on May 11, 2005. Final government approval was reached on July 14, 2005. As a first step during this process, a Distribution Value Added (“DVA”) increase of 28% effective February 1, 2005 has been granted. Invoicing of the tariff increase commenced in August 2005. The agreement also includes: (i) local cost adjustments to the tariff; (ii) elimination of penalties arising from the gas curtailment by Argentina; (iii) long term payment terms of penalties owed to the customers; (iv) and other favorable conditions which are intended to increase the company value. The agreement was the first of its kind signed with UNIREN (Unit for the Renegotiation and Analysis of Public Services Contracts) in the Argentine electricity sector. Upon execution of the Letter of Understanding, AES agreed to postpone or suspend certain international claims, however, the Letter of Understanding provides that if the government does not fulfill its commitments, AES may re-start the international claim process. AES has postponed any action until the tariff reset is finalized (not later than December 2006).

On October 24, 2005, EDEN and EDES, two AES distribution businesses in Argentina, signed a Letter of Understanding with the Ministry of Infrastructure and Public Services of the Province of Buenos Aires to renegotiate their concession contracts and to start a tariff reform process, which was approved by

20




a Governor Decree on November 30, 2005. This Letter of Understanding includes the following: (i) an initial 19% DVA increase effective August 2005, and an additional DVA increase which will be in force in accordance with National Government policies; (ii) penalties recorded during the 2002-2005 period will not be paid; (iii) Quality Service Regime penalties will be reduced and (iv) full tariff reset proceedings will be carried out in 2007. This Letter of Understanding also includes other favorable conditions beneficial to these distribution facilities. The Letter of Understanding provides that in case the government does not fulfill its commitments, AES may re-start the international claim process. AES has postponed any action with respect to international claims until the tariff reset is finalized (not later than December 2007).

Brazil.   Under the present regulatory structure, the power industry in Brazil is regulated by the Brazilian government, acting through the Ministry of Mines and Energy (“MME”) and the National Electric Energy Agency (“ANEEL”), an independent federal regulatory agency which has exclusive authority over the Brazilian power industry.

ANEEL’s main function is to ensure the efficient and economic supply of energy to consumers by monitoring prices and ensuring adherence to market rules by market participants in line with policies dictated by the MME. ANEEL supervises concessions for electricity generation, transmission, trading and distribution, including the approval of applications for the setting of tariff rates, and supervising and auditing the concessionaires. ANEEL’s core areas of responsibility that are directly related to AES’s businesses are: economic regulation, technical regulation and consumer affairs oversight.

On December 21, 2001, in order to compensate electricity distributors and generators for losses incurred during the rationing program instituted in June of that year, the President of Brazil issued a provisional measure. The provisional measure provided general authorization for: (i) the pass-through to consumers of costs incurred by generators for the purchase of energy at spot prices during the rationing program, (ii) the recovery in future years of revenue losses sustained by distributors during the rationing period, through an Extraordinary Tariff Adjustment (“RTE”), and (iii) the institution, by the Brazilian National Bank for Economic and Social Development (“BNDES”), of an emergency support program in order to compensate distributors, generators and independent power producers for the rationing impacts, which contemplates the disbursement of some loans to these companies.

The Brazilian government established a tracking account mechanism (“CVA”) to mitigate risks relating to Parcel A costs (non-manageable costs relating to energy purchase and sector charges that each distribution company is permitted to pass through to customers) not being passed-through to tariffs.

Generator’s and distributor’s losses are recovered through the RTE, as calculated pursuant to a resolution issued by ANEEL on January 24, 2002 and a resolution issued by the Energy Crisis Coordination Committee, the committee created as result of the energy crisis, on December 21, 2001. As of January 2002, the Company was permitted to charge consumers the RTE over a 65-month period. However, after regulatory review, and in order to allow the full recovery of the Parcel A costs, ANEEL, through a resolution issued on January 12, 2004, established the extension of AES Eletropaulo’s RTE recovery period (from 65 to 70 months), and that Parcel A recovery will happen only after the RTE recovery.

Under the rationing agreement of 2001, AES Sul was permitted to record additional revenue and a corresponding receivable from the spot market during 2001 and the first quarter of 2002. However, ANEEL promulgated Order # 288 in May 2002, which retroactively changed the calculation methods for electricity pricing in the Brazilian Wholesale Energy Market, Mercado Atacadista de Energia or “MAE”, transforming a $187 million credit in the favor of AES Sul into a debt of $34.8 million. We recorded a pretax provision of approximately $160 million, including the amounts for AES Sul, against revenues during May 2002, to reflect the negative impacts of this retroactive regulatory decision.

21




On August 23, 2002, AES Sul filed a lawsuit against the ANEEL seeking the annulment of Order # 288. On September 18, 2002, a preliminary injunction was granted to AES Sul. This injunction was suspended due to an Interlocutory Appeal filed by ANEEL on September 20, 2002. However, on July 20, 2005, ANEEL’s appeal was deemed groundless by the Federal Region Court, and the original injunction granted AES Sul was reinstated. Therefore, ANEEL must file with the Câmara de Comercialização de Energia Elétrica (“CCEE”) (formerly the MAE) to recalculate settlement amounts for each market participant during this disputed period, and to issue new credit/debit invoices to these market participants. A decision on the merits is still pending with the first level court.

If a settlement occurs with the effect of Order # 288 in place, AES Sul will owe approximately a net amount of $30 million, based upon the December 31, 2004 exchange rate. AES Sul does not believe it will have sufficient funds to make this payment and several creditors have filed lawsuits in an effort to collect amounts they claim are overdue. AES Sul is petitioning the courts to aggregate the individual lawsuits with payments until the matter is resolved. If AES Sul prevails and the MAE settlement occurs absent the effect of Order # 288, AES Sul will receive approximately $132 million, based upon the December 31, 2004 exchange rate. If AES Sul is unsuccessful and unable to pay any amount that may be due to MAE, penalties and fines could be imposed up to and including the termination of the concession contract by ANEEL. AES Sul is current on all MAE charges and costs incurred subsequent to the period in question in the Order # 288 matter. All amounts, including the amount owed to MAE in the event AES Sul loses the case, are provisioned in AES Sul’s books.

The CVA is a tracking account that records non-manageable costs monthly price variations (positive and negative) over the course of the year. At each tariff adjustment date, distribution companies would be allowed an additional tariff increase, for the following 12 months, in order to compensate for the accumulated value of the CVA plus interest. On April 4, 2003, the MME issued a decree postponing, for a 1-year period, the tracking account tariff increase. According to this decree, the pass-through to tariffs of the amounts accumulated in the tracking account for the distribution concessionaires that had been scheduled to occur from April 8, 2003 to April 7, 2004 were postponed to the subsequent year’s tariff adjustment. As a result, approximately $12 million and $173 million, for AES Sul and AES Eletropaulo, respectively, are to be recovered over a 24-month period rather than the usual 12-month period. AES Eletropaulo and AES Sul received in their respective 2004 tariff adjustments, 50% of the deferred CVA recoverable over a 12-month period; and the additional 50% as part of the 2005 tariff adjustments, which will be recoverable over the ensuing 12-month period.

In order to compensate for the deferral of the increase relating to the tracking account, BNDES provided distribution companies with loans, which will be repaid during the recovery period. On December 23, 2004, AES Sul received a BNDES loan equivalent to $16.5 million and on June 3, 2004, AES Eletropaulo received a BNDES loan equivalent to $166 million, both to be repaid within the recovery period.

In order to maintain the economic and financial equilibrium of the concession, utilities are entitled to the following types of tariff adjustments contemplated in the concession contracts:

·       annual tariff adjustments;

·       tariff reset; and

·       extraordinary revisions, in the event of significant changes in concessionaires’ cost structure.

The primary purpose of the Annual Tariff Adjustment (“IRT”) is the maintenance of an adjusted tariff for inflation and the sharing of efficiency gains with consumers. The IRT uses a formula such that non-manageable (Parcel A) costs are passed through to the consumers and manageable (Parcel B) costs are indexed to inflation. An ‘X-Factor’ is applied to capture the sharing of efficiency gains, effectively reducing the inflation index that is applied to Parcel B costs. The operations and maintenance costs

22




considered in the tariff are based on the concept of a Reference Company, not actual costs. In many cases, the Reference Company may not be reflective of distribution companies operating in Brazil and thus, underestimate true operating costs. These costs which include certain taxes and other issues are being discussed under administrative appeal with ANEEL. In addition, the distribution companies are challenging certain methodologies used for the tariff revision.

ANEEL authorized an average adjustment of 2.12% for AES Eletropaulo tariffs on July 4, 2005. ANEEL authorized an average adjustment of 9.42% for AES Sul on April 19, 2005.

The Brazilian government carried out a wide reform in the Brazilian power sector and on December 11, 2003, announced a proposed new model for the Brazilian power sector (the “New Power Sector Model”) and enacted Provisional Measures #144 and #145, which set forth the basic rules that will govern the New Power Sector Model. On March 15, 2004, Law #10848 was enacted, which sets forth the basis of the new regulatory framework and general rules for power commercialization, regulated by Decree #5163, of July 30, 2004, and other administrative rulings.

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

·       It creates two energy commercialization environments: (1) the regulated contractual environment (ACR), intended for the distribution companies, and (2) the free contract environment (ACL), designed for traders and free consumers.

·       As of January 2005, every distribution utility is obligated to meet 100% of its anticipated energy requirements, subject to the application of penalties. Compliance with such obligation requires distribution companies to contract for energy through: (i) auctions of energy from new (proposed) generation projects; (ii) auctions of energy from existing generation facilities; and (iii) other sources, including public calls to purchase energy from distributed generation; renewable energy sources (through PROINFA—Brazilian Renewable Energy Incentive Program); pre-existing purchases made before Law #10848/04; and purchases from Itaipu.

·       Distribution utilities can pass through the amounts contracted, up to 103% of their load, conditioned upon the amendment of the concession contracts: ANEEL will adopt a new pass-through methodology in the annual tariff adjustment; and variations of the energy purchase costs will be reflected in the tracking account (CVA).

As part of the implementation process of the New Power Sector Model, distribution companies signed amendments to the concession contracts, which modified the clause relating to the tariffs with respect to: (i) methodology of power purchase cost pass-through; and (ii) exclusion of PIS/COFINS (taxes over revenue).

The Electric Energy Commercialization Chamber (“CCEE”), successor of the MAE, carried out, on December 7, 2004, the largest auction in the country’s history, in which power distribution utilities bought energy to serve 100% of their markets projected for 2005, 2006 and 2007. The energy traded in this auction will be the object of contracts lasting eight years starting from 2005, 2006 and 2007. The Brazilian government is inserting the rights for the CVA of energy purchased from the auction to agreement on additional amendments to concession contracts. This can represent risk relating to certain aspects of the current IRT methodology. The New Power Sector Model Law is currently being challenged on constitutional grounds before the Brazilian Supreme Court. To date, the Brazilian Supreme Court has not reached a final decision and we do not know when such a decision may be reached. Therefore, the New Power Sector Model is currently in force. Regardless of the Supreme Court’s final decision, certain portions of the New Power Sector Model relating to restrictions on 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.

23




If all or a portion of the New Power Sector Model is determined unconstitutional by the Brazilian Supreme Court, the regulatory scheme introduced by the New Power Sector Model may not come into effect, generating uncertainty as to how and when the Brazilian government will be able to introduce changes to the electric energy sector. We have already purchased a significant portion of our electricity needs through 2016, and the pass-through to tariffs of such electricity is expected to continue to be governed by the regulation in effect on the date of the purchase. As such, irrespective of the outcome of the Supreme Court’s decision, we believe that in the short term the effects of any such decision on our activities will be limited. Nevertheless, the exact effect of an unfavorable outcome of the legal proceedings on us is difficult to predict and it could have an adverse impact on our business and results of operations.

Cameroon.   The law governing the electricity sector was passed and promulgated in December 1998, which defines the new institutional organization of the electricity sector. This law, and subsequent ministerial decrees and orders, govern the activities of the electricity sector, sets the rates and basis for the calculation, recovery and distribution of royalties due by operators in the electricity sector, and spells out required documents and charges for the processing of applications relating to concession, license, authorization and declaration in order to carry out generation, transmission, distribution, importation, exportation and sales of electricity.

The mission of the Electricity Sector Regulatory Board (“ARSEL”) involves regulating and ensuring the proper functioning of the electricity sector, maintaining its economic and financial balance and safeguarding the interests of electricity operators and consumers. ARSEL has the legal status of a Public Administrative Establishment and is placed under the dual technical supervisory authority of the Ministries charged with electricity and finance.

The Concession agreement of July 18, 2001, between the Republic of Cameroon and AES SONEL covers a twenty-year (20) period of which 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 2004, AES SONEL and the Cameroonian Government started renegotiating the concession contract. The issues included in this renegotiation process were: the quality of services requirements, the connection targets, the tariff formulation, the obligation of developing new generation capacity and the penalties regime. AES SONEL expects to complete the renegotiation process in 2006.

Chile.   In Chile, the regulation of production schedules for electricity generation facilities is based on the marginal cost of production, which is the cost of the most expensive unit required by the system at the time. The spot price among generation companies for both electrical capacity (the amount of electricity available at any point in time) and electrical energy (the amount of electricity produced or consumed over a period of time) is also the marginal cost of production. Chile has four electricity systems. The major two interconnected electricity systems are the Central Interconnected System (Sistema Interconectado Central) (“SIC”) and the Northern Interconnected System (Sistema Interconectado del Norte Grande) (“SING”), which cover almost 97% of the population of the country.

In order to meet demand for electricity at any point in time, the lowest marginal cost generating plant in an interconnected system is used before the next lowest marginal cost plant is dispatched. As a result, at any specific level of demand, the appropriate supply will be provided at the lowest possible marginal cost of production available in the system.

Generation companies are free to enter into sales contracts with distribution companies and other customers for the sale of capacity and energy. However, the electricity necessary to fulfill these contracts is provided by the contracting generation company only if the generation company’s marginal cost of production is low enough for its generating capacity to be dispatched to meet demand. Otherwise, the generation company will purchase electricity from other generation companies at the marginal cost of production in the system.

24




According to existing law, during periods when production cannot meet system demands, regardless of whether the government has enacted a rationing decree, the price of energy exchanges among generation companies is valued at the “shortage cost” determined by the National Energy Commission (“NEC”), which takes into account the cost to consumers for not having energy available. This law was first tested in November 1998 when generators in the SIC were unable to agree on the implementation of the shortage cost during the supply deficit and associated mandated rationing periods. The matter was referred to the Ministry of Economy, which issued its ruling in March 1999. Based on this decision, generators with energy deficits at the time were required to pay companies with energy surpluses the shortage cost or corresponding spot price equal to the cost of unserved energy for energy purchases during that period.

The prices paid to generation companies by distribution companies for capacity and energy to be resold to their retail customers are, pursuant to law, based on the expected average marginal cost of capacity or energy. In order to ensure price stability, however, the regulatory authorities in Chile establish prices, known as “node prices,” every six months to be paid by distribution companies for the energy and capacity requirements of regulated consumers. Node prices for energy are calculated on the basis of the projections of the expected marginal costs within the system over the next 24 to 48 months, in the case of the SIC and the SING. The formula takes into account, among other things, assumptions regarding available supply and demand in the future. Node prices for capacity are based on the marginal investment required to meet peak demand, based on the cost of a diesel-fired turbine. Prices for capacity and energy sold to large customers (over 0.5 MW) and other generation companies purchasing on a contractual basis are unregulated and are often set with reference to node prices, alternative fuel prices, exchange rates and other factors. If average prices for capacity and energy sold to non-regulated customers differ from node prices by more than a defined percentage (5%-30%, calculated pursuant to regulations), node prices are adjusted upward or downward, as the case may be, so that the difference between such prices equals such percentage. In contrast, the spot price paid by one generation company to another for energy is referred to as the “system marginal cost,” which is based on the actual marginal cost of the highest cost generator producing electricity in the system during the relevant period, as determined on an hourly basis.

Since the system marginal cost for energy is set weekly (but may in certain circumstances be changed on a daily basis) based on variables that can change on an instantaneous basis, and the node price for energy is set every six months based on projections of these variables over the next 24 to 48 months, in the case of the SIC and SING, the system marginal cost for energy of a system tends to be more volatile than the node price for energy of that system. In periods of low water conditions that require greater generation of energy by more costly thermoelectric plants, the system marginal cost typically exceeds the node price. In periods of high water conditions when lower cost hydroelectric facilities can meet the majority of demand, the system marginal cost is typically below the node price and may in fact decline to zero at some hours.

On March 13, 2004, Law No. 19.940 was enacted establishing amendments to the existing Electricity Law, principally in relation to tolls charged for the use of high voltage network and transmission systems. The reduction of the minimum demand required to be considered as an unregulated customer went from 2 MW to 0.5 MW. In addition, other factors considered are the reduction of the floating band for regulated price from 10% to 5%, the incorporation of elements to create an ancillary services market and the pricing mechanism for small and medium-sized electricity systems. The modifications contained in Law No. 19.940 maintain or improve our position with regard to both our current status and projected development and, in particular, with regard to the issues related with transmission tolls. In addition, the Regulations to the Electricity Law, Supreme Decree No. 327, which was modified on October 9, 2003 with respect to the clarification of the methodology utilized to calculate transmission tolls, has been replaced by Law No. 19.940.

On March 25, 2004, the Argentine government published Resolution 265, which privileged the domestic supply of natural gas, immediately affecting the export of natural gas to neighboring countries,

25




primarily Chile. However, this resolution provided suppliers with alternative means of supply under existing export contracts. Between April and June 2004, daily export restrictions to Chile fluctuated between 20% and 47% of contracted volumes, depending on domestic demand. At the end of 2004, the curtailments were less than 10% due to improved hydrological conditions in Argentina and Chile, and increased availability of Bolivian gas.

This situation changed at the beginning of 2005 when as a result of high electricity demand and natural gas consumption in Argentina, in addition to the policy established by CAMMESA to conserve water under Resolution 839, the curtailments increased during summer months reaching a peak of almost 50%, equivalent to 402 Mmcf/d at the end of May 2005. From May until September 2005, the daily export restrictions to Chile fluctuated between 40% and 10%. In the last quarter of 2005, the restrictions were reduced 7% to 12%, mainly due to improved hydrological conditions compared to the beginning of the year.

Our subsidiary Electrica Santiago produces electricity by burning natural gas produced in southern Argentina which is transported to central Argentina through a pipeline owned by Transportadora Gas del Norte S.A., or TGN, and then to Chile. The TGN pipeline supplies consumers in Argentina and Chile. Interruptions in the supply and/or transportation of natural gas by TGN would adversely affect the operations and financial condition of Electrica Santiago. Such potential interruptions would materially impair Electrica Santiago’s ability to generate electricity and would force it to rely on the spot market to purchase electricity to meet its contractual commitments. Furthermore, because all combined-cycle plants in the SIC use the same pipeline to obtain their natural gas supplies from Argentina, a disruption of this supply would materially increase prices in the spot market. The reliance on the spot market to purchase electricity could have a material adverse effect on Electrica Santiago.

On May 3, 2005, a bill to amend the Electric Law was approved by the Chilean Congress which was promulgated by the executive branch on May 19, 2005 (Law No 20.018). The bill was designed to mitigate the effects of the restrictions on natural gas exports to Chile which have been applied by the Argentine government since March 2004. The main aspects of Law 20.018 include:

·       implementation of public bid processes for distribution companies after 2009;

·       modification of regulated node price methodology, progressively replacing the node price with public bid prices and improvement in the correlation between regulated node prices and unregulated market prices in the interim period;

·       stabilization of generation companies’ revenues by allowing them to enter into long-term fixed price contracts with distribution companies (maximum of 15 years);

·       authorization of voluntary savings incentives which allow generation companies to directly negotiate demand reductions with final customers;

·       determination that natural gas shortages can no longer be considered force majeure events and compensation to customers by generation companies which fail to operate due to gas shortages; and

·       establishment of compensation for losses by generation companies when obligated to sell to distribution companies that are unable to independently contract adequate supplies.

China.   The Chinese government is in the process of implementing a fundamental long-term restructuring of the electric power sector, embodied in the National Power Industry Framework Reform Plan (the “Reform Plan”) promulgated by the State Council in April 2002. The key elements of this plan involve separation of generation and transmission, and the introduction of market-driven competition into China’s electric power industry whereby generators will be required to compete in the market for their output, with a system of competitive bidding for on-grid tariffs.

26




As a result of the restructuring, a new industry regulator, China’s National Electricity Regulatory Commission (“China’s NERC”) was established. The responsibilities of China’s NERC include: promulgating operating rules for the electric power industry; supervising the operation of the electric power industry and safeguarding fair competition; monitoring the quality and standard of production by electric power enterprises; and issuing and administrating electric power service licenses.

The surge in economic growth over the last three years increased the demand for electric power, which has outpaced previous demand forecasts, leading to a shortage of generating capacity and even load-shedding in some areas. The strong growth in electricity demand has caused the government to delay or slow the pace of moving towards a competitive market. However, it is expected that supply and demand in China will reach equilibrium in 2006, with some regional power grids experiencing supply surplus in 2007. The ultimate adoption of the Reform Plan may result in market and regulatory changes.

In April 2005, with a view to implementing the power industry reform, the National Development and Reform Commission released an interim regulation governing on-grid tariffs, along with two other regulations governing transmission and retail tariffs. All three came into effect on May 1, 2005 (“Interim Regulations”). Pursuant to the Interim Regulations, prior to adoption of a pooling system, the on-grid tariffs shall be appraised and ratified by the pricing authorities by reference to the economic life of power generation projects, and determined in accordance with the principle of allowing independent power producers to cover reasonable costs and to obtain reasonable returns. However, it further defined that the generation costs shall be the average costs in the industry and reasonable returns shall be formulated on the basis of interest rate of China’s long-term treasury bond plus certain percentage points. Furthermore, the Interim Regulations provided that, after adoption of a pooling system, the on-grid tariffs shall comprise two components: capacity charge and energy charge. The capacity charge shall be determined by the pricing authorities based on the average investment costs in the same regional power market; and the energy charge shall be determined through market competition. There is also a provision to allow the on-grid tariffs to be pegged to the fuel price in the case of significant fluctuations in fuel price. It is unclear whether these Interim Regulations will have a material adverse effect on our businesses.

Colombia.   In 1994 the Colombian Congress issued the laws of Domiciliary Public Services and the Electricity Law, which set the institutional arrangement for the electric sector and the general regulatory framework. The Regulatory Commission of Electricity and Gas (“CREG”) was created to foster the efficient supply of energy through regulation of the wholesale market, the natural monopolies of transmission and distribution, and by setting limits for horizontal and vertical economic integration. The control function was assigned to the Superintendency of Public Services. The Mining and Energy Planning Unit (“UPME”) develops plans for the energy sector. These plans are then adopted by the Ministry of Mines and Energy. The general regulatory framework established free access in the networks, free entrance 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 bilateral contracts and a mandatory pool and spot market for all generation units larger than 20 MW. Each unit offers its availability quantities for a 24 hour period with one price set for those 24 hours. The dispatch is arranged by price merit and the spot price is set by the marginal unit. The system is one node.

The spot market started in July 1995, and in 1996 a capacity payment was introduced for a term of 10 years. This payment is US$5.25 kW-month, and it is assigned through an administrative and centralized hydro/thermal dispatch model based on the calculated firm capacity that is needed to be generated under extremely dry conditions. This capacity payment is reflected in the spot market as a floor of the generators’ bids of approximately US$12/MWh. Although the 1996 capacity factors for hydro plants were based on the worst historical El Niño situation, in 2000 CREG recalculated these capacity factors based on a theoretically more severe hydrology condition. This regulatory change reduced the firm capacity

27




remuneration of AES-Chivor for that year from 485 MW to 304 MW. Our company and other hydro generators initiated litigation for this reason. The current remuneration for 2006 is 290 MW.

CREG has released an outline of a proposal that would replace this administrative process for firm capacity payments, and instead have a more market based system, in which capacity payments would be determined through auctions of energy options. CREG has not yet released sufficient detail of this new proposal to evaluate the effect it would have on the Company.

Bilateral contracts between a generator and suppliers are treated as financial instruments which are settled by the Market Administrator. These contracts are normally either “take or pay” or “take and pay” agreements, and normally have a term of one to three years. There is no regulatory obligation for an electricity supplier to hedge its consumers’ demand, and the negotiation of energy contracts between generators and suppliers for unregulated customers is unrestricted. The contracts to supply energy to regulated (small) consumers must be assigned by the Load Servicing Entities (“LSE”) through a public bidding process to determine the lowest offer.

Dominican Republic.   The electricity sector in the Dominican Republic has evolved from a state owned system, to a reform period from 1997 through 1999 which was regulated by the Ministry of Industry and Commerce without an overall plan, and finally, with the passage of the General Electricity Law No. 125-01 on July 26, 2001, and its regulations, into a system with more concise rules, along with new institutions to formulate energy policy and regulate the sector, governed by the Energy National Commission (“CNE”) and the Superintendancy of Electricity (“SIE”). However, some of the new resolutions adopted by SIE are in conflict with the regulations created by the Ministry of Industry and Commerce prior to enactment of Law 125-01.

During 2004, the Dominican Republic was shaken by a severe economic, financial and political crisis, caused mainly by the status of the public finances and the bankruptcy of the three main commercial banks. Although the electricity sector has been vulnerable for years, it was this economic downturn and an increase in fuel prices that essentially caused a financial crisis in the Dominican Republic electrical sector. Specifically, the inability to pass through higher fuel prices and the costs of devaluation led to a gap between collections at the distribution companies and the amounts required to pay generators for electricity generated. There are no assurances that these issues will be resolved in favor of the Company.

The election of a new presidential administration in August 2004 has been accompanied by progress towards addressing the crisis in the electricity sector. Negotiations have intensified between the government, the multilateral lending and development agencies such as the IMF and the World Bank and the private electricity sector. The key issues that are the focus of these negotiations include (i) the failure to provide for full pass through of the costs of electricity supply to consumers; (ii) the failure of the regulator to follow through on subsidy commitments, which has put the distribution companies in the position of effectively financing portions of the subsidy programs; and (iii) the fiscal deficit of the government that requires multilateral lending to reconstitute the sector.

During 2005, the government has been paying both the subsidies and its own energy bills on time; the tariff has been modified to recognize the fuel generation basket, and there is increased support for fraud prosecution. Despite this improvement over prior years, the electricity sector has not completely recovered from the financial crisis of 2004. Last year it needed US$500 million to cover the current operations, and for 2006 it will need another US$500 million, which indicates that the electricity sector in the Dominican Republic remains fiscally unstable, so that additional reforms may be needed.

El Salvador.   In 1996, the government of El Salvador began the process of privatizing, modernizing and restructuring El Salvador’s electricity industry in order to create an open and competitive electricity sector with the support of strategic foreign investors. To accomplish its goal, the government created a new regulatory framework through the enactment of the Electricity Law in October of 1996, as subsequently

28




amended in June 2003. The Electricity Law regulates the generation, transmission, marketing, distribution and supply of electricity in El Salvador and provided the basis for private sector participation and competition in the Salvadoran energy sector, the unbundling of electricity generation, transmission and distribution, the privatization of electricity distribution and generation assets and the creation of a transparent regulatory structure.

From 1986 to 1998 CEL, a Salvadoran state-owned entity, generated, transmitted and distributed all of El Salvador’s electricity on a monopoly basis. All planning, regulatory and executive functions concerning electricity generation, transmission and distribution were vested in CEL. Under the Electricity Law, an independent regulator, SIGET, was established, and CEL was required to reorganize its generation, transmission and distribution assets to facilitate privatization. CEL separated its generation, transmission and distribution activities from one another and further divided its generation and distribution activities into operationally independent companies for purposes of privatization.

El Salvador has five electricity distribution companies, created from CEL’s distribution assets, which were privatized in 1998. AES controls four of these five distribution companies: CAESS, CLESA, EEO, and DEUSEM. In preparation for their privatization, each of these companies absorbed elements of CEL’s rural electrification activities that were situated near their networks.

The government has recently adopted certain revisions and adjustments to the regulatory system created by the Electricity Law, and additional modifications are under consideration. The government is studying how to further separate the activities of CEL and ETESAL, the transmission company that is owned by CEL, with the goal of privatizing ETESAL. In addition, new Salvadoran regulations have been recently issued aimed at facilitating the entry of electricity traders into the electricity market and improve the transparency of the pricing signals in the wholesale market.

In June 2003, the government amended the Electricity Law to grant greater regulatory authority to SIGET and to create a compensatory fund in the wholesale market to promote stability in the price of energy on the spot market. SIGET has recently prepared norms and guidelines in the form of a manual which will set minimum standards for electricity distribution companies for system design, distribution losses and costs, as well as service quality and reliability. In addition, as part of the Company’s regular upcoming five-year tariff review process, SIGET is reviewing the characteristics of the demand curve for each of the Company’s electricity distribution networks, in order to be able to better analyze and review the Company’s proposed tariffs.

During 2005, the Ministry of Economy (“Ministerio de Economía”) proposed revising the dispatch rules for El Salvador’s electricity market from a bidding to an economic dispatch basis. If this reform is adopted in the future, it may adversely affect the Company’s ability to continue to generate margins on the energy they buy and sell for their customers.

European Union.   European Union (“EU”) legislation is required to be implemented in each of the EU member states, although there is a degree of disparity as to how such legislation is implemented and the pace of implementation in the respective member states. EU legislation covers a range of topics which impact on the energy sector, including market liberalization and environmental legislation. The Company has subsidiaries which operate existing generation businesses in a number of countries which are member states of the European Union (EU), including the Czech Republic, Hungary, the Netherlands and the United Kingdom.

The principles of market liberalization in the EU electricity and gas markets were introduced under the Electricity and Gas Directives (Directive 1996/92/EC and Directive 1998/30/EC, respectively). In 2005, the European Commission, the legislative and administrative body of the EU, launched a sector-wide inquiry into the European gas and electricity markets. In the context of the electricity market, the inquiry has to date focused on identifying problems related to price formation in the electricity wholesale markets

29




and the role of long term agreements as a possible barrier to entry with a view to improving the competitive situation. The Hungarian Competition Authority launched a parallel inquiry into the national electricity and gas market and announced its preliminary findings in late 2005. These findings identified long term contracts as a potential source of competition concern, in addition to other obstacles, such as having a single power buyer, MVM. The European Commission (“EC”) is presently analyzing the results of its inquiry, and has yet to decide what formal steps if any they will take with respect to their preliminary analyses. It is therefore too early to predict the concrete impact of the EC sector inquiry or the Hungarian Competition Authority’s inquiry into AES businesses in the EU.

The EC has also introduced environmental legislation which impacts the electricity sector in general and includes:

·       The EU Directive on Integrated Pollution Prevention and Control (1996/61/EC) (“IPPC Directive”) which requires member states to prevent or reduce pollution from a range of installations including electricity generation stations and introduces a permit regime to ensure the prevention or reduction of pollution from such installations.

·       The Large Combustion Plants Directive (2001/80/EC) (“LCPD”) which introduced a regime for the reduction of emissions sulphur dioxide, nitrogen oxides and particulates from large combustion plants, with increased restrictions coming into effect in two phases from 2008 and 2016, respectively.

·       The Renewables Directive (2001/77/EC) which deals with the promotion of electricity generated from renewable sources and sets a target of 12% of electricity consumed in the EU to be generated from renewable sources by 2010.

·       The EU Emissions Trading Directive (2003/87/EC) which, amongst other things, established the EU Emissions Trading Scheme (“EUETS”) in respect of emissions of carbon dioxide effective January 1, 2005.

Progress in the implementation of the directives referred to above varies from member state to member state. AES generation businesses in each member state will be required to comply with the relevant measures taken to implement the directives. See “Air Emissions” below, for a description of these Directives.

Hungary.   In 2004, in connection with the accession of Hungary as a member state of the European Union, the Hungarian government provided notification to the European Commission of certain legislative arrangements concerning compensation to the state owned electricity wholesaler, MVM. The Commission conducted a preliminary investigation to determine whether or not any alleged government aid was provided through MVM to its suppliers which was incompatible with the common market. The Commission has decided to open a formal investigation. AES Tisza is not a named party to the investigation, but could be adversely affected in the event that the Commission was to conclude that AES Tisza was one of the beneficiaries of unlawful state aid by virtue of its power purchase arrangements with MVM. As an interested party, AES Tisza will have the opportunity to make submissions to the Commission in relation to the investigation. It is currently too early to predict the outcome of the formal investigation.

In 2006, the Hungarian government enacted legislation to amend the Hungarian Electricity Act (Act 110 of 2001) to enable, amongst other things, the application of regulatory pricing to the sale of electricity by generators to the state owned utility wholesaler, MVM. No implementing legislation or regulations have yet been enacted and it is therefore too early to predict the impact of this legislation.

30




India.   In 2003, the Government of India enacted Electricity Act 2003 (“New Act”) to establish a framework for a multi-seller-multi-buyer model for the electricity industry, and introduced significant change in India’s electricity sector. These changes included:

·       Generation, excluding hydro and nuclear, is delicensed. Generation companies can sell power to a customer of its choice;

·       Transmission, immediate non-discriminatory open access is allowed;

·       Distribution, open access will be implemented in phases;

·       Trading is recognized as a licensed activity; and

·       All states are required to establish an electricity regulator.

In March 2004, the Central Electricity Regulatory Commission (“CERC”) issued terms of conditions for tariff determination for generation and transmission. In early 2004, the Government of India issued Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by Distribution Licensees. In February 2005, the Government of India came out with the National Electricity Policy and in January 2006 published the National Tariff Policy (together “Policy”).

The Policy established deadlines to implement provisions of the New Act: June 2005 was the deadline for the state regulators to notify regulation for open access to 1 MW; June 2006 is the deadline for technology upgrades to facilitate open access in transmission; and March 2007 is the deadline for Electricity Regulatory Commission of the respective States (“SERC”) to ensure energy audits.

The Policy recommends Multi-Year Tariffs (“MYT”) but without any deadline for implementation. The Policy also advocates rationalization of tariffs but without focusing on removal or reduction of cross subsidies. The Policy recognizes the need for private investment to meet full demand for power by 2012, but does not specify specific measures to attract private capital.

India’s power sector is regulated by CERC at the national level and by SERCs at the state level. CERC is responsible for interstate transmission and generation for more than one state. SERCs are responsible for electricity and intra-state transmission tariffs. The Government of India assists states in arranging financing for restructuring of state utilities for financial turnaround. However, actual implementation of the reform process is entirely contingent on the state governments and regulators. Although the New Act and the Policy advocates regulators be independent, and develop transparency and political insulation, the regulatory environment and risks could be substantially different across States. It is not clear whether existing and concluded power purchase agreements are subject to re-opening by regulatory bodies. If re-opened, the review could have an adverse impact on OPGC, our generation facility in India.

Kazakhstan.   The Kazakhstan Parliament and Government have implemented a series of regulatory normative acts to encourage competition in wholesale and retail electricity markets. Under the present regulatory structure, the electricity generation and supply sector in Kazakhstan is mainly regulated by the government, acting through the Ministry of Energy and Mineral Resources and its committees (the “Ministry”), the Committee for protection of competition of the Ministry of Industry and Commerce (the “Committee”) and the Agency for regulation of the natural monopolies (the “Agency”), that have the necessary authority for the supervision of the Kazakhstan power industry.

The Ministry’s main function is to supervise the appropriate implementation of the normative and sub-normative acts, rules and regulations, ensure the efficiency of the wholesale and retail markets of electricity, and ensure the efficient and economic supply of energy to consumers by monitoring market conditions and ensuring adherence to market rules by market participants. The Ministry’s core areas of responsibility that directly relate to AES’s businesses in Kazakhstan are: competitive economic regulation of the wholesale and retail market of heat and electricity supply, legislative regulation of the businesses

31




within the scope of normative rules and regulations, and consultative assistance of the businesses within the authority granted by the normative acts.

The newly created Committee is an authorized state agency which exercises control over monopolistic activity and the protection of the competition on the wholesale and retail markets of the electricity supply and to coordinate and approve tariffs. The Agency’s main function is to approve and regulate the tariffs of the “naturals monopolists,” the tariffs estimation and discount policy, approval of the compensation tariff and to supervise the activity of the natural monopolists with respect to their tariffs policy.

Ust-Kamenogorsk CHP (“UK CHP”), together with the two hydro plants we operate on a concession basis, Ust-Kamenogorsk (“UK Hydro”) and Shulbinsk (“Shulbinsk Hydro”), have been under jurisdictional control of the Agency since 2003 because their aggregated share in the electricity supply commodity market in the Eastern Kazakhstan oblast is 70%. As such, these businesses are required to notify the Agency about the future price increases for monopolistic commodities (works, services) and the reasons for such price increase. Currently, the Agency is authorized to regulate prices, and to date, all requested price increases have been deemed to be excessive by the Agency.

Power generating entities (UK CHP and our hydro power plants) are required to participate in the centralized trade of electric power. Up to 30% of generated electricity is supposed to be sold via these centralized auctions. Since UK CHP, UK Hydro and Shulbinsk Hydro are deemed to have dominating positions (monopolies), they must get Agency approval for price increases one month in advance, and are therefore disqualified from participating in the centralized auctions (since prices are not set in advance).

Two of our companies that participate in both the wholesale and retail markets as energy sellers are Nurenergoservice LLP and AES Kazakhstan LLP. Although they are not regulated by the antimonopoly legislation or the legislation on the natural monopolies, due to their indirect affiliation with AES generation companies in Eastern Kazakhstan, AES Kazakhstan LLP and Nurenergoservice LLP comply with the antimonopoly legislation when entering into contracts with our generators. During the last two years there were several attempts by the antimonopoly bodies to recognize some contracts as invalid on the grounds of artificially increasing tariffs of the generators by using AES Kazakhstan as an intermediary company.

Mexico.   In 1992, the Electric Energy Public Service Law (Ley del Servicio Público de Energía Eléctrica) (the “Energy Law”) was amended to allow national and foreign private investment participation in the energy generation segment through the following independent-generation forms: self-supply, cogeneration, small production, independent production for sale to the Federal Electricity Commission (Comisión Federal de Electricidad) (“CFE”) and generation for export derived from cogeneration, independent production and small production.

The government entities involved in power generation projects are the Ministry of Energy (Secretaría de Energía), which is in charge of developing the relevant policies on energy matters, the Energy Regulating Commission (Comisión Reguladora de Energía) (“CRE”), which acts as the sector regulator and the CFE, which provides the electric energy public service and owns and operates the national electric system.

The CRE has the authority to grant or revoke permits and authorizations required by private investors to generate electricity in Mexico. The CRE must approve tariffs for the sale of energy to CFE for public distribution, as well as the prices for the transmission and delivery of electricity.

The federal government intends to promote private participation in power generating plants, and to this end has allowed independent power producers to present bids for the purchase of capacity and power. The government seeks what it deems to be a reasonable balance between private and public investment in generating plants.

Independent power production in Mexico has increased considerably in the past years. In 2002, 7% of the national total of electric power was produced by independent producers, in 2003, the percentage

32




increased to 19% and in 2005 to 33%. Installed capacity in independent power production plants has also increased, as has reserve capacity which has grown over 40% in the last six years.

Oman.   Prior to May 2005, the Ministry of Housing, Electricity and Water (“MHEW”) owned all electricity and related water infrastructure in Oman, with exception of a few independent power producers (“IPP”) and independent power and water producers (“IPWP”). MHEW was responsible for the operation and maintenance of the government owned generation plants and the entire transmission and distribution system. Consequent to promulgation of a Sector Law in July 2004 (effective August 2004) the electricity sector was unbundled and divided into newly created corporate entities. A new Regulatory Authority was formed to oversee the Power sector. The Authority was to promulgate rules and subsequently grant generation licenses to all the generating companies in Oman. AES Barka was granted its generation license in May 2005 after complying with all the requirements of the regulator. Furthermore, an Electricity Holding Company was also incorporated to hold the Government’s stake in its generation assets and newly unbundled companies. As a result of the unbundling, nine (9) other companies were formed, comprised of one off-taker for all the electricity and water production in Oman, one transmission company, three generation companies for the government owned plants, and four distribution companies. The existing market continues to be comprised of fully contracted entities and no change in this structure is envisioned, especially for presently contracted facilities, at this time.

Pakistan.   The electricity sector in Pakistan is regulated by three main entities, namely the Water and Power Development Authority (“WAPDA”), the National Electric Power Regulatory Authority (“NEPRA”) and the Private Power Infrastructure Board (“PPIB”).

WAPDA acts as a power off-taker. In 1992, the government of Pakistan approved WAPDA’s Strategic Plan for the Privatisation of the Pakistan Power Sector. This Plan sought to meet three critical goals: a) enhance capital formation, b) improve efficiency and rationalize prices, and c) move over time towards full competition by providing the greatest possible role for the private sector through privatization. A critical element of the Strategic Plan was the creation and establishment of a Regulatory Authority to oversee the restructuring process and to regulate monopolistic services. In December 1997, The Regulation of Generation, Transmission and Distribution of Electric Power Act, 1997, became effective.

NEPRA was created to introduce transparent and judicious economic regulation, based on sound commercial principles, to the electric power sector of Pakistan. NEPRA’s main responsibilities are to: a) issue licenses for generation, transmission and distribution of electric power; b) establish and enforce standards to ensure quality and safety of operation and supply of electric power to consumers; c) approve investment and power acquisition programs of the utility companies; and d) determine tariffs for generation, transmission and distribution of electric power.

NEPRA regulates the electric power sector to promote a competitive structure for the industry and to ensure the co-ordination of reliable and adequate supply of electric power in the future. By law, NEPRA is mandated to ensure that the interests of the investor and the customer are protected through judicious decisions based on transparent commercial principles and that the sector moves towards a competitive environment.

PPIB was established in 1994 to offer support by the government of Pakistan to the private sector in implementing power projects. PPIB provides a “One-Window” facility to investors in the private power sector by acting as a one stop organization on behalf of all ministries, departments and agencies of the Government of Pakistan in matters relating to developing and expediting the progress of power projects in the private sector, either through competitive bidding or through proposals submitted by interested parties. PPIB’s functions include the following:

a)               to negotiate the interconnection agreements and provide support in negotiating power purchase agreements, fuel supply agreements, water use licenses, and other related agreements;

33




b)              to provide guarantees to independent power producers for the performance of government of Pakistan entities;

c)               to prepare, conduct and monitor litigation and international arbitration for, and on behalf of Pakistan for private power projects and proposals; and

d)              to assist NEPRA in determining and approving tariffs for new private power projects.

Panama.   In 1995, Panama initiated the reform of its electricity sector with the passage of legislation allowing private participation in power projects. This was followed in 1996 by the Public Services Regulatory Agency Law, which established new institutional arrangements for the regulation of public services, including electricity. In 1997, the Electricity Law was passed, calling for the restructuring of the Instituto de Recursos Hidráulicos y Electrificación (“IRHE”), the Panamanian government agency responsible for electricity generation, transmission and distribution. IRHE was divided into three distribution companies, four generation companies and one transmission company for privatization.

In 1998, the three distribution companies were privatized, and were each granted 15-year concessions. The same year, the four generation companies were privatized, with the hydropower generators receiving 50-year concessions granting the use of water, and the thermal power generators receiving 40-year licenses. The transmission company remains under state ownership.

The dispatch of the system is the responsibility of the Centro Nacional de Despacho (“CND”), which is part of the transmission company, Ente Regulador de los Servicios Públicos (“ETESA” or the “Regulator”). There is a surcharge levied on revenues in the system to cover the administrative costs of the CND and ETESA, which helps to promote the Regulator’s political independence.

The regulatory framework establishes the operation of generation plants on a merit-order dispatch basis. Dispatch priority is determined based on audited variable operating costs with the last unit dispatched determining the marginal cost of the system. Hydroelectric plants are dispatched in such a way as to optimize the use of water.

The Panamanian electric system operates with both contract and spot markets. At the time of privatization, the distribution companies were assigned PPAs with each of the generators, sufficient to meet the generators’ peak energy demand requirements. The cost of electricity with respect to spot market purchases and PPAs approved by the electric industry regulator (including initial and new contracts) are a direct pass-through to residential and industrial users. The system is designed to preserve the financial health of the distribution companies and the entire electricity sector. Distribution companies are required to contract 100% of their annual energy requirements (although they can self-generate up to 15% of their demand), reducing uncertainty for generators and consumers.

In the recent years, certain changes have been made to this system. The Panama Canal Authority, a government company, is competing in the electricity generation market under different rules that give the Canal Authority advantages over private generators. The Regulator is trying to put caps on electricity prices and the distribution companies are trying to have the 15% cap on generation removed. Tariffs were increased in 2003 and 2004, which prompted the government to subsidize the 2005 tariff increase. Although the government decided to halt these subsidies in 2006, they have recently suspended the scheduled tariff increase for 90 days, while the government reviews a proposed bill to modify the law.

Qatar.   In the State of Qatar there is no regulatory authority. Generation licenses are granted by the State of Qatar.

34




The Government is moving steadily away from the former pattern of electricity supply being seen as the function of a State Ministry. The creation of Qatar Electricity and Water Company (“QEWC”) in 1998 was the first key step in this process. More recently, the former Ministry of Electricity and Water has been transformed into a state owned Corporation called the Qatar General Electricity and Water Corporation (“KAHRAMAA”).

It is envisaged that KAHRAMAA will continue to be responsible for the bulk purchase of power from QEWC and other generators, while also managing the control and dispatch of the national grid and local reticulation systems.

Ukraine.   Restructuring of the Ukrainian electrical energy sector began in 1995. Until that time the electrical energy sector was functioning as a single vertically integrated system operated by the Ministry of Energy and Electrification. In April 1995, the President of Ukraine issued Decree No. 282/95 “On the Restructuring in Electrical Energy Complex of Ukraine,” by which the vertically integrated system was separated into generation, local distribution and high voltage transmission. The local distribution and supply services were placed into 27 regionally defined operating companies (called “oblenergos”). The Ministry of Energy and Electrification remained as a policy agency, and also controlled shares (assets) of state joint stock companies.

In March 1995, the President of Ukraine created the National Regulatory Energy Commission (“NREC”), the main purpose of which was to ensure the effective functioning of the electric energy sector and the formation of an electric energy market.

In 1996, NREC approved the Wholesale Electricity Market (“WEM”) Members Agreement. As a result, transactions for power and energy sales from the generating companies to the supply companies were structured through a wholesale electricity market modeled on the early version of the British power pool.

The Law of Ukraine “On the Energy Sector” adopted in 1997, became the first legislative act regulating electricity generation, transmission, supply and consumption, competition, customers’ rights protection and energy safety. In June 2000, amendments to the Law of Ukraine “On the Energy Sector” were passed, which obligated customers to make cash payments for consumed electricity into special bank accounts. Allocations of funds from the special bank accounts to sector entities are made based on a fund allocation procedure issued by the NREC. By the end of 2004, cash collections had recovered to approximately 97% from 27% in 2000.

In 2002, the Cabinet of Ministers of Ukraine approved the Concept of WEM Development, laying out foundations for further market development in three stages over several years, leading to replacement of the current “single buyer” market model with bilateral contracts between suppliers and generators, and between end-users and generators, as well as a balancing market. In order to improve the overall investment climate, the Concept also addressed power sector problems such as administrative interference in market operations and cash flows, cross-subsidization through retail and wholesale tariff structures, non-payment and debt accumulation. In June 2004, a special commission created by the government approved a plan of measures for the WEM Concept Implementation. The plan set out a list of legislative acts, which have to be drafted or amended, and responsible agencies for that work.

In 2004, the Cabinet of Ministers of Ukraine created the national energy holding company, Energy Company of Ukraine (“ECU”), which holds state owned shares in Ukrainian thermal and hydro generation companies as well as electricity distributors, an export operator and others, with the exception of high voltage and interstate network operator. ECU controls the operational activity of those energy companies, where the government owns controlling shares, the role previously performed by Ministry for Fuel and Energy.

35




At the end of 2005, the Cabinet of Ministers transferred the powers for managing ECU and another state holding company—gas monopolist Naftogas—to the Ministry of Fuel and Energy (MFE) such that the MFE is now in charge of the electricity, nuclear and gas sectors.

In 2005, the NREC approved and implemented a system of uniform electricity tariffs for end users. The uniform tariff mechanism is aimed at the equalization of retail electricity prices for each non-residential customer within the same voltage-class, removing regional price differentiation across all regions of Ukraine. The new end user pricing system does not change the methodology for calculating distribution and supply tariffs. Starting in September 2005, a phased in introduction of uniform tariffs began. The system results in reallocation of part of electricity payments from customers of rural areas to those of industrial areas. Any surplus or deficiency of each distributor’s revenue that results from the uniform tariffs is offset through the wholesale market price adjustment mechanism; thus, the uniform tariff should not affect each distributor’s margin. However, the NREC has put a cap on customer tariff increases and thus, “uniform tariffs” are in reality not yet uniform country wide.

In 2005, the wholesale electricity market price increased approximately 30% due to the increase in the fuel prices in the country and changes in the pricing arrangements for thermal generating companies. Most of this growth took place in the second half of the year, after the presidential elections.

In late 2005, the government indicated it intends to increase electricity tariffs for residential customers. Such tariffs have been fixed since 1999. It is expected that tariffs will be increased some time in 2006 by at least 20% of the current level.

In 2005, a new law came into force introducing a comprehensive set of measures to resolve Ukraine’s energy sector debts problem. The law introduces (a) a set of standardized measures, such as offsets through the supply chain, receivables write-offs with no tax consequences, and payables restructuring guidelines, (b) incentives for implementation thereof and (c) an organizational framework within which implementation of the mechanisms will take place. For AES Ukraine, the new law will allow it to resolve currently existing doubtful receivables through a supply chain offset against the residual restructured payables to the wholesale energy market.

In July 2005, the government issued a special resolution for which government debts to the population resulting from the default of Soviet banks may be offset against debts for purchased electricity. From AES Ukraine’s perspective, this resolution will allow it to offset part of doubtful residential customers’ receivables against its payables to the WEM for purchased power.

United Kingdom.   AES Kilroot in Northern Ireland is subject to the regime established by the LCPD and will therefore be required to comply with the increased restrictions on emissions imposed under that regime. It is also required to obtain a permit under the IPPC Directive to enable it to continue to operate. AES Kilroot will be implementing modifications to ensure that the plant complies with the requirements of the LCPD and the IPPC Directive.

AES Kilroot is subject to regulation by the Northern Ireland Authority for Energy Regulation (“NIAER”). Under the terms of the generating license granted to AES Kilroot, the NIAER has the right to review and, subject to compliance with certain procedural steps and conditions, require the early termination of the long term power purchase agreements under which AES Kilroot currently supplies electricity to Northern Ireland Electricity (“NIE”) in 2010.

36




Venezuela.   The Electric Service Law, enacted on December 31, 2001, contemplates the restructuring of the entire regulatory system for the electric sector in Venezuela by defining separation of activities and the functions of some of the current entities that regulate the sector, introducing new entities and eliminating others that had regulatory authority over the electric sector. The implementation of this new regulatory regime has been gradual. Certain elements of the old regulatory regime will remain, particularly the tariff regime, while the new entities and regulations to be created under the Electric Service Law are being adopted.

On December 14, 2000, the Government issued regulations which provide the mechanism for the implementation of the Electric Service Law and establish the general regulatory framework for Venezuela’s electricity sector relating to, among other things, the free market for generation, the segregation of generation, transmission, distribution and commercialization activities, concessions for existing distribution companies and public auctions for new distribution concessions. The Ministerio de Energia y Petroleo (“MEP”) is the principal regulatory authority of the electric sector in Venezuela. The MEP is responsible for, among other things, coordinating the activities of the government bodies responsible for administering the regulatory system of the electric service, planning the development of the electric sector, granting concessions for distribution and transmission activities and executing the respective contracts and, in conjunction with the Ministerio de Industrias Ligeras y Comercio (“MILCO”), adopting tariff rates for distribution activities. The Electric Service Law also contemplates the creation of the Comisión Nacional de Energía Electrica (“CNEE”) to regulate the electricity sector in Venezuela. The CNEE is expected to be an agency under the MEP with functional, administrative and financial autonomy. Once established, it is expected that the CNEE will gradually take over the functions now being conducted by the Fundación para el Desarrollo del Servicio Eléctrico (“FUNDELEC”). The Electric Service Law also contemplates the creation of a centralized, state-owned company, the Centro Nacional de Gestión del Servicio Eléctrico (“CNGSE”), to administer the dispatch of electricity nation-wide. The CNGSE will replace the functions that have been historically assumed by the electricity companies through the Interconnection Contract and administrated by the Oficina de Planificación del Sistema Interconectado (“OPSIS”). While the CNGSE is being organized, OPSIS will continue to operate and control the dispatch of electricity under the terms of the Interconnection Agreement.

The Electric Service Law introduces a complete revision of the manner in which electric services are to be remunerated. According to the Electric Service Law, distribution and transmission activities will be regulated and their remuneration will be governed by a tariff regime to be implemented by the MEP in conjunction with MILCO. The Electric Service Law provides that, until a new tariff regime is put in place by the MEP, the current tariff regime, set forth in Decree 368 and the 1999 Resolution, will continue to be in effect. These basic tariff rates are subject to semi-annual and monthly adjustments to reflect changes in the inflation and currency exchange rates and the prices of energy and combustible fuels, respectively. However, since price controls were established in the country in 2004, the Government has not permitted EDC to adjust its tariff rates to reflect inflation and devaluation. The adjustment factor to correct fuel and energy prices and quantities is still being implemented monthly.

The failure by the Government in future periods to allow EDC to adjust its tariff rates could have a material adverse effect on its financial condition, results of operations, business prospects and, ultimately, its ability to satisfy its obligations. In addition, the tariff review and setting process in Venezuela is subject to political and regulatory uncertainty. No assurance can be given as to the outcome of such process or to the licensing of activities in the energy sector tariff policy formations, the development of a competitive framework, and customers’ rights protection.

In November 2003, MEP promulgated regulations governing retail activities of distribution companies and their contractual arrangements with customers. Regulations were also promulgated to govern certain technical aspects of the services provided by distribution companies, including signal voltage and frequency and duration of interruptions. These regulations contemplate the gradual implementation by distribution companies of the systems necessary for compliance with the prescribed quality standards and assume the

37




application of appropriate tariff levels to cover the costs of implementing such systems. The service quality regulations seek to provide incentives for distribution companies that come into compliance with the prescribed standards and impose penalties in the event of non-fulfillment. By request of the distribution companies, the MEP has announced the intention to postpone the application of the penalty stage of the quality standards.

Government officers have also announced recently the intention to change the Electric Service Law, and the main changes expected to be proposed are a regulated generation market with competition for expansion projects, making the CNEE more dependent on the central government and changes in the policy toward subsidies for low income customers.

Environmental and Land Use Regulations

Overview.   We have ownership interests in generation and distribution assets in the U.S. and many other countries and we are therefore subject to various international, national, federal, state and local environmental and land use laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharge of effluents into water and the use of water, waste disposal, remediation, noise pollution, contamination at current or former facilities or waste disposal sites, wetlands preservation and endangered species. Each of the countries in which we do business has laws and regulations governing operation of power generation and distribution assets, including laws relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from, such assets. In addition to such laws and regulations, international projects funded by the World Bank are subject to World Bank environmental standards, which tend to be more stringent than local country standards. AES often has used advanced environmental technologies (such as CFB coal technologies or advanced gas turbines) in order to minimize environmental impacts.

Environmental laws and regulations affecting power generation and distribution are complex, change frequently and have tended to become more stringent over time. We have incurred and will continue to incur capital costs and other expenditures in order to comply with environmental laws and regulations, in particular, with respect to the laws and regulations described below. See Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity for more detail. If environmental and land use regulations change in the future, we may be required to make significant capital or other expenditures. There can be no assurance that we would be able to recover from our customers some or all costs to comply with such environmental or land use regulations or that our business, financial conditions or results of operations would not be materially and adversely affected.

Various licenses, permits and approvals are required for our operations. Failure to comply with permits or approvals, or with environmental laws, can result in fines, penalties, or interruptions to our operations. While we have at times been out of compliance with environmental laws and regulations, past non-compliance has not resulted in the revocation of material permits or licenses and has not had a material impact on our operations or results.

Air Emissions.   The U.S. Clean Air Act and various state laws and regulations regulate emissions of major air pollutants, including sulfur dioxide (“SO2”), nitrogen oxides (“NOx”) and particulate matter (“PM”) in the U.S. The Environmental Protection Agency’s (“EPA”) rulemaking requiring adjustments to state implementation plans relating to NOx emissions (the “NOx SIP Call”) resulted in operators of coal-fired electric generating facilities in 21 U.S. states and the District of Columbia either (i) reducing their NOx emissions to levels allocated under the plan or (ii) purchasing NOx emissions allowances from other operators in order to meet allocated emissions levels by May 31, 2004. We are in the process or have completed installing selective catalytic reduction (“SCR”) and other NOx control technologies at three facilities of our subsidiary, Indianapolis Power and Light (“IPL”) in response to NOx SIP Call implementation and other proposed air emissions regulations that are discussed in more detail below.

38




In March 2005, the EPA finalized two rules that will affect many of our U.S. coal-fired power generating plants. The first rule, named the “Clean Air Interstate Rule” (“CAIR”), was promulgated on March 10, 2005 and requires significant reductions of SO2 and NOx emissions from existing power plants located in 28 eastern states and the District of Columbia. The required emission reductions will be in two phases with the first phase beginning in 2009 and 2010 for NOx and SO2, respectively, and a second phase with additional reductions in both air pollutant emissions beginning in 2015. The second rule, called the “Clean Air Mercury Rule,” was issued on March 15, 2005 and requires reductions of mercury emissions from coal-fired power plants in two phases. The first phase will begin in 2010 and will require nationwide reduction of coal-fired power plant mercury emissions from 48 to 38 tons per year. The second phase will begin in 2018 and will require nationwide reduction of mercury emissions from these sources from 38 tons per year to 15 tons per year. The Clean Air Mercury Rule also establishes stringent mercury emission performance standards for new coal-fired power plants. The EPA has granted reconsideration on certain aspects of this rule.

To implement the required emission reductions for these two new rules, the states will establish emission allowance-based NOx, SO2 and mercury emission “cap-and-trade” programs. While the exact impact and cost of these two new rules cannot be established until the states complete the process of assigning emission allowances to our affected facilities, there can be no assurance that our business, financial conditions or results of operations would not be materially and adversely affected by these new rules.

The New York State Department of Environmental Conservation (“NYSDEC”) recently promulgated regulations requiring electric generators to reduce SO2 emissions by 50% below current U.S. Clean Air Act standards. The SO2 regulations began to be phased in beginning on January 1, 2005 with implementation to be completed by January 1, 2008. These regulations also establish stringent NOx reduction requirements year-round, rather than just during the summertime ozone season. As a result, in order to operate our four electric generation facilities located in New York, installation of pollution control technology will likely be required.

In July 1999, the EPA published the “Regional Haze Rule” to reduce haze and protect visibility in designated federal areas. On June 15, 2005, EPA proposed amendments to the Regional Haze Rule that, among other things, set guidelines for determining when to require the installation of “best available retrofit technology” (“BART”) at older plants. The proposed amendment to the Regional Haze Rule would require states to consider the visibility impacts of the haze produced by an individual facility, among other factors, when determining whether that facility must install potentially costly emissions controls. States are required to submit to the EPA their regional haze state implementation plans by December 2007. States that adopt the CAIR cap and trade program for SO2 and NOx are allowed to apply CAIR controls as a substitute for controls required under BART. On June 20, 2005, EPA proposed a rule for an emission trading program under the regional haze program.

Currently, in the United States there are no federal mandatory greenhouse gas emission reduction programs, including carbon dioxide (“CO2”), affecting our electricity power generation facilities. The U.S. Congress has debated a number of proposed greenhouse gas legislative initiatives, but to date there have been no new federal laws in this area. Also, individual states and groups of states are also examining possible greenhouse gas emission reduction programs including the State of California and a group of seven northeastern states under an initiative called the Regional Greenhouse Gas initiative (“RGGI”). Although final legislation or regulations implementing the California and RGGI greenhouse gas emission reduction programs has yet to be enacted, these greenhouse gas-related initiatives may potentially affect AES electric power generation facilities in California, New York, Connecticut and New Jersey. At present, we cannot predict whether compliance with potential future U.S. national, regional and state greenhouse gas emission reduction programs will have a material impact on our operations or results.

39




In Europe we are, and will continue to be, required to reduce air emissions from our facilities to comply with applicable European Community (“EC”) Directives, including Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants (the “LCPD”), which sets emission limit values for NOx, SO2, and particulate matter for large-scale industrial combustion plants for all member states. Until June 2004, existing coal plants could “opt-in” or “opt-out” of the LCPD emissions standards. Those plants that opted out will be required to cease all operations by 2015, and may not operate for more than 20,000 hours after 2008. Those that opt-in, like our AES Kilroot facility in the United Kingdom, must invest in abatement technology to achieve specific SO2 reductions. Generally, AES’s other coal plants in Europe have opted-in but will not require any additional abatement technology to comply with the LCPD.

In July 2003, the EC “Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading” was created, which requires member states to limit emissions of CO2 from large industrial sources within their countries. To do so, member states will be required to implement EC approved national allocation plans (“NAPs”). Under the NAPs, member states will be responsible for allocating limited CO2 allowances within their borders. Directive 2003/87/EC does not dictate how these allocations are to be made and NAPs that have been submitted thus far have varied their allocation methodologies. For these and other reasons, there remain significant uncertainties regarding the application of the European Union Emissions Trading System which commenced operation in January 2005. Based on our current analyses, we expect that certain AES businesses will be under-allocated and others will be over-allocated. At present, we cannot predict whether compliance with the respective NAPs will have a material impact on our operations or results.

On February 16, 2005, the “Kyoto Protocol to the United Nations Framework Convention on Climate Change” (the “Kyoto Protocol”) became effective. The Kyoto Protocol requires countries that have ratified it to substantially reduce their greenhouse gas emissions including CO2. AES has generation operations in six countries that have ratified the Kyoto Protocol. Over the course of the next several years, as decisions surrounding implementation of the Kyoto Protocol become more detailed, we will have a better understanding of the impact of the Kyoto Protocol on the Company. At present, we cannot predict whether compliance with the Kyoto Protocol will have a material impact on our operations or results.

Water Discharges.   Our facilities are subject to a variety of rules governing water discharges. In particular, we are evaluating the impact of the U.S. Clean Water Act Section 316(b) rule regarding cooling water intake. To protect fish and other aquatic organisms, the rule requires existing steam electric generating facilities to utilize the best technology available for cooling water intake structures. We believe that many of our facilities will be affected by this rule. To comply, we must first prepare a Comprehensive Demonstration Study to assess each facility’s effect on the local aquatic environment. Because each facility’s design, location, existing control equipment and results of impact assessments must be taken into consideration, costs will likely vary. The timing of capital expenditures to achieve compliance with this rule will vary from site to site, and may begin as early as 2008 for some of our U.S. plants. At present, however, we cannot predict whether compliance with the 316(b) rule will have a material impact on our operations or results.

Waste Management.   In the course of operations, our facilities generate solid and liquid waste materials requiring eventual disposal. With the exception of coal combustion products (“CCP”), our wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCP, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities include CCP, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl (“PCB”) contaminated liquids and solids. We endeavor to ensure that all our solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations.

40




ITEM 1A.         RISK FACTORS

Investing in our company involves a high degree risk. You should carefully consider the risks described below before deciding to invest in our Company.

The Company’s disclosure controls and procedures and internal control over financial reporting were determined not to be effective as of December 31, 2005 and December 31, 2004, due to the material weaknesses that existed in our internal control over financial reporting. Our disclosure controls and procedures and internal control over financial reporting may not be effective in future periods, as a result of existing or newly identified material weaknesses in internal control over financial reporting.

As required by the federal securities laws, our management periodically performs an evaluation of our disclosure controls and procedures and conducts an assessment of our internal control over financial reporting. “Disclosure controls and procedures” are controls and procedures that are designed to ensure that information required to be disclosed by a company in the reports that it files with the SEC under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the chief executive officer and chief financial officer to allow timely decisions regarding required disclosures. “Internal control over financial reporting” is the process designed by a company’s senior management to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

In performing the assessment at the end of 2005 and 2004, our management identified material weaknesses in our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, that adversely affects a company's ability to initiate, authorize, record, process, or report external financial data reliably in accordance with generally accepted accounting principles such that there is a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. For a discussion of the material weaknesses identified by our management, see Item 9A of this 2005 annual report on Form 10-K.

Due to these material weaknesses, our management concluded that as of December 31, 2005 and December 31, 2004, our Company did not maintain effective control over financial reporting and concluded that our disclosure controls and procedures were ineffective. During our remediation efforts to correct the material weakness that was identified at the end of 2004, errors were discovered in our financial statements which resulted from such material weakness, as well as newly identified material weaknesses. These errors required us to restate our financial statements that were previously filed in our annual report on Form 10-K for the year ended December 31, 2004 and our quarterly report on Form 10-Q for the quarter ended March 31, 2005. To address the material weaknesses, we performed additional analysis and other post-closing procedures in order to prepare our consolidated financial statements in accordance with generally accepted accounting principles. These additional procedures were costly, time consuming and required us to dedicate a significant amount of our resources, including the time and attention of our senior management, toward the correction of these problems. Performing these additional procedures and the need to restate our financial statements also caused us to delay the filing of our quarterly reports for the second and third quarters of 2005 until January 2006, which was well beyond the deadline prescribed by the SEC’s rules to file such reports. In addition, during the 2005 year-end closing process, additional errors were identified that required us to restate our 2004 and 2003 financial results. These corrections are included in the 2005 annual report on Form 10-K. The delays in filing our 2004 Form 10-K/A, and restated quarterly reports, as well as the additional errors identified during the year-end closing process caused the 2005 annual report on Form 10-K to be filed after the SEC deadline for the 2005 annual report on Form 10-K, as well.

As a result of not timely filing the quarterly and annual reports with the SEC, we lost our eligibility to offer and sell our securities pursuant to our shelf registration statement on Form S-3 which could impair

41




our ability to access the capital markets in a timely manner. In addition, the restatements and the delay in the filing of our quarterly and annual reports could have other adverse effects on our business, including, but not limited to:

·       civil litigation or an investigation by the SEC or other regulatory authorities, which could require us to incur significant legal expenses and other costs or to pay damages, fines or other penalties,

·       covenant defaults, and potentially events of default, under our senior secured credit facilities and the indentures governing our outstanding debt securities, resulting from our failure to timely file our financial statements,

·       negative publicity, or

·       the loss or impairment of investor confidence in our Company.

Because of our decentralized structure and the many disparate accounting systems of varying quality and sophistication at our various businesses throughout the world, there is still extensive work remaining to remedy the material weaknesses in internal control over financial reporting. We have developed a remediation plan and have begun implementing this plan, but we expect that this work will extend throughout 2006 and possibly beyond. We cannot assure you as to when the remediation plan will be fully implemented, nor can we assure that additional material weaknesses will not be identified by our management or the auditors in the future. Until our remediation efforts are completed, we will continue to incur the expense and management burdens associated with the additional procedures required to prepare our consolidated financial statements. There will also continue to be an increased risk that we will be unable to timely file future periodic reports with the SEC, that a related default under our senior secured credit facilities and indentures could occur and that our financial statements could contain errors that will be undetected.

Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates. In addition, the effect of new, or changes in, accounting policies and practices and the application of such policies and practices could adversely affect our business.

Our high level of indebtedness, and the security provided for this indebtedness, could adversely affect our business and our ability to fulfill our obligations.

At December 31, 2005, we had approximately $17.7 billion of outstanding indebtedness on a consolidated basis, of which approximately $4.9 billion was recourse debt of The AES Corporation and approximately $12.8 billion was non-recourse debt. All outstanding borrowings under our Senior Secured Credit Facility, our Second Priority Senior Secured Notes and certain other indebtedness are secured by certain of our assets, including the pledge of capital stock of many of our directly held subsidiaries. Most of the debt of our subsidiaries is pledged by substantially all of the assets of those subsidiaries. This level of indebtedness and related security could have important consequences to us and our investors because it could:

·       make it more difficult for us to satisfy our debt service and other obligations,

·       increase our vulnerability to general adverse economic and industry conditions,

42




·       require us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes and grow our business,

·       limit our flexibility in planning for, or reacting to, changes in our business and the industry,

·       place us at a competitive disadvantage to our competitors that are not as highly leveraged, and

·       limit, along with the financial and other restrictive covenants in our and our subsidiaries’ indebtedness, among other things, our ability to borrow additional funds as needed or take advantage of business opportunities as they arise.

The agreements governing our indebtedness and the indebtedness of our subsidiaries limit but do not prohibit us or our subsidiaries from incurring additional indebtedness. To the extent we become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due.

We have significant cash requirements and limited sources of liquidity.

The AES Corporation, which refers to the AES parent company, requires cash primarily to fund:

·       principal repayments of debt,

·       interest and preferred dividends,

·       acquisitions,

·       construction and other project commitments,

·       other equity commitments,

·       taxes, and

·       parent company overhead and development costs.

The AES Corporation’s principal sources of liquidity are:

·       dividends and distributions from its subsidiaries,

·       proceeds from debt and equity financings at the parent company level, and

·       proceeds from asset sales.

For a more detailed discussion of our cash requirements and sources of liquidity, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in this 2005 annual report on Form 10-K.

While we believe that these sources will be adequate to meet our obligations at the parent company level for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital or commercial lending markets, the operating and financial performance of our subsidiaries, exchange rates and the ability of its subsidiaries to pay dividends. Any number of assumptions could prove to be incorrect and therefore we cannot assure you that these sources will be available when needed or that our actual cash requirements will not be greater than expected. In addition, our cash flow may not be sufficient to repay at maturity all of the principal outstanding under our senior secured credit facilities and our debt securities and we may have to refinance such obligations. We cannot assure you that we will be successful in obtaining such refinancings.

43




Existing and potential future defaults by project subsidiaries could adversely affect our results of operations and financial condition.

We attempt to finance our domestic and foreign projects primarily under loan agreements and related documents which, except as noted below, require the loans to be repaid solely from the project’s revenues and provide that the repayment of the loans (and interest thereon) is secured solely by the capital stock, physical assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as non-recourse debt or “project financing.” In some project financings, The AES Corporation has explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take the form of guarantees, indemnities, letter of credit reimbursement agreements, and agreements to pay, in certain circumstances, the project lenders or other parties. To the extent The AES Corporation becomes liable under such guarantees and other arrangements, distributions received by The AES Corporation from other projects are subject to the possibility of being utilized by The AES Corporation to satisfy these obligations.

At December 31, 2005, we had approximately $4.9 billon of recourse debt and approximately $12.8 billion of non-recourse debt outstanding. At December 31, 2005, The AES Corporation had provided outstanding financial and performance related guarantees or other credit support commitments to or for the benefit of its subsidiaries, which were limited by the terms of the agreements, to an aggregate of approximately $507 million (excluding those collateralized by letter-of-credit obligations discussed below). The AES Corporation also is obligated under other commitments, which are limited to amounts, or percentages of amounts, received by The AES Corporation as distributions from its project subsidiaries. In addition, The AES Corporation has commitments to fund its equity in projects currently under development or in construction. At December 31, 2005, The AES Corporation also had $294 million in letters of credit outstanding and $1 million in surety bonds outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations.

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in our consolidated balance sheets related to such defaults was $138 million at December 31, 2005.

While the lenders under our non-recourse project financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults thereunder can still have important consequences for The AES Corporation’s results of operations and liquidity, including, without limitation:

·       reducing The AES Corporation’s cash flows since the project subsidiary will typically be prohibited from distributing cash to The AES Corporation during the pendancy of any default,

·       triggering The AES Corporation’s obligation to make payments under any financial guarantee, letter of credit or other credit support which The AES Corporation has provided to or on behalf of such subsidiary,

·       causing The AES Corporation to record a loss in the event the lender forecloses on the assets, or

·       triggering defaults in The AES Corporation’s outstanding debt and trust preferred instruments. For example, The AES Corporation’s senior secured credit facilities and outstanding senior notes and junior subordinated notes include events of default for certain bankruptcy related events involving material subsidiaries. In addition, The AES Corporation’s senior secured credit facilities include events of default relating to accelerations of outstanding debt of material subsidiaries.

None of the projects that are currently in default are owned by subsidiaries that meet the applicable definition of materiality in The AES Corporation’s senior secured credit facilities in order for such defaults to trigger an event of default or permit an acceleration under such indebtedness. However, as a result of

44




future write down of assets, dispositions and other matters that affect our financial position and results of operations, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration of such subsidiary’s debt, trigger an event of default and possible acceleration of the indebtedness under The AES Corporation’s senior secured credit facilities.

Our competitive supply and Latin American operations represent a substantial portion of our assets and have caused and are expected to continue to cause significant volatility in our results of operations and cash flows.

The competitive supply segment of our business and our Latin American operations each experience volatility in revenues and earnings and has had and is expected to continue to cause significant volatility on our results of operations and cash flows. The competitive supply segment’s volatility has resulted from volatile electricity prices, which are influenced by peak demand requirements, weather conditions, competition, market regulation, interest rate and foreign exchange rate fluctuations, electricity transmission and environmental emission constraints, the availability or prices of emission credits and fuel prices, as well as plant availability and other relevant factors. Our Latin American operations have experienced significant volatility because of regulatory and economic difficulties, political instability and currency devaluations being experienced in many of these countries.

We do a significant amount of our business outside the United States which presents significant risks.

During 2005, approximately 79% of our revenue was generated outside the United States and a significant portion of our international operations is conducted in developing countries. Part of our growth strategy is to expand our business in developing countries because the growth rates and the opportunity to implement operating improvements and achieve higher operating margins may be greater than those typically achievable in more developed countries. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:

·       economic, social and political instability in any particular country or region,

·       adverse changes in currency exchange rates,

·       government restrictions on converting currencies or repatriating funds,

·       unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies,

·       high inflation and monetary fluctuations,

·       restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate,

·       expropriation of our assets by foreign governments,

·       difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with U.S. GAAP expertise,

·       unwillingness of governments, government agencies or similar organizations to honor their contracts,

·       inability to obtain access to fair and equitable political, regulatory, administrative and legal systems,

·       difficulties in enforcing our contractual rights or enforcing judgments or obtaining a just result in local jurisdictions, and

·       potentially adverse tax consequences of operating in multiple jurisdictions.

45




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

Furthermore, the ability to obtain financing on a commercially acceptable non-recourse basis in developing nations is difficult. Even when such non-recourse financing is available, lenders may require us to make higher equity investments or provide greater credit support than historically have been the case. In addition, financing in countries with less than investment grade sovereign credit ratings may also require substantial participation by multilateral financing agencies. There can be no assurance that such financing can be obtained when needed.

Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates.

We operate in many foreign environments and such investment in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. Our exposure to currency exchange rate fluctuations results primarily from the translation exposure associated with the preparation of our consolidated financial statements, as well as from transaction exposure associated with generating revenues and incurring expenses in different currencies. While our consolidated financial statements are reported in U.S. dollars, the financial statements of many of our subsidiaries outside the United States are prepared using the local currency as the functional currency and translated into U.S. dollars by applying an appropriate exchange rate. As a result, fluctuations in the exchange rate of the U.S. dollar relative to the local currencies in which our subsidiaries outside the United States report could cause significant fluctuations in our results. In addition, while our expenses with respect to foreign operations are generally denominated in the same currency as corresponding sales, we have transaction exposure to the extent our receipts and expenditures, including debt service expenditures, are not offsetting in any currency. Moreover, the costs of doing business abroad may increase as a result of adverse exchange rate fluctuations. Our financial position and results of operations have been significantly affected by fluctuations in the value of the Argentine peso, Brazilian real, the Dominican Republic peso, the Pakistani rupee and the Venezuelan bolivar relative to the U.S. dollar. Depreciation of the Argentine peso and Brazilian real has resulted in foreign currency translation and transaction losses, while the appreciation of those currencies has resulted in gains. Conversely, depreciation of the Venezuelan bolivar has resulted in foreign currency gains and appreciation has resulted in losses.

Our business is subject to substantial development uncertainties.

Certain of our subsidiaries and affiliates are in various stages of developing and constructing greenfield power plants, some but not all of which have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion depends upon overcoming substantial risks, including, but not limited to, risks relating to failures of siting, financing, construction, permitting, governmental approvals or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. We believe that capitalized costs for projects under development are recoverable; however, we cannot assure you that any individual project will be completed and reach commercial operation. If these development efforts are not successful, we may abandon a project under development. At the time of abandonment, we would expense all capitalized development costs incurred in connection therewith and could incur additional losses associated with any related contingent liabilities.

Our acquisitions may not perform as expected.

Historically, we have achieved a majority of our growth through acquisitions. We plan to continue to grow our business through acquisitions. Although acquired businesses may have significant operating histories at the time we acquired them, we will have a limited or no history of owning and operating many of these businesses and possibly limited or no experience operating in the country or region where these businesses are located. Some of these businesses may be government owned and some may be operated as

46




part of a larger integrated utility prior to their acquisition. If we were to acquire any of these types of businesses, we cannot assure you that:

·       we will be successful in transitioning them to private ownership,

·       such businesses will perform as expected,

·       we will not incur unforeseen obligations or liabilities,

·       such business will generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them, or

·       the rate of return from such businesses will justify our decision to invest our capital to acquire them.

Acquisitions have placed, and in the future may place, a strain on our internal accounting and managerial controls. In addition, our acquisitions outside the United States have required, and will require, us to hire personnel with sufficient expertise in U.S. GAAP to timely and accurately comply with our reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse affect on our ability to report our financial condition and results of operations.

Most of our contract generation businesses are dependent to a large degree on one or a limited number of customers and a limited number of fuel suppliers.

Most of our contract generation businesses rely on power sales contracts with one or a limited number of customers for the majority of, and in some case all of, the relevant plant’s output and revenues over the term of the power sales contract. The remaining term of the power sales contracts related to our contract generation power plants ranges from 1 to 25 years. Many of these businesses also limit their exposure to fluctuations in fuel prices by entering into long term contracts for fuel with a limited number of suppliers. The cash flows and results of operations of such businesses are dependent on the continued ability of their customers and suppliers to meet their obligations under the relevant power sales contract or fuel supply contract, respectively. Some of contract generation businesses’ long-term power sales agreements are for prices above current spot market prices. The loss of one or more significant power sales contracts or fuel supply contracts, or the failure by any of the parties to such contracts to fulfill its obligations thereunder, could have a material adverse impact on our business, results of operations and financial condition.

We have sought to reduce this counter-party credit risk for our contract generation businesses in part by entering into power sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from the sovereign government of the customer’s obligations. However, many of our contract generation businesses’ customers do not have, or have failed to maintain, an investment grade credit rating, and our generation businesses can not always obtain government guarantees and if they do, the government does not always have an investment grade credit rating. We have also sought to reduce our credit risk by locating our plants in different geographic areas in order to mitigate the effects of regional economic downturns. However, we cannot assure you that our efforts to mitigate this risk will be successful.

Competition is increasing and could adversely affect us.

The power production markets in which we operate are characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental or operating experience (including both domestic and international experience) and financial resources similar to or greater than ours. Further, in recent years, the power production industry has been characterized by strong and increasing competition with respect to both obtaining power sales agreements and acquiring existing power generation assets. In certain markets, these factors have caused reductions in prices contained in new power sales agreements and, in many cases, have caused higher acquisition prices for existing assets

47




through competitive bidding practices. The evolution of competitive electricity markets and the development of highly efficient gas-fired power plants have also caused, or are anticipated to cause, price pressure in certain power markets where we sell or intend to sell power. There can be no assurance that the foregoing competitive factors will not have a material adverse effect on us.

Our distribution businesses are highly regulated.

Our distribution businesses face increased regulatory and political scrutiny in the normal conduct of their operations. This scrutiny may adversely impact our results of operations to the extent that such scrutiny or pressure prevents us from reducing losses as quickly as we planned or denies us a rate increase called for by our concession agreements. In general, our distribution businesses have lower margins and are more dependent on regulation to ensure expected annual rate increases for inflation, capital expenditures and increased fuel and power costs, among other things. There can be no assurance that these rate reviews will be granted, or occur in a timely manner.

Our ability to raise capital on favorable terms, to refinance existing corporate or subsidiary indebtedness or to fund operations, capital expenditures, future acquisitions, construction of greenfield projects could adversely affect our results of operations.

Our ability to arrange for financing on either a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including

·       general economic and capital market conditions,

·       the availability of bank credit,

·       investor confidence,

·       the financial condition, performance, prospects and credit rating of our company in general and/or that of our subsidiary requiring the financing, and

·       changes in tax and securities laws which are conducive to raising capital.

Should future access to capital not be available, we may have to sell assets or decide not to build new plants or acquire existing facilities. While a decision not to build new plants or acquire existing facilities would not affect the results of operations of our currently operating facilities or facilities under construction, such a decision would affect our future growth.

Our business and results of operations could be adversely affected by changes in our operating performance or cost structure.

We are in the business of generating and distributing electricity, which involves certain risks that can adversely affect financial and operating performance, including:

·       changes in the availability of our generation facilities or distribution systems due to increases in scheduled and unscheduled plant outages, equipment failure, labor disputes, disruptions in fuel supply, inability to comply with regulatory or permit requirements or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, explosions, terrorist acts or other similar occurrences; and

·       changes in our operating cost structure, including, but not limited to, increases in costs relating to: gas, coal, oil and other fuel; fuel transportation; purchased electricity; operations, maintenance and repair; environmental compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental emission equipment; transmission access; and insurance.

Any of the above risks could adversely affect our business and results of operations, and our ability to meet our publicly announced projections or analysts expectations.

48




We are subject to significant government regulation and our business and results of operations could be adversely affected by changes in the law or regulatory schemes.

We operate a portfolio of electricity generation and distribution businesses in 25 countries and, therefore, we are subject to significant and diverse government regulation. Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including our inability to obtain expected or contracted increases in electricity tariff rates or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet our publicly announced projections or analyst’s expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our regulated utilities where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:

·       changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs,

·       changes in the definition or determination of controllable or non-controllable costs,

·       changes in the definition of events which may or may not qualify as changes in economic equilibrium,

·       changes in the timing of tariff increases, or

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

Our businesses, particularly our businesses in our competitive supply segment, may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets.

Our generation businesses, especially our businesses in the competitive supply segment, sell electricity in the wholesale spot markets. Our regulated utility businesses, and to the extent they require additional capacity our generations businesses, also buy electricity in the wholesale spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. The open market wholesale prices for electricity are very volatile and often reflect the fluctuating cost of coal, natural gas, or oil. Consequently, any changes in the supply and cost of coal, natural gas, and oil may impact the open market wholesale price of electricity.

A significant percentage of our generation facilities, particularly the facilities in our competitive supply segment, operate wholly or partially without long-term power sales agreements. As a result, power from these facilities is sold on the spot market or on a short-term contractual basis, which if not fully hedged may affect the volatility of our financial results. In addition, our business depends upon transmission facilities owned and operated by others; if transmission is disrupted or capacity is inadequate or unavailable, our ability to sell and deliver our wholesale power may be limited.

Volatility in market prices for fuel and electricity may result from among other things:

·       weather conditions,

·       seasonality,

·       electricity usage,

·       illiquid markets,

·       transmission or transportation constraints or inefficiencies,

·       availability of competitively priced alternative energy sources,

49




·       demand for energy commodities,

·       available supplies of natural gas, crude oil and refined products, and coal,

·       generating unit performance,

·       natural disasters, terrorism, wars, embargoes and other catastrophic events,

·       federal and state energy and environmental regulation, legislation and policies,

·       geopolitical concerns affecting global supply of oil and natural gas, and

·       general economic conditions in areas where we generate which impact energy consumption.

We are a holding company and our ability to make payments on our outstanding indebtedness at the parent company level is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans, or otherwise.

The AES Corporation is a holding company with no material assets, other than the stock of its subsidiaries. All of our revenue generating operations are conducted through our subsidiaries. Accordingly, almost all of our cash flow is generated by the operating activities of our subsidiaries. Our subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of our indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to our debt or to make any funds available therefore, whether by dividends, fees, loans or other payments. While some of our subsidiaries guarantee our indebtedness under our senior secured credit facility and certain other indebtedness, none of our subsidiaries guarantee, or is otherwise obligated with respect to, our outstanding public debt securities. Accordingly, our ability to make payments on our indebtedness and to fund our other obligations at the parent company level is dependent not only on the ability of our subsidiaries to generate cash, but also on the ability of our subsidiaries to distribute cash to us in the form of dividends, fees, interest, loans or otherwise. Most of our subsidiaries are obligated, pursuant to loan agreements, indentures or project financing arrangements, to satisfy certain restricted payment covenants or other conditions before they may make distributions to us. In addition, the payment of dividends or the making of loans, advances or other payments to us may be subject to legal or regulatory restrictions. Our subsidiaries in foreign countries may also be prevented from distributing funds to us as a result of restrictions imposed by the foreign government on repatriating funds or converting currencies. Any right we have to receive any assets of any of our subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of our indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary’s creditors (including trade creditors and holders of debt issued by such subsidiary).

We may not be able to raise sufficient capital to fund greenfield projects in certain less developed economies.

Commercial lending institutions sometimes refuse to provide non-recourse project financing (including financial guarantees) in certain less developed economies, thus we have sought and will continue to seek, in such locations, direct or indirect (through credit support or guarantees) project financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such project financing available, these institutions may also require governmental guarantees of certain project and sovereign related risks. Depending on the policies of specific governments, such guarantees may not be offered and as a result, we may determine that sufficient financing will ultimately not be available to fund the related project. In addition, we are frequently required to provide more sponsor equity for projects that sell their electricity into the merchant market than for projects that sell their electricity under long term contracts.

50




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

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

Furthermore, as a result of The AES Corporation’s credit ratings and the trading prices of its equity and debt securities, counter parties may no longer be as willing to accept general unsecured commitments by The AES Corporation to provide credit support. Accordingly, with respect to both new and existing commitments, The AES Corporation may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace any credit support by The AES Corporation. We cannot provide assurance that such counter parties will accept such guarantees in the future. In addition, to the extent The AES Corporation is required and able to provide letters of credit or other collateral to such counterparties, it will limit the amount of credit available to The AES Corporation to meet its other liquidity needs.

Our generation business in the United States is subject to the provisions of various laws and regulations administered in whole or in part by the FERC, including the Public Utility Regulatory Policies Act of 1978(“PURPA”) and the Federal Power Act. The recently enacted Energy Policy Act of 2005 (“EPAct 2005”) made a number of changes to these and other laws that may affect our business. Actions by the FERC and by state utility commissions can have a material effect on our operations.

EPAct 2005 authorizes the FERC to remove the obligation of electric utilities under Section 210 of PURPA to enter into new contracts for the purchase or sale of electricity from or to ‘Qualified Facilities’ (“QFs”) if certain market conditions are met. Pursuant to this authority the FERC has recently proposed to remove the purchase/sale obligation for all utilities located within the control areas of the Midwest Transmission System Operator, Inc., PJM Interconnection, L.L.C., ISO New England, Inc. and the New York Independent System Operator. In addition, the FERC is authorized under the new law to remove the purchase/sale obligations of individual utilities on a case-by-case basis. While the new law does not affect existing contracts, as a result of the changes to PURPA our QFs may face a more difficult market environment when their current long-term contracts expire.

EPAct 2005 repealed PUHCA of 1935 and enacted PUHCA of 2005 in its place. PUHCA 1935 had the effect of requiring utility holding companies to operate in geographically proximate regions and therefore limited the range of potential combinations and mergers among utilities. By comparison PUHCA 2005 has no such restrictions and simply provides the FERC and state utility commissions with enhanced access to the books and records of certain utility holding companies. The repeal of PUHCA 1935 may spur an increased number of mergers and the creation of large, geographically dispersed utility holding companies. These entities may have enhanced financial strength and therefore an increased ability to compete with us in the U.S. generation market.

In accordance with Congressional mandates in the Energy Policy Act of 1992 and now in EPAct 2005, the FERC has strongly encouraged competition in wholesale electric markets. Increased competition may have the effect of lowering our operating margins. Among other steps, the FERC has encouraged regional transmission organizations and independent system operators to develop demand response bidding programs as a mechanism for responding to peak electric demand. These programs may reduce the value of our peaking assets which rely on very high prices during a relatively small number of hours to recover their costs. Similarly, the FERC is encouraging the construction of new transmission infrastructure in accordance with provisions of EPAct 2005. Although new transmission lines may increase our market opportunities, they may also increase the competition in our existing markets.

While the FERC continues to promote competition, some state utility commissions have reversed course and begun to encourage the construction of generation facilities by traditional utilities to be paid

51




for on a cost-of-service basis by retail ratepayers. Such actions have the effect of reducing sale opportunities in the competitive wholesale generating markets in which we operate.

Finally, EPAct 2005 affects nearly every aspect of the energy business and energy regulation. We are still in the process of analyzing the new law’s effects, and those effects could have a material adverse effect on our business.

We are subject to material litigation and regulatory proceedings.

We and our affiliates are parties to material litigation and regulatory proceedings. Investors should review the descriptions of such matters contained in this annual report, as well as our other periodic reports we file in the future with the Commission. There can be no assurances that the outcome of such matters will not have a material adverse effect on our consolidated financial position.

Our business is subject to stringent environmental laws and regulations.

Our activities are subject to stringent environmental laws and regulation by federal, state, local authorities, international treaties and foreign governmental authorities. These regulations generally involve emissions into the air, effluents into the water, use of water, wetlands preservation, waste disposal, endangered species, and noise regulation, among others. Failure to comply with such laws and regulations or to obtain any necessary environmental permits pursuant to such laws and regulations could result in fines or other sanctions. Environmental laws and regulations affecting power generation and distribution are complex and have tended to become more stringent over time. Congress and other domestic and foreign governmental authorities have either considered or implemented various laws and regulations to restrict or tax certain emissions, particularly those involving air and water emissions. See the various descriptions of these laws and regulations contained in this annual report on Form 10-K under the caption “Regulation Matters—Environmental and Land Use Regulations.”  These laws and regulations have imposed, and proposed laws and regulations could impose in the future, additional costs on the operation of our power plants. We have made and will continue to make significant capital and other expenditures to comply with these and other environmental laws and regulations. Changes in, or new, environmental restrictions may force us to incur significant expenses or exceed our estimates. There can be no assurance that we would be able to recover all or any increased environmental costs from our customers or that our business, financial condition or results of operations would not be materially and adversely affected by such expenditures or any changes in domestic or foreign environmental laws and regulations.

Catastrophic events could adversely affect our facilities and operations.

Catastrophic events such as fires, explosions, terrorist acts or natural disasters such as floods or tornadoes, or other similar occurrences could adversely affect our facilities, operations, earnings and cash flow.

Our business is sensitive to variations in weather and seasonal variations.

The energy business is affected by variations in general weather conditions and unusually severe weather. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather (such as warmer winters and cooler summers) where our business are located could have a material impact on our results of operations. Storms that interrupt our services to our customers have in the past required us, and in the future may require us, to incur significant costs to restore services.

52




Some of our subsidiaries participate in defined benefit pension plans and their net pension plan obligations may require additional significant contributions.

Certain of our subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Of the thirteen defined benefit plans, two are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries. Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. Our subsidiaries who participate in these plans are responsible for funding any shortfall of pension plan assets compared to pension obligations under the pension plan. Future downturns in the equity markets, or the failure of any of our assumptions underlying the estimates of our subsidiaries’ pension plan obligations to prove correct, could increase the underfunding of the pension plan. This may necessitate additional cash contributions to the pension plans that could adversely affect our and our subsidiaries’ liquidity.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Pension and Postretirement Obligations” and footnote 12 to our consolidated financial statements included in this annual report on Form 10-K.

The operation of power generation facilities involves significant risks that could adversely affect our financial results.

The operation of power generation facilities involves many risks, including:

·       equipment failure causing unplanned outages,

·       failure of transmission systems,

·       the dependence on a specified fuel source, including the transportation of fuel, or

·       the impact of unusual or adverse weather conditions (including natural disasters such as hurricanes) or

·       environmental compliance

Any of these risks could have an adverse effect on our generation facilities. A portion of our generation facilities were constructed many years ago. Older generating equipment may require significant capital expenditures to keep it operating at peak efficiency. This equipment is also likely to require periodic upgrading and improvement. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of the agreement or incurring a liability for liquidated damages.

We may not fully hedge our exposure against changes in commodity prices.

To lower our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity, fuel requirements and other commodities. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, we may not cover the entire exposure of our assets or positions to market price volatility, and the coverage will vary over time. Fluctuating commodity prices may negatively impact our financial results to the extent we have unhedged positions.

53




ITEM 1B.         UNRESOLVED STAFF COMMENTS

None.

ITEM 2.                 PROPERTIES

We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-term leases, none of which are material. With a few exceptions, our facilities, which are described in Item 1 of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project’s related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.

ITEM 3.                 LEGAL PROCEEDINGS

The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is possible, however, that some matters could be decided unfavorably to the Company, and could require the Company to pay damages or to make expenditures in amounts that could have a material adverse effect on the Company’s financial position and results of operations.

In September 1999, a Brazilian appellate state court of Minas Gerais granted a temporary injunction suspending the effectiveness of a shareholders’ agreement between Southern Electric Brasil Participacoes, Ltda. (“SEB”) and the state of Minas Gerais concerning CEMIG. AES’ investment in CEMIG is through SEB. This shareholders’ agreement granted SEB certain rights and powers in respect of CEMIG (“Special Rights”). In March 2000, a lower state court in Minas Gerais held the shareholders’ agreement invalid where it purported to grant SEB the Special Rights and the lower state court enjoined the exercise of Special Rights. In August 2001, the state appellate court denied an appeal of the merits decision, and extended the injunction. In October 2001, SEB filed two appeals against the decision on the merits of the state appellate court, one appeal to the Federal Superior Court and the other appeal to the Supreme Court of Justice. The state appellate court denied access of these two appeals to the higher courts, and in August 2002, SEB filed two interlocutory appeals against such decision, one directed to the Federal Superior Court and the other to the Supreme Court of Justice. In December 2004, the Federal Superior Court declined to hear SEB’s appeal. However, the Supreme Court of Justice is considering whether to hear SEB’s appeal. SEB intends to vigorously pursue a restoration of the value of its investment in CEMIG by all legal means; however, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit SEB’s influence on the daily operation of CEMIG.

In November 2000, the Company was named in a purported class action suit along with six other defendants, alleging unlawful manipulation of the California wholesale electricity market, allegedly resulting in inflated wholesale electricity prices throughout California. The alleged causes of action include violation of the Cartwright Act, the California Unfair Trade Practices Act and the California Consumers Legal Remedies Act. In December 2000, the case was removed from the San Diego County Superior Court to the U.S. District Court for the Southern District of California. On July 30, 2001, the Court remanded the case to San Diego Superior Court. The case was consolidated with five other lawsuits alleging similar claims against other defendants. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which reasserted the claims raised in the earlier action and names the Company,

54




AES Redondo Beach, LLC, AES Alamitos, LLC, and AES Huntington Beach, LLC as defendants. In May 2002, the case was removed by certain cross-defendants from the San Diego County Superior Court to the United States District Court for the Southern District of California. The plaintiffs filed a motion to remand the case to state court, which was granted on December 13, 2002. Certain defendants appealed aspects of that decision to the United States Court of Appeals for the Ninth Circuit. On December 8, 2004, a panel of the Ninth Circuit issued an opinion affirming in part and reversing in part the decision of the District Court, and remanding the case to state court. On July 8, 2005, defendants filed a demurrer in state court seeking dismissal of the case in its entirety. On October 3, 2005, the court sustained the demurrer and entered an order of dismissal. On December 2, 2005, plaintiffs filed a notice of appeal. The Company believes that it has meritorious defenses to any actions asserted against it and will defend itself vigorously against the allegations.

In August 2000, the Federal Energy Regulatory Commission (“FERC”) announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. The FERC requested documents from each of the AES Southland plants and AES Placerita. AES Southland and AES Placerita have cooperated fully with the FERC investigation. AES Southland is not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. AES Placerita is currently subject to refund liability of $586,000 for sales to the California Power Exchange. The Ninth Circuit Court of Appeals addressed the appeal of the FERC’s decision not to impose refunds for the alleged failure to file rates including transaction specific data for sales during 2000 and 2001. Although in its order issued on September 9, 2004 the Ninth Circuit did not order refunds, the Ninth Circuit remanded the case to the FERC for a refund proceeding to consider remedial options. That remand order is stayed pending rehearing at the Ninth Circuit. In addition, in a separate case, the Ninth Circuit heard oral arguments on the time and scope of the refunds. Placerita made sales during the time period at issue in the appeals. Depending on the result of the appeals, the method of calculating refunds and the time period to which the method is applied, the alleged refunds sought from AES Placerita could approximate $23 million.

In August 2001, the Grid Corporation of Orissa, India (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to, and approved by, the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the

55




“CESCO arbitration”). In the arbitration, Gridco appears to seek approximately $188.5 million in damages plus undisclosed penalties and interest, but a detailed alleged damages analysis has yet to be filed by Gridco. The Company has counter-claimed against Gridco for damages. An arbitration hearing with respect to liability was conducted on August 3-9, 2005 in India. Final written arguments regarding liability were submitted by the parties to the arbitral tribunal in late October 2005. A decision on liability may be issued in the near future. A petition remains pending before the Indian Supreme Court concerning fees of the third neutral arbitrator and the venue of future hearings with respect to the CESCO arbitration. The Company believes that it has meritorious defenses to any actions asserted against it and will defend itself vigorously against the allegations.

In December 2001, a petition was filed by Gridco in the local India courts seeking an injunction to prohibit the Company and its subsidiaries from selling their shares in Orissa Power Generation Company Pvt. Ltd. (“OPGC”), an affiliate of the Company, pending the outcome of the above-mentioned CESCO arbitration. OPGC, located in Orissa, is a 420 MW coal-based electricity generation business from which Gridco is the sole off-taker of electricity. Gridco obtained a temporary injunction, but the District Court eventually dismissed Gridco’s petition for an injunction in March 2002. Gridco appealed to the Orissa High Court, which in January 2005 allowed the appeal and granted the injunction. The Company has appealed the High Court’s decision to the Supreme Court of India. In May 2005, the Supreme Court adjourned this matter until August 2005. In August 2005, the Supreme Court adjourned the matter again to await the award of the arbitral tribunal in the CESCO arbitration. The Company believes that it has meritorious defenses to any actions asserted against it and will defend itself vigorously against the allegations.

In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing power purchase agreement (“PPA”) with Gridco. In response, OPGC filed a petition in the India courts to block any such OERC proceedings. In early 2005 the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPA terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financials. The Company believes that it has meritorious defenses to any actions asserted against it and will defend itself vigorously against the allegations.

In July 2002, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana. In September 2002, two virtually identical complaints were filed against the same defendants in the same court. All three lawsuits purported to be filed on behalf of a class of all persons who exchanged their shares of IPALCO Enterprises, Inc. (“IPALCO”) common stock for shares of AES common stock issued pursuant to a registration statement dated and filed with the Securities and Exchange Commission on August 16, 2000. The complaints purported to allege violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 based on statements in or omissions from the registration statement concerning certain secured equity-linked loans by AES subsidiaries, the supposedly volatile nature of AES stock, as well as AES’ allegedly unhedged operations in the United Kingdom at that time, and the alleged effect of the New Electrical Trading Agreements on AES’ United Kingdom operations. On April 14, 2003, lead plaintiffs filed an amended and consolidated complaint, which added former IPALCO directors and officers John R. Hodowal, Ramon L. Humke and John R. Brehm as defendants and, in addition to the purported claims in the original complaints, purported to allege against the newly added defendants violations of Sections 10(b) and 14(a) of the Securities Exchange Act of 1934 and Rules 10b-5 and 14a-9

56




promulgated thereunder. The amended complaint also purported to add a claim based on alleged misstatements or omissions concerning an alleged breach by AES of alleged obligations AES owed to Williams Energy Services Co. (“Williams”) under an agreement between the two companies in connection with the California energy market. On September 26, 2003, defendants filed a motion to dismiss the amended and consolidated complaint. By Order dated November 17, 2004, the Court dismissed all of the claims asserted in the amended and consolidated complaint against all defendants except for the claim alleging that the registration statement and prospectus disseminated to the IPALCO stockholders for purposes of the share exchange transaction failed to disclose AES’ purported temporary default on its contract with Williams. On December 15, 2004, the AES defendants filed a motion for judgment on the pleadings to dismiss the remaining claims. On July 7, 2005, the district court granted defendants’ motion for judgment on the pleadings and entered an order dismissing all claims and thereby terminating this action in the district court. The time to file an appeal to the action has expired without the filing of an appeal.

In April 2002, IPALCO and certain former officers and directors of IPALCO were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana. On May 28, 2002, an amended complaint was filed in the lawsuit. The amended complaint asserts that IPALCO and former members of the pension committee for the Indianapolis Power & Light Company thrift plan breached their fiduciary duties to the plaintiffs under the Employees Retirement Income Security Act by investing assets of the thrift plan in the common stock of IPALCO prior to the acquisition of IPALCO by the Company. In December 2002, plaintiffs moved to certify this case as a class action. The Court granted the motion for class certification on September 30, 2003. On October 31, 2003, the parties filed cross-motions for summary judgment on liability. On August 11, 2005, the Court issued an Order denying the summary judgment motions, but striking one defense asserted by defendants. A trial addressing only the allegations of breach of fiduciary duty began on February 21, 2006 and concluded on February 28, 2006. Post trial briefs are due by April 6, 2006, and responses are due by April 20, 2006. A decision will follow sometime thereafter. If the Court rules against the IPALCO defendants, one or more trials on reliance, damages, and other issues will be conducted separately. IPALCO believes it has meritorious defenses to the claims asserted against it and intends to defend this lawsuit vigorously.

In November 2002, Stone & Webster, Inc. (“S&W”) filed a lawsuit against AES Wolf Hollow, L.P. (“AESWH”) and AES Frontier, L.P. (“AESF,” and, collectively with AESWH, “sub-subsidiaries”) in the District Court of Hood County, Texas. At the time of filing, AESWH and AESF were two indirect subsidiaries of the Company, but in December 2004, the Company finalized agreements to transfer the ownership of AESWH and AESF. S&W contracted with AESWH and AESF in March 2002 to perform the engineering, procurement and construction of the Wolf Hollow project, a gas-fired combined cycle power plant in Hood County, Texas. In its initial complaint, filed in November 2002, S&W requested a declaratory judgment that a fire that took place at the project on June 16, 2002 constituted a force majeure event, and that S&W was not required to pay rebates assessed for associated delays. As part of the initial complaint, S&W also sought to enjoin AESWH and AESF from drawing down on letters of credit provided by S&W. The Court refused to issue the injunction, and the sub-subsidiaries drew down on the letters of credit and withheld milestone payments from S&W. S&W has since amended its complaint five times and joined additional parties, including the Company and Parsons Energy & Chemicals Group, Inc. In addition to the claims already mentioned, the current claims by S&W include claims for breach of contract, breach of warranty, wrongful liquidated damages, foreclosure of lien, fraud and negligent misrepresentation. S&W appears to assert damages against the sub-subsidiaries and the Company in the amount of $114 million in recently filed expert reports and seeks exemplary damages. S&W filed a lien against the ownership interests of AESWH and AESF in the property, with each lien allegedly valued, after amendment on March 14, 2005, at approximately $87 million. In January 2004, the Company filed a counterclaim against S&W and its parent, the Shaw Group, Inc. (“Shaw”). AESWH and AESF filed

57




answers and counterclaims against S&W, which since have been amended. The amount of AESWH and AESF’s counterclaims are approximately $215 million, according to calculations of the sub-subsidiaries and of an expert retained in connection with the litigation, minus the Contract balance, not earned as of December 31, 2005, to the knowledge or the Company, in the amount of $45.8 million. In March 2004, S&W and Shaw each filed an answer to the counterclaims. The counterclaims and answers subsequently were amended. In March 2005, the Court rescheduled the trial date for October 24, 2005. In September 2005, the trial date was re-scheduled for June 2006. In November 2005, the Company filed a motion for summary judgment to dismiss the claims asserted against it by S&W. On February 21, 2006 the Court issued a letter ruling granting the Company’s motion for summary judgment and directing the Company to submit a proposed order. On February 22, 2006 the Company submitted a proposed order, which has been objected to by S&W and Shaw. On March 15, 2006, S&W moved to reconsider the Court’s decision granting the Company’s summary judgment motion. A decision on the proposed order and the motion for reconsideration are pending; the Court has yet to enter a final order on the Company’s summary judgment motion. The Company believes that the allegations in S&W’s complaint are meritless, and that it has meritorious defenses to the claims asserted by S&W. The Company intends to defend the lawsuit and pursue its claims vigorously.

In March 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil (“MPF”) notified AES Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgas and the rationing loan provided to AES Eletropaulo, changes in the control of AES Eletropaulo, sales of assets by AES Eletropaulo and the quality of service provided by AES Eletropaulo to its customers, and requested various documents from AES Eletropaulo relating to these matters. In October 2003 this inquiry was sent to the MPF for continuing investigation. Also in March 2003, the Commission for Public Works and Services of the Sao Paulo Congress requested AES Eletropaulo to appear at a hearing concerning the alleged default by AES Elpa and AES Transgas on the BNDES financings and the quality of service rendered by AES Eletropaulo. This hearing was postponed indefinitely. In addition, in April 2003, the office of the MPF notified AES Eletropaulo that it is conducting an inquiry into possible errors related to the collection by AES Eletropaulo of customers’ unpaid past-due debts and requesting the company to justify its procedures. In December 2003, ANEEL answered, as requested by the MPF, that the issue regarding the past-due debts are to be included in the analysis to the revision of the “General Conditions for the Electric Energy Supply.”

In May 2003, there were press reports of allegations that in April 1998 Light Serviços de Eletricidade S.A. (“Light”) colluded with Enron in connection with the auction of AES Eletropaulo. Enron and Light were among three potential bidders for AES Eletropaulo. At the time of the transaction in 1998, AES owned less than 15% of the stock of Light and shared representation in Light’s management and Board with three other shareholders. In June 2003, the Secretariat of Economic Law for the Brazilian Department of Economic Protection and Defense (“SDE”) issued a notice of preliminary investigation seeking information from a number of entities, including AES Brasil Energia, with respect to certain allegations arising out of the privatization of AES Eletropaulo. On August 1, 2003, AES Elpa responded on behalf of AES-affiliated companies and denied knowledge of these allegations. The SDE began a follow-up administrative proceeding as reported in a notice published on October 31, 2003. In response to the Secretary of Economic Law’s official letters requesting explanations on such accusation, AES Eletropaulo filed its defense on January 19, 2004. On April 7, 2005 AES Eletropaulo responded to a SDE request for additional information. On July 11, 2005, the SDE ruled that the case was dismissed due to the passing of the statute of limitations and was subsequently sent to the Superior Council of the SDE for final review of the decision.

58




AES Florestal, Ltd., (“Florestal”), a wooden utility pole manufacturer located in Triunfo, in the state of Rio Grande do Sul, Brazil, has been operated by Sul since October 1997 as part of the original privatization transaction by the Government of the State of Rio Grande do Sul, Brazil, that created Sul. From 1997 to the present, the chemical compound chromated copper arsenate was used by Florestal to chemically treat the poles under an operating license issued by the Brazilian government. Prior to 1997, another chemical, creosote, was used to treat the poles. After becoming the operator of Florestal, Sul discovered approximately 200 barrels of solid creosote waste on the Florestal property. In 2002, a civil inquiry (Civil Inquiry No. 02/02) was initiated and a criminal lawsuit was filed in the city of Triunfo’s Judiciary both by the Public Prosecutors’ office of the city of Triunfo. The civil lawsuit was settled in 2003, and on June 27, 2005, the criminal lawsuit was dismissed. Florestal hired an independent environmental assessment company to perform an environmental audit of the operational cycle at Florestal. Florestal submitted an action plan that was accepted by the environmental authority under which it voluntarily offered to do containment work at the site. Companhia Estadual de Energia Elétrica (“CEEE”), which controlled Florestal prior to the privatization, has disputed the transfer of Florestal in the privatization, and has sought its return. A court decision recently determined that CEEE has rights of ownership in Florestal, and the company will be returned to CEEE. AES Sul will demand the return of that portion of the purchase price paid in the privatization for Florestal.

On January 27, 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A., Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A.) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity law of the Dominican Republic. On February 10, 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic (“Court”) an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). On or about February 24, 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. On March 1, 2004, the Superintendence of Electricity appealed the Court’s decision. On or about July 12, 2004, the Company divested any interest in Empresa Distribuidora de Electricidad del Este, S.A. The Superintendence of Electricity’s appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and intends to defend this lawsuit vigorously.

In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”), which is the government entity that currently owns 50% of Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), filed two lawsuits against Itabo, an AES affiliate, and another lawsuit against Ede Este, a former indirect subsidiary of AES. The lawsuits against Itabo also name the former president of Itabo as a defendant. In one of the lawsuits against Itabo, CDEEE requested an accounting of all transactions between Itabo and related parties. On November 29, 2004, the First Room of the Court of First Instance of the National District dismissed the case. CDEEE appealed the dismissal to the Second Room of the Court of Appeal of the National District. A hearing was held on May 12, 2005, and Itabo requested that the Court of Appeal of the National District declare that it lacked jurisdiction to decide the matter, in light of the arbitration clause set forth in the contracts executed between Itabo and CDEEE during the Capitalization Process. The Court of Appeal of the National District denied Itabo’s request and ordered that the claims be heard on the merits, but reserved judgment on Itabo’s arguments that the matter should be resolved in an arbitration proceeding. On May 25, 2005, Itabo appealed before the Court of Appeals of Santo Domingo and requested a stay of the May 12, 2005 decision. On October 14, 2005 the Court of Appeals of Santo Domingo upheld Itabo’s request of jurisdictional incompetence, accepting Itabo’s argument that the International Chamber of Commerce (“ICC”) had exclusive jurisdiction over the matter. In the other Itabo

59




lawsuit, CDEEE requested that the Second Room of the Court of Appeal of the National District order Itabo to deliver its accounting books and records for the period from September 1999 to July 2004 to CDEEE. At a hearing on March 30, 2005, Itabo argued that the Court of Appeal of the National District did not have jurisdiction to hear the case, and that the case should be decided in an arbitration proceeding. On October 6, 2005 the Court of Appeal of the National District upheld Itabo’s petition of jurisdictional incompetence and declared that the lawsuit should be decided in an arbitral proceeding. CDEEE filed an appeal of the decision with the First Room of the Court of Appeal of the National District, which is pending. In the Ede Este lawsuit, CDEEE requests an accounting of all of Ede Este’s commercial and financial operations with affiliate companies since August 5, 1999. This lawsuit was dismissed by the First Instance Tribunal of the National District for lack of jurisdiction. CDEEE then filed an identical lawsuit in the First Instance Tribunal of the Santo Domingo Province, which is pending. In a related proceeding, on May 26, 2005, Itabo filed a lawsuit in the United States District Court for the Southern District of New York, seeking to compel CDEEE to arbitrate its claims against Itabo. The petition was denied on July 18, 2005, and Itabo appealed that decision on September 6, 2005. The appeal is pending. In another related proceeding, on February 9, 2005, Itabo initiated arbitration against CDEEE and the Fondo Patrimonial para el Desarrollo (“FONPER”) in the Arbitral Court of the ICC seeking, among other relief, to enforce the arbitration/dispute resolution provisions in the contracts among the parties. FONPER submitted an answer and a counterclaim while CDEEE submitted only an answer. On March 28, 2006, Itabo and FONPER executed an agreement resolving all of their respective claims in the arbitration. The settlement agreement will be submitted to the ICC. The arbitration continues as between Itabo and CDEEE. Itabo believes it has meritorious defenses to the allegations asserted against it and will defend itself vigorously against those allegations.

On February 18, 2004, AES Gener S.A. (“Gener SA”), a subsidiary of the Company, filed a lawsuit against Coastal Itabo, Ltd. (“Coastal”), Gener SA’s co-venturer in Itabo, a Dominican Republic power generation company, in the Federal District Court for the Southern District of New York. The lawsuit sought to enjoin the efforts initiated by Coastal to hire an alleged “independent expert,” purportedly pursuant to the Shareholders Agreement between the parties, to perform a valuation of Gener SA’s aggregate interests in Itabo. Coastal asserted that Gener SA had committed a material breach under the parties’ Shareholders Agreement, and therefore, Gener SA was required if requested by Coastal to sell its aggregate interests in Itabo to Coastal at a price equal to 75% of the independent expert’s valuation. Coastal claimed a breach occurred based on alleged violations by Gener SA of purported antitrust laws of the Dominican Republic and breaches of fiduciary duty. Gener SA disputed that any default had occurred. On March 11, 2004, upon motion by Gener SA, the court enjoined disclosure of the valuation performed by the “expert” and ordered the parties to arbitration. On March 11, 2004, Gener SA commenced arbitration proceedings seeking, among other things, a declaration that it had not breached the Shareholders Agreement. Coastal then filed a counterclaim alleging that Gener SA had breached the Shareholders Agreement. On January 4, 2006, Coastal filed a “Withdrawal of Counterclaim” with a “Withdrawal of Notice of Defaults” withdrawing with prejudice its allegations that Gener SA had violated the Shareholders Agreement. On January 25, 2006, the arbitration tribunal heard arguments on the form of the final award and whether to award fees and costs to Gener SA. The arbitration tribunal’s decision on those matters is pending.

Pursuant to the pesification established by the Public Emergency Law and related decrees in Argentina, since the beginning of 2002, the Company’s subsidiary TermoAndes has converted its obligations under its gas supply and gas transportation contracts into pesos. In accordance with the Argentine regulations, payments were made in Argentine pesos at a 1:1 exchange rate. Certain gas suppliers (Tecpetrol, Mobil and Compañía General de Combustibles S.A.), which represented 50% of the gas supply contract, have objected to the payment in pesos. On January 30, 2004, such gas suppliers filed for arbitration with the ICC requesting the re-dollarization of the gas price. TermoAndes replied on March 10, 2004 with a counter-lawsuit related to: (i) the default of suppliers regarding the most favored

60




nation clause; (ii) the unilateral modification of the point of gas injection by the suppliers; (iii) the obligations to supply the contracted quantities; and (iv) the ability of TermoAndes to resell the gas not consumed. On January 26, 2006, the parties reached agreement resolving all reciprocal claims, including those submitted for arbitration. The settlement agreement was submitted to the arbitration court for it to issue a decision based on the agreed settlement. The arbitration court has yet to issue a decision.

On or about October 27, 2004, Raytheon Company (“Raytheon”) filed a lawsuit against AES Red Oak LLC (“Red Oak”) in the Supreme Court of the State of New York, County of New York. The complaint purports to allege claims for breach of contract, fraud, interference with contractual rights and equitable relief concerning alleged issues related to the construction and/or performance of the Red Oak project. The complaint seeks the return from Red Oak of approximately $30 million that was drawn by Red Oak under a letter of credit that was posted by Raytheon related to the construction and/or performance of the Red Oak project. Raytheon also seeks $110 million in purported additional expenses allegedly incurred by Raytheon in connection with the guaranty and construction agreements entered with Red Oak. In December 2004, Red Oak answered the complaint and filed counterclaims against Raytheon. In January 2005, Raytheon moved for dismissal of Red Oak’s counterclaims. In March 2005, the motion to dismiss was withdrawn and a partial motion for summary judgment was filed by Raytheon seeking return of approximately $16 million of the letter of credit draw. Red Oak submitted its opposition to the partial motion for summary judgment in April 2005. Meanwhile, Raytheon re-filed its motion to dismiss the fraud allegations in the counterclaim. In late April 2005, Red Oak filed its response opposing the renewed motion to dismiss. In December 2005, the Court granted a dismissal of Red Oak’s fraud claim. The Court also ordered the return of approximately $16 million of the letter of credit draw that had yet to be utilized for the performance/construction issues. At the Court’s suggestion, the parties are negotiating whether to deposit the $16 million into a new letter of credit by Raytheon. The parties are conducting discovery. The discovery cut-off is December 15, 2006. Raytheon also filed a related action against Red Oak in the Superior Court of Middlesex County, New Jersey, on May 27, 2005, seeking to foreclose on a construction lien filed against property allegedly owned by Red Oak, in the amount of $31 million. Red Oak was served with the Complaint in September of 2005, and filed its answer, affirmative defenses, and counterclaim in October of 2005. Raytheon has stated that it wishes to stay the New Jersey action pending the outcome of the New York action. Red Oak has not decided whether it wishes to oppose the lien or consent to a stay. Red Oak believes it has meritorious defenses to the claims asserted against it and expects to defend itself vigorously in the lawsuits.

In 2004, the Hungarian environmental authority issued a notice of environmental penalty to Borsod, AES’ Hungarian generation facility, for approximately $733,000 for emissions violations. Borsod believes that the environmental authority’s penalty calculation does not properly reflect Borsod’s environmental investments, and has therefore appealed the calculation to the Supreme Court of Hungary. If Borsod’s appeal is successful, the penalty will be reduced to approximately $175,000. A decision is expected in the second quarter of 2006. In addition, on October 24, 2005, Borsod paid an environmental penalty in local currency equivalent to approximately $191,000 for operations during 2004. Since January 1, 2005, Borsod has been operating with reduced emissions as required by regulation 14/2001, so either no penalty, or at least a reduced penalty, is expected for 2005 operations.

On January 26, 2005, the City of Redondo Beach (“City”), California, sent Williams Power Co., Inc., (“Williams”) and AES Redondo Beach, LLC (“AES Redondo”), an indirect subsidiary of the Company, a notice of assessment for allegedly overdue utility users’ tax (“UUT”) for the period of May 1998 through September 2004, taxing the natural gas used at AES Redondo’s plant to generate electricity during that period. The original assessment included alleged amounts owing of $32.8 million for gas usage and $38.9 million in interest and penalties. The City lowered the total assessment to $56.7 million on July 13, 2005, based on an admitted calculation error. An administrative hearing before the Tax Administrator was held on July 18-21, 2005, to hear Williams’ and AES Redondo’s respective objections to the assessment. On

61




September 23, 2005, the Tax Administrator issued a decision holding AES Redondo and Williams jointly and severally liable for approximately $56.7 million, over $20 million of which is interest and penalties (“September 23 Decision”). On October 7, 2005, AES Redondo and Williams filed an appeal of that decision with the City Manager of Redondo Beach. Under its Ordinance, the City of Redondo Beach was required to hold the appeal hearing within 45 days of the filing of the appeal. The City’s hearing officer, however, has issued a tentative schedule stating that any hearing will be completed by April 21, 2006, and that the “appeal determination” will be issued by May 19, 2006. In addition, in July 2005, AES Redondo filed a lawsuit in Los Angeles Superior Court seeking a refund of UUT that was paid from February 2005 through final judgment of that case, and an order that the City cannot charge AES Redondo UUT going forward. At a February 6, 2006 status conference, the Los Angeles Superior Court stayed AES Redondo’s July 2005 lawsuit until May 22, 2006, after ordering the City and AES Redondo to agree on dates by which the administrative appeal of the September 23 Decision should be finalized. On May 22, 2006, the Court will hold a status conference to determine whether the Court should proceed with AES Redondo’s July 2005 lawsuit. Furthermore, on December 13, 2005, the Tax Administrator sent AES Redondo and Williams two itemized bills for allegedly overdue UUT on the gas used at the facility. The first bill was for $1,274,753.49 in UUT, interest, and penalties on the gas used at the facility from October 1, 2004, through February 1, 2005. The second bill was for $1,757,242.12 in UUT, interest, and penalties on the gas used at the facility from February 2, 2005, through September 30, 2005. Subsequently, on January 21, 2006, the Tax Administrator sent AES Redondo and Williams another itemized bill that assessed $269,592.37 in allegedly overdue UUT, interest, and penalties on gas used at the facility from October 1, 2005, through December 31, 2005. On December 30, 2005, AES Redondo filed objections with the Tax Administrator to the City’s December 13, 2005, January 21, 2006, and any future UUT assessments. A hearing has not been scheduled on those objections, but the Tax Administrator has denied AES Redondo’s objections to the December 13, 2005 UUT assessments based on the findings of his September 23 Decision, which, as noted above, is on appeal. If there is a hearing on the December 13, 2005, and January 21, 2006, UUT assessments, the Tax Administrator has indicated that he will only address the amount of those assessments, but not the merits of them. The Company believes that it has meritorious defenses to the allegations asserted against it and will defend itself vigorously against the allegations.

The Government of the Dominican Republic (“Dominican Republic”) and its attorneys have stated in press reports that the Dominican Republic intends to file lawsuits in United States and Dominican courts against The AES Corporation (the “Company”) asserting various claims purportedly relating to the alleged disposal of manufactured aggregate in the Dominican Republic. The manufactured aggregate allegedly was manufactured at a Puerto Rico facility owned by a subsidiary of the Company and located in Guayama, Puerto Rico. The Dominican Republic and its attorneys have stated that the Dominican Republic will seek $80 million in purported damages. The Company has not been served with the referenced lawsuit regarding the manufactured aggregate.

ITEM 4                    SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fourth quarter of 2005.

62




PART II

ITEM 5.                 MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Recent Sales of Unregistered Securities

None.

Market Information

Our common stock is currently traded on the New York Stock Exchange (“NYSE”) under the symbol “AES.” The following tables set forth the high and low sale prices for our common stock as reported by the NYSE for the periods indicated.

Price Range of Common Stock

2005

 

 

 

High

 

Low

 

First Quarter

 

$

17.65

 

$

12.84

 

Second Quarter

 

17.36

 

13.72

 

Third Quarter

 

16.67

 

14.67

 

Fourth Quarter

 

17.10

 

14.94

 

 

2004

 

 

 

High

 

Low

 

First Quarter

 

$

10.71

 

$

8.02

 

Second Quarter

 

10.15

 

7.69

 

Third Quarter

 

10.65

 

9.20

 

Fourth Quarter

 

13.67

 

10.15

 

 

Holders

As of February 28, 2006, there were approximately 7,650 record holders of our common stock, par value $0.01 per share.

Dividends

Under the terms of our Senior Secured Credit Facilities, which we entered into with a commercial bank syndicate, we are not allowed to pay cash dividends. In addition, under the terms of a guaranty we provided to the utility customer in connection with the AES Thames project, we are precluded from paying cash dividends on our common stock if we do not meet certain net worth and liquidity tests. The terms of the indentures governing our outstanding Senior Subordinated Notes and Second Priority Senior Secured Notes also restrict our ability to pay dividends.

Our project subsidiaries’ ability to declare and pay cash dividends to us is subject to certain limitations contained in the project loans, governmental provisions and other agreements that our project subsidiaries are subject to.

See Item 12 (d) of this Form 10-K for information regarding Securities Authorized for Issuance under Equity Compensation Plans.

63




ITEM 6.                 SELECTED FINANCIAL DATA

The selected financial data set forth in this item 6 has been restated to correct errors that were contained in our consolidated financial statements and other financial information included in our 2004 Annual Report on Form 10-K/A, filed with the U.S. Securities and Exchange Commission on January 19, 2006. The following selected financial data should be read in conjunction with our consolidated financial statements and the related notes to the consolidated financial statements.

Our acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further explanation of the effect of such activities. Please refer to Item 1A and Note 22 to the Consolidated Financial Statements included in Item 8 of this Form 10-K for certain risks and uncertainties that may cause the data reflected herein not to be indicative of our future financial condition or results of operations.

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

 

 

(Restated)(1)

 

(Restated)(1)

 

 

 

 

 

 

 

(in millions, except per share data)

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

11,086

 

 

$

9,463

 

 

 

$

8,413

 

 

$

7,377

 

$

6,299

 

Income (loss) from continuing operations

 

632

 

 

264

 

 

 

294

 

 

(2,064

)

323

 

Discontinued operations, net of tax

 

 

 

34

 

 

 

(787

)

 

(1,561

)

(130

)

Cumulative effect of change in accounting principle, net of tax

 

(2

)

 

 

 

 

41

 

 

(376

)

 

Net income (loss)

 

$

630

 

 

$

298

 

 

 

$

(452

)

 

$

(4,001

)

$

193

 

Basic income (loss) earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

$

0.96

 

 

$

0.41

 

 

 

$

0.49

 

 

$

(3.83

)

$

0.61

 

Discontinued operations

 

 

 

0.06

 

 

 

(1.32

)

 

(2.89

)

(0.25

)

Cumulative effect of change in accounting principle

 

 

 

 

 

 

0.07

 

 

(0.70

)

 

Basic income (loss) earnings per share

 

$

0.96

 

 

$

0.47

 

 

 

$

(0.76

)

 

$

(7.42

)

$

0.36

 

Diluted income (loss) earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

$

0.95

 

 

$

0.41

 

 

 

$

0.49

 

 

$

(3.83

)

$

0.60

 

Discontinued operations

 

 

 

0.05

 

 

 

(1.32

)

 

(2.89

)

(0.24

)

Cumulative effect of change in accounting principle

 

 

 

 

 

 

0.07

 

 

(0.70

)

 

Diluted income (loss) earnings per share

 

$

0.95

 

 

$

0.46

 

 

 

$

(0.76

)

 

$

(7.42

)

$

0.36

 

 

 

 

December 31,

 

 

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

 

 

(Restated)(1)

 

(Restated)(1)

 

 

 

 

 

 

 

(in millions)

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

29,432

 

 

$

28,923

 

 

 

$

29,137

 

 

$

34,550

 

$

36,636

 

Non-recourse debt (long-term)

 

$

11,226

 

 

$

11,817

 

 

 

$

10,930

 

 

$

10,044

 

$

10,787

 

Non-recourse debt (long-term)—Discontinued operations

 

$

 

 

$

 

 

 

$

56

 

 

$

4,126

 

$

4,037

 

Recourse debt (long-term)

 

$

4,682

 

 

$

5,010

 

 

 

$

5,862

 

 

$

6,755

 

$

5,891

 

Stockholders’ equity (deficit)

 

$

1,649

 

 

$

956

 

 

 

$

(102

)

 

$

(855

)

$

5,154

 


(1)          See Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K for information related to restated Consolidated Financial Statements. A $12 million reduction to stockholders’ equity was recognized as of January 1, 2003 as the cumulative effect of the correction of errors for all periods preceding January 1, 2003. This correction was not material to the financial data presented herein as of and for the years ended December 31, 2002 and 2001.

64




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

The accompanying management’s discussion and analysis of financial condition and results of operations set forth in this Item 7 is restated to reflect the correction of errors that were contained in our consolidated financial statements and other financial information for the year ended December 31, 2004 as discussed below and in Note 1 of the Consolidated Financial Statements. The following management’s discussion and analysis of financial condition and results of operations should be read in conjunction with our restated consolidated financial statements and the related notes.

RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to filing its restated annual report on Form 10-K/A with the Securities Exchange Commission on January 19, 2006, the Company discovered its previously issued restated consolidated financial statements included certain errors in accounting for derivative instruments and hedging activities, minority interest expense and income taxes. The errors in accounting for derivative instruments and hedging activities resulted in differences in previously issued consolidated interim financial statements for certain quarterly periods in 2004 sufficient to require restatement of prior period interim results. The errors in accounting for income taxes and minority interest expense required restatement of previously issued consolidated annual financial statements.

As a result of evaluating these adjustments, the Company reduced its stockholders’ equity by $12 million as of January 1, 2003 as the cumulative effect of the correction of errors for all periods proceeding January 1, 2003, and restated its consolidated statements of operations and cash flows for the years ended December 31, 2004 and 2003 and its consolidated balance sheet as of December 31, 2004.

The restatement adjustments resulted in an increase to previously reported net income of $6 million for the year ended December 31, 2004 and in a decrease to previously reported net income of $17 million for the year ended December 31, 2003. There was no impact on gross margin or net cash flow from operating activities of the Company for any years presented. Based upon management’s review it has been determined that these errors were inadvertent and unintentional. The errors relate to the following areas:

A.              Accounting for Derivative Instruments and Hedging Activities

The Company determined that it failed to perform adequate on-going effectiveness testing for three interest rate cash flow hedges and one foreign currency cash flow hedge during 2004 as required by SFAS No. 133. As a result, the Company should have discontinued hedge accounting and recognized changes in the fair value of the derivative instruments in earnings prospectively from the last valid effectiveness assessment until the earlier of either (1) the expiration of the derivative instrument or (2) the re-designation of the derivative instrument as a hedging activity.

The net impact related to the correction of these errors to previously reported net income resulted in a decrease of $4 million and an increase of $2 million for the years ending December 31, 2004 and 2003, respectively.

B.               Income Tax and Minority Interest Adjustments

As a result of the Company’s year end closing review process, the Company discovered certain other errors related to the recording of income tax liabilities and minority interest expense. The adjustments primarily include:

·       An increase in income tax expense related to the recording of certain historical withholding tax liabilities at one of our El Salvador subsidiaries;

·       An increase in minority interest expense related to a correction of the allocation of income tax expense to minority shareholders. This allocation pertained to certain deferred tax adjustments recorded in the original restatement at one of our Brazilian generating companies. In addition,

65




minority interest expense was also corrected at this subsidiary as a result of identifying differences arising from a more comprehensive reconciliation of prior year statutory financial records to U.S. GAAP financial statements.

·       A reduction of 2004 income tax expense related to adjustments derived from 2004 income tax returns filed in 2005.

The net impact related to the correction of these errors to previously reported net income resulted in an increase of $10 million and a decrease of $19 million for the years ending December 31, 2004 and 2003, respectively. In addition, the Company restated stockholders’ equity as of January 1, 2003 by $12 million as a correction for these errors in all periods preceding January 1, 2003.

C.               Other Balance Sheet Reclassifications

Certain other balance sheet reclassifications were recorded at December 31, 2004 including a $45 million reclassification which reduced Accounts Receivables and increased Other Current Assets (regulatory assets).

EXECUTIVE SUMMARY AND OVERVIEW

The following discussion should be read in conjunction with our restated consolidated financial statements and notes to the consolidated financial statements included in Item 8 of this Form 10-K, and other information included in this report.

Who Are We?

AES is a global power company managed to meet the growing demand for electricity in ways that benefit all of our stakeholders. AES is a holding company that through its subsidiaries and affiliates owns and operates a portfolio of electricity generation and distribution businesses in 25 countries. We seek to capture the benefits of our global expertise and economies of scale in our operations. Predictable and growing cash flow, an efficient capital structure, operating and portfolio risk management, and world-class operating performance are the focus of our management efforts.

What Businesses Are We In?

We operate in two principal businesses. The first is the generation of power for sale to utilities and other wholesale customers. The second is the operation of electric utilities which distribute power to retail, commercial, industrial and governmental customers. Our financial results are reported as three business segments, two for the generation business and one for the utility business.

Our businesses may be significantly affected by a number of risks, uncertainties and other factors. Important factors that could affect financial results are discussed under Section 1A, Risk Factors.

What Are Our Reporting Segments?

We report our generation business under two reporting segments, contract generation and competitive supply. These segments together consist of approximately 36.4 gigawatts of generating capacity from 107 power plants in 20 countries.

Our contract generation businesses principally sell electricity to utilities or other wholesale customers under power purchase agreements (“PPA”) of generally five years or longer and for 75% or more of their capacity. These PPAs are designed to provide a predictable recovery of the costs of building and operating our plants as well as generating a return on our investment. Fuel supply cost risk is often limited contractually either through contract price escalation provisions or through tolling arrangements where we convert the customer’s fuel into electricity. Through these contractual agreements, the businesses generally reduce commodity and electricity price volatility and thereby increase the predictability of their gross margin, net income and cash flow.

66




Our competitive supply businesses sell electricity to wholesale customers through competitive markets and, as a result, the cash flows and earnings of such businesses are more sensitive to fluctuations in the market price of electricity, as well as natural gas, coal and other fuels. However, for our U.S. competitive supply business which includes a fleet of low-cost coal fired plants in New York, we typically hedge the majority of our fuel exposure on a rolling two year basis.

Our regulated utilities consist of 14 distribution companies in seven countries with approximately 11 million end-user customers. Three of these utilities, in the U.S., Venezuela and Cameroon, are integrated utilities providing both power generation and distribution. The remaining utilities, located in Brazil, El Salvador, Argentina, and Ukraine, are solely transmission and distribution businesses. Only one of our regulated utilities, Indianapolis Power and Light (IPL), is located in the U.S.

The largest part of our utility business portfolio operates in emerging markets, where electricity demand is expected to grow at a higher rate than in more developed countries. However, we are exposed to foreign currency, political, payment, and economic risks and significant electricity theft-related losses within developing countries. The challenge within all of these businesses is to provide dependable and quality service to a diverse customer base and achieve appropriate returns on investment through tariff increases, cost management and prudent capital investment.

In 2005, we realigned our management reporting structure into four regions: North America; Latin America; Europe, Middle East and Africa (“EMEA”); and Asia, each led by a regional president who reports directly to the Chief Executive Officer (“CEO”). This realignment allowed us to place senior leaders and resources closer to the businesses to further improve operating performance and integrate operations and development on a more localized level. This structure will help us leverage regional market trends to enhance our competitiveness and identify and capitalize on key business development opportunities. The organizational changes are expected to streamline some corporate functions to more effectively support AES businesses around the globe.

The Company also maintains a corporate Business Development group which manages large scale transactions such as mergers and acquisitions, and portfolio management, as well as targeted strategic initiatives. In addition to our primary business of operating a global power portfolio, we are engaged in exploring and promoting a set of related activities that include alternative energy businesses such as wind generation, the supply of liquefied natural gas to certain targeted North American markets, the production of greenhouse gas reduction activities and new energy technologies. At present, these initiatives represent growth opportunities for us but currently account for a de minimus amount of revenue and earnings.

What Did We Focus On In 2005?

In 2005, we focused on global operational excellence, deleveraging and credit improvement, and our growth strategies. Our operational focus included (a) safety, (b) plant and distribution system operational excellence and (c) customer service. Our deleveraging and credit improvement focus included (a) paying down $2.7 billion in debt, including $254 million at the parent company, (b) extending maturities of subsidiary debt, (c) improving parent liquidity, and (d) gaining improved parent and subsidiary credit quality and ratings. It was also a year to rebuild our growth development pipeline under a new organization structure implemented midyear. We completed the restatement of our prior year Form 10-K and are continuing to develop and implement action plans to address the material weaknesses within our financial reporting processes.

How Did We Do?

Revenue—We achieved record revenues in 2005 of $11.1 billion, an increase of 17% from $9.5 billion last year. Favorable foreign currency trends and higher prices led the increase.

Gross margin—Gross margin increased 14% to $3.2 billion, driven by the higher revenues.

67




Net cash from operating activities—Our cash flow increased 38% to $2.2 billion, driven by higher net earnings (adjusted for non-cash items), an increase in other assets net of other liabilities, and a decrease in working capital.

Earnings per share—Diluted earnings per share from continuing operations increased 132% to $0.95 in 2005 from $0.41 in 2004. Higher revenue and gross margin, together with favorable foreign currency transaction effects led the improvement.

What Was The Restatement About?

At the end of 2004, the Company identified a material weakness related to its accounting for deferred income taxes and embarked upon a global process to document the deferred income tax calculations and to perform more detailed reconciliations at its foreign subsidiaries. In July 2005 the Company determined that errors found during that process required a restatement, which was completed in January 2006. The restatement required that the Company re-file its 2004 Form 10-K and its previously issued Form 10-Q for the first quarter of 2005. The most significant adjustments involved areas of accounting that required a high degree of interpretation and/or judgment involving transactions which occurred during and prior to 2002. Management concluded that all errors were both inadvertent and unintentional. The income tax restatement errors identified primarily relate to:

·       the calculation of deferred income taxes related to certain purchase accounting adjustments for acquisitions,

·       the correct application of foreign currency translation of certain deferred income tax balances, and

·       the correction of other income tax accounts related to a review and reconciliation of prior year income tax returns.

As a result of extended review procedures, certain other adjustments related to the classification of cash versus short-term investments, consolidation, acquisition and translation accounting and revenue deferrals related to a Brazilian energy efficiency program, were identified and corrected.

In addition, subsequent to the filing of the Company’s restated financial statements as described above, the Company identified certain other errors which led us to restate our 2003 and 2004 year end numbers and the quarterly periods for 2004. These adjustments related largely to the correction of income tax expense and minority interest expense upon additional year end review of certain calculations performed during the earlier restatement process. Additionally, we identified certain derivative adjustments related to the proper documentation and treatment of a cash flow foreign currency hedge and cash flow interest rate hedges at certain of our foreign businesses.

How Are We Addressing Our Material Weaknesses?

As of December 31, 2005, the Company reported material weaknesses related to the following areas: accounting for income taxes; an aggregation of control deficiencies at our Cameroonian subsidiary; a lack of U.S. GAAP expertise and review in our Brazilian businesses; the treatment of intercompany loans denominated in other than the functional currency; and, accounting for derivatives.

Management, the Audit Committee and our Board of Directors are committed to the remediation of the material weaknesses and the continued improvement of the Company’s overall system of internal control over financial reporting. Over the last several years, in recognition of the decentralized and complex nature of our organization, management, the Audit committee and the Board of Directors have taken steps to improve the quality of the people, processes and systems within the Company’s income tax, accounting, financial reporting, internal control, compliance and internal audit functions. This included creating several new Corporate leadership positions as well as adding staffing to these functions.

In response to the material weaknesses reported as of December 31, 2005, management has developed remediation plans for each of the weaknesses and is undergoing continued efforts to strengthen

68




the existing finance organization and systems across the Company. These efforts include the reorganization of the Company-wide accounting and tax functions to align the local business finance functions with teams at the Corporate office. In addition, the Company is continuing to further expand the number of accounting and tax personnel at the Corporate office who will provide technical support and oversight of our global financial processes, as well as adding additional finance resources to our subsidiaries. This accelerated hiring effort began in February 2006, and, once completed, is expected to result in approximately 50 additional personnel within the Corporate finance organization as well as additional personnel at our subsidiaries, particularly those subsidiaries where material weaknesses were found. While the recruiting and reorganization effort is underway, the Company will continue to use third parties to provide assistance in the performance of relevant accounting and tax procedures, as well as provide assistance in the development and execution of the remediation plans.

In its effort to develop a world-class finance organization, the Company is preparing a finance leadership development program, in partnership with an international leader in management education, that is expected to begin offering courses for our finance professionals in June 2006. In addition, various levels of training programs on specific aspects of U.S. GAAP are being developed for distribution to our subsidiaries during 2006. In March 2006, the Company completed its first in-depth training related to Accounting for Income Taxes, with participation from approximately 100 AES professionals from our Corporate office, domestic, and international subsidiaries.

While the Company continues to refine and execute its remediation efforts, it will utilize additional resources to assist in the program management aspect of each material weakness remediation plan and has committed to provide status reports to our external auditors and our Audit Committee of the Board of Directors on a monthly basis throughout 2006.

What Key Growth Projects are Underway?

Our largest growth project under construction remains a 1,200 MW gas-fired power plant in Cartagena, Spain. This project is scheduled for completion in 2006, and will provide power under long-term contract to Gaz de France which will sell into the Spanish merchant power market. Other important growth projects under construction include 120 MW diesel-fired peaking facility to serve the largest power market in Chile, and a 120 MW wind farm project in Texas. Both of these projects are scheduled to be on-line in 2006 as well. In addition, a multi-pollution control project is under construction at our Greenidge coal-fired plant in New York, which will extend the useful life of the project and allow for more economical power dispatch and the generation of additional air emission allowances, both leading to increased revenues.We also secured a 15 year PPA and matching fuel supply agreement, together with construction and long-term financing for a new 670 MW (gross) lignite-fired power plant near Galabovo, Bulgaria. This project is in final engineering and permitting stages and is expected to enter construction in the spring of 2006, with start-up planned in two phases in 2009 and 2010. We have also secured a 10 year PPA for a new 150 MW hydro-electric power plant in Panama. AES has begun the engineering and geo-technical work and plans to begin construction in 2007. The plant is scheduled to be operational by 2010.

How Are We Positioning For Growth?

AES’s strategy for growing its business involves utilizing a local management structure operating in local markets. AES believes this is the best method for identifying and capitalizing on growth opportunities. These opportunities generally happen in a variety of ways: (i) through platform expansions, which are investment opportunities in existing businesses or existing country markets; (ii) greenfield development, which typically means development and construction of a new facility; and (iii) privatizations, which involves the transfer of government-owned generation and distribution systems in the private sector. These opportunities are pursued by the Company’s regional organizations. These efforts are supplemented by targeted mergers and acquisitions, which can be on an individual basis or involve

69




more complex portfolios. These efforts are led by the Company’s corporate Business Development group, acting in conjunction with the appropriate regional organization.

Our active development pipeline of potential growth investments includes opportunities in 38 countries. We have assessed country financial and operating risks in prioritizing those countries in which we would like to make investments, and look to develop a balanced geographic portfolio over time with increased presence in Eastern Europe and Asia in particular. We continue to devote significant resources at both the corporate and business level in support of these opportunities and are funding development related costs which could lead to significant new investments in 2006 and in future years. We signed a memorandum of understanding in 2005 to develop a 1,000 MW coal fired power plant in Vietnam in partnership with a Vietnamese coal producer. These agreements may or may not lead to a firm project, but provide the basis for improving the potential for a successful project, especially if the agreement is entered into on an exclusive basis.

We continue to develop wind generation opportunities, a market we entered early in 2005. We quickly became a significant player in the U.S., with responsibility for the operation of 500 MW of wind facilities and 1,000 MW of wind projects in development. We also continue to develop stand-alone LNG regasification facilities, and have started development of two new projects on the U.S. east cost during the year. Our proposed Bahamas LNG regasification terminal and 95-mile natural gas pipeline from the terminal to serve south Florida, awaits final Bahamian government approval.

The global power market is extremely large and offers multiple opportunities. In the European Union (“EU”), the market rules require a liberalized competitive wholesale power market as a condition for EU entry. However, there are a number of considerations that may limit the number of available near term opportunities in other markets. First, in the United States and, to a lesser extent, Western Europe there is limited need for new capacity, reducing the number of available greenfield opportunities in the most stable markets. Many states in the United States have slowed or reversed their trends towards liberalization, thereby reducing the number of available opportunities. Internationally, some planned privatization programs have been deferred for specific local reasons. In some of the markets outside of the United States that are liberalizing the rules, those rules are being designed such that the risks are too great to justify the level of returns currently available. Hence we have decided to either not participate in those markets or to only do so in a limited manner and wait for a more balanced set of rules or regulations to emerge.

An adjunct part of our growth strategies is portfolio management. High valuations placed on generation assets in particular, which is noted below as a challenge to our growth strategies, is also an opportunity to monetize investments or a portion of one or more of our businesses where we see the marketplace placing a significantly higher value on assets than what our own valuation shows. We would likely use proceeds from such portfolio management transaction to fund new growth investments.

The Company expects to fund these investments from our cash flows from operations and/or the proceeds from our issuance of debt, common stock, other securities and asset sales. We see sufficient value creating growth investment opportunities that may exceed available cash and cash flow from operations in future periods.

What Are Our Key Challenges?

There are several challenges we face in achieving our plans for 2006 and beyond.

Global Competition

We have seen increased global competition in our markets. In the United States and Europe multiple new financial sponsors are aggressively acquiring assets. Internationally, a number of new, regionally focused and aggressive competitors have emerged. This increased competition has led to an increase in the prices for assets in both secondary asset sales and privatizations. Prices for materials and engineering and

70




construction services are increasing, and there is a limited supply of certain key equipment components, especially in the wind generation marketplace, which may limit our ability to secure growth opportunities or achieve acceptable returns.

Foreign Currency Risk

A significant majority of our business portfolio is located outside of the U.S. and therefore usually subject to both currency translation and transaction risk. Our financial position and results of operations have been affected in the past by significant fluctuations in the value of the Argentine peso, Brazilian real and Venezuelan bolivar relative to the U.S. dollar. We hedge certain transaction exposures principally related to debt, and have restructured debt into local currency denomination to minimize risk when possible. Although these actions may have mitigated negative impacts in certain cases, movements within currencies are difficult to predict and continue to have a significant impact on our financial results.

Political Environment

Several of our businesses operate in politically unstable environments. The impact of governmental change and uncertainty impacts foreign currency volatility, our ability to maintain or attract needed financing, as well as our ability to effectively recover costs through routine tariff or regulatory reset proceedings.

Regulatory Risk

Due to the regulated nature of the utilities business, we are subject to regulatory risk related to changes in tariff agreements, and existing laws and provisions. Changes in regulation may impact our future operations, cash flows and financial condition.

Long-term Contracts

Several of our power generation plants operate on a long term contract basis with one or a limited number of contracts related to both the fuel supply and power demand. The remaining periods for these long-term contracts range from 1 to 26 years. The ability of our customers and suppliers to perform under these contracts and our ability to negotiate new contracts upon expiration may have a significant impact on our results of operations in the future.

Performance Improvement

Although we continue to place significant effort on performance improvement initiatives, it remains difficult to measure the financial impact of such initiatives in our financial results, and the reported impact has not been significant in comparison to other important business drivers such as price, volume, and foreign currency movements. In addition, benefits from global sourcing include avoided costs, reduction in actual versus originally estimated capital project costs, and projected savings on assumed spend volume which may or may not actually be achieved. These benefits will not be fully reflected in our consolidated financial position, results of operations and cash flows.

Looking Ahead—What Is Our Key Focus For 2006?

Our focus in 2006 will be in several key areas, starting with safety, by building on two years of improvement in both lower lost workday cases and in reporting of accidents and near misses. Operational excellence will also continue to drive for improvements in both the generation and utility businesses. In addition, management is committed to the remediation of our material weaknesses in internal control over financial reporting as well as the continued improvement of the Company’s overall system of internal controls. The Company also will continue to strengthen its training and development programs for AES people at all levels.

71




We will continue to pursue growth opportunities, including platform expansion, greenfield projects, privatization and mergers and acquisitions, as well as our strategic initiatives in alternative energy businesses such as wind generation, LNG, and climate change. As we see an increase in projects under construction, we look to further strengthen our ability to manage and execute multiple construction projects. We want to ensure all the appropriate policies, work procedures, and accountability is in place to execute transactions with proper financial controls and tax and accounting determinations.

To take advantage of these opportunities we intend to leverage our existing strengths and capitalize on favorable market conditions to deliver higher earnings and cash flow and improved credit quality. The catalysts to further growth, consistent with appropriate risk/reward profiles, include both external and internal factors such as:

·       continued electricity demand growth in key markets;

·       attraction of private and public capital for emerging markets;

·       government policies that encourage the development of new areas of opportunity, including renewable energy; and

·       experience with related areas that can lead to business opportunities such as LNG regasification, fossil fuel sourcing, non-power markets, and air emission allowance markets.

CRITICAL ACCOUNTING ESTIMATES

The consolidated financial statements of AES are prepared in conformity with generally accepted accounting principles in the United States of America, which requires the use of estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. AES’s significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K. Critical accounting estimates are described in this section. An accounting estimate is considered critical if: the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made; different estimates reasonably could have been used; or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods.

Allowance for Doubtful Accounts

The Company maintains an allowance for doubtful accounts for estimated uncollectible accounts receivable. The allowance is based on the Company’s assessment of known delinquent accounts, historical experience, and other currently available evidence of the collectability and aging of accounts receivable. There is an increased level of exposure related to the Company’s regulated utilities receivables in certain non U.S. locations which are due from local municipalities and other governmental agencies. These customers are often large and normally pay within extended timeframes. The amount of historical experience is limited in some cases due to the recent nature of AES acquisitions subsequent to privatization. In addition, local political and economic factors often play a part in a municipality’s current ability or willingness to pay. The Company monitors these situations closely and continues to refine its reserving policy based on both historical experience and current knowledge of the related political/economic environments.

72




Income Tax Reserves

We are subject to income taxes in both the United States and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certain of its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the provision for income taxes. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amount of the tax estimates is reasonable, it is possible that the ultimate outcome of current or future examinations may exceed current reserves in amounts that could be material. A range of these amounts cannot be reasonably estimated at December 31, 2005, as they are primarily unasserted claims.

On October 22, 2004, the American Jobs Creation Act (“the AJCA”) was signed into law. The AJCA includes a deduction of 85% of certain foreign earnings that are repatriated, as defined in the AJCA. The Company conducted an evaluation of the effects of the repatriation provision in accordance with recently issued Treasury Department guidance. As a result, the Company elected not to apply this provision to qualifying earnings repatriations in 2005.

Long-Lived Assets

In accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” we periodically review the carrying value of our long-lived assets held and used, other than goodwill and intangible assets with indefinite lives, and assets to be disposed of when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under SFAS No. 144. These events or circumstances may include the relative pricing of wholesale electricity by region and the anticipated demand and cost of fuel. If the carrying amount is not recoverable, an impairment charge is recorded for the amount by which the carrying value of the long-lived asset exceeds its fair value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery was probable. For non-regulated assets, an impairment charge would be recorded as a charge against earnings.

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for measurement, if available. In the absence of quoted market prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow projections or other indicators of fair value such as bids received, comparable sales or independent appraisals.

In connection with the periodic evaluation of long-lived assets in accordance with the requirements of SFAS No. 144, the fair value of the asset can vary if different estimates and assumptions would have been used in our applied valuation techniques. In cases of impairment described in Note 16 to the Consolidated Financial Statements included in Item 8 of this Form 10-K, we made our best estimate of fair value using valuation methods based on the most current information at that time. We have been in the process of divesting certain assets and their sales values can vary from the recorded fair value as described in Note 19 to the Consolidated Financial Statements included in Item 8 of this Form 10-K. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions, and management’s analysis of the benefits of the transaction.

73




Goodwill

We review the carrying value of our goodwill annually during the fourth quarter. We also review the carrying value of our goodwill periodically when events and circumstances warrant such a review. This review is performed using estimates of fair value and includes discounted future cash flows. If the carrying value of goodwill is considered impaired, an impairment charge is recorded.

Pension and Postretirement Obligations

Certain of our foreign and domestic subsidiaries maintain defined benefit pension plans which we refer to as the pension plans, or the plans, covering substantially all of their respective employees. Pension benefits are generally based on years of credited service, age of the participant and average earnings. Of the twenty one defined benefit pension plans existing at December 31, 2005, two exist at domestic subsidiaries and the remainder exists at foreign subsidiaries. The measurement of our pension obligations, costs and liabilities is dependent on a variety of assumptions used by our actuaries. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions. The plan trustee conducts an independent valuation of the fair value of pension plan assets.

The assumptions used in developing the required estimates include the following key factors:

·       Discount rates

·       Salary growth

·       Retirement rates

·       Inflation

·       Expected return on plan assets

·       Mortality rates

The effects of actual results differing from our assumptions are accumulated and amortized over future periods and, therefore, generally affect our recognized expense in such future periods.

Sensitivity of our pension funded status and stockholders’ equity to the indicated increase or decrease in the discount rate assumption is shown below. Although not an estimate, we’ve also included sensitivity around the actual return on pension assets. Note that these sensitivities may be asymmetric, and are specific to the base conditions at year-end 2005. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The December 31, 2005 funded status is affected by December 31, 2005 assumptions. Pension expense for 2005 is affected by December 31, 2004 assumptions. The impact on our funded status, equity and U.S. pension expense from a one percentage point change in these assumptions is shown below (in millions):

Increase of 1% in the discount rate

 

$

(16

)

Decrease of 1% in the discount rate

 

$

23

 

Increase of 1% in the long-term rate of return on plan assets

 

$

(19

)

Decrease of 1% in the long-term rate of return on plan assets

 

$

19

 

 

Regulatory Assets and Liabilities

The Company accounts for certain of its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, AES records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-

74




regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income.

Accounting for Derivative Instruments and Hedging Activities

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

Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments are recorded in the same category as generated by the underlying asset or liability.

SFAS No. 133 enables companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with SFAS No. 133. If we deem that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

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

AES generally uses quoted exchange prices to the extent they are available to determine the fair value of derivatives. In the absence of actively quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, AES will estimate prices, when possible, based on available historical and near-term future price information as well as utilizing statistical methods. When external valuation models are not available, the company utilizes internal models for valuation. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.

For cash flow hedges of forecasted transactions, AES must estimate the future cash flows represented by the forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing for the reclassification of gains or losses on cash flow hedges from accumulated other comprehensive loss (“AOCI”) into earnings.

75




NEW ACCOUNTING PRONOUNCEMENTS

Consolidation of Variable Interest Entities

In January 2003, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (“FIN 46” or “Interpretation”). FIN 46 is an interpretation of Accounting Research Bulletin 51 “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (“VIE”). The primary objective of the Interpretation is to provide guidance on the identification of and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. On December 24, 2003, the FASB issued Interpretation No. 46 (Revised 2003) Consolidation of Variable Interest Entities (“FIN 46(R)” or “Revised Interpretation”), which partially deferred the effective date of FIN 46 for certain entities and makes other changes to FIN 46, including a more complete definition of variable interest and an exemption for many entities defined as businesses. The Company applied FIN 46 in its financial statements relating to its interest in variable interest entities or potential variable interest entities as of December 31, 2003, and applied FIN 46(R) as of March 31, 2004. The application of FIN 46(R) did not have an impact on the Company’s condensed consolidated financial statements for any quarter through December 31, 2004.

In March 2005, the FASB issued Staff Position (“FSP”) No. FIN 46(R)-5, “Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities.” This FSP clarifies that when applying the variable interest consolidation model, a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (“VIE”) or potential VIE. FSP No. FIN 46(R)-5 became effective as of April 1, 2005. Upon the adoption of FSP No. FIN 46(R)-5, the Company did not identify any potential or implicit VIEs.

Share-Based Payment

In December 2004, the Financial Accounting Standards Board (“FASB”) issued a revised Statement of Financial Accounting Standard (“SFAS”) No. 123, “Share-Based Payment.” SFAS 123R eliminates the intrinsic value method as an alternative method of accounting for stock-based awards under Accounting Principles Board (“APB”) No. 25 by requiring that all share-based payments to employees, including grants of stock options for all outstanding years, be recognized in the financial statements based on their fair values. It also revises the fair-value based method of accounting for share-based payment liabilities, forfeitures and modifications of stock-based awards and clarifies the guidance under SFAS No. 123 related to measurement of fair value, classifying an award as equity or as a liability and attributing compensation to reporting periods. In addition, SFAS No. 123R amends SFAS No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as an operating cash flow.

Effective January 1, 2003, the Company adopted the fair value recognition provision of SFAS No. 123, as amended by SFAS No. 148, prospectively to all employee awards granted, modified or settled after January 1, 2003. We adopted SFAS No. 123R and related guidance on January 1, 2006, using the modified prospective transition method. Under this transition method, compensation cost will be recognized (a) based on the requirements of SFAS No. 123R for all share-based awards granted subsequent to January 1, 2006 and (b) based on the original provisions of SFAS No. 123 for all awards granted prior to January 1, 2006, but not vested as of this date. Results for prior periods will not be restated. Management is currently evaluating the effect of the adoption of SFAS No. 123R under the modified prospective application transition method, but does not expect the adoption to have a material effect on the Company’s financial condition, results of operations or cash flows.

76




Conditional Asset Retirement Obligations

In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47 “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143,” which clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143 “Accounting for Asset Retirement Obligations.” Specifically, FIN 47 provides that an asset retirement obligation is conditional when the timing and/or method of settling the obligation is conditioned on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005.

The Company’s asset retirement obligations covered by FIN 47 primarily include conditional obligations to demolish assets or return assets in good working condition at the end of the contractual or concession term, and for the removal of equipment containing asbestos and other contaminants. As of December 31, 2005, the Company recorded additional asset retirement obligations in the amount of $18 million as a result of the implementation of FIN 47. The cumulative effect of the initial application of this Interpretation was recognized as a change in accounting principle in the amount of $2 million, net of income tax benefit of $1 million.

The pro forma net income (loss) and earnings (loss) per share resulting from the adoption of FIN 47 for the years ended December 31, 2005, 2004 and 2003, is not materially different from the actual amounts reported in the accompanying consolidated statement of operations for those periods. Had FIN 47 been applied during all periods presented, the asset retirement obligations at December 31, 2003 and December 31, 2004 would have been approximately $14 million and $15 million, respectively.

77




RESULTS OF OPERATIONS

 

 

For The Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

$ change 2005
vs. 2004

 

$ change 2004
vs. 2003

 

 

 

(in millions, except per share data)

 

Gross Margin:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated utilities

 

$

1,237

 

$

1,116

 

$

976

 

 

$

121

 

 

 

$

140

 

 

Contract generation

 

1,603

 

1,428

 

1,262

 

 

175

 

 

 

166

 

 

Competitive supply

 

338

 

238

 

221

 

 

100

 

 

 

17

 

 

Total gross margin

 

3,178

 

2,782

 

2,459

 

 

396

 

 

 

323

 

 

General and administrative expenses(1)

 

(221

)

(182

)

(157

)

 

(39

)

 

 

(25

)

 

Interest expense

 

(1,896

)

(1,932

)

(1,984

)

 

36

 

 

 

52

 

 

Interest income

 

391

 

282

 

280

 

 

109

 

 

 

2

 

 

Other income, net

 

19

 

12

 

65

 

 

7

 

 

 

(53

)

 

Loss on sale of investments, asset and goodwill impairment expense

 

 

(45

)

(212

)

 

45

 

 

 

167

 

 

Foreign currency transaction (losses) gains on net monetary position

 

(89

)

(165

)

99

 

 

76

 

 

 

(264

)

 

Equity in earnings (loss) of affiliates

 

76

 

70

 

94

 

 

6

 

 

 

(24

)

 

Income tax expense

 

(465

)

(359

)

(211

)

 

(106

)

 

 

(148

)

 

Minority interest (expense) income

 

(361

)

(199

)

(139

)

 

(162

)

 

 

(60

)

 

Income (loss) from continuing operations

 

632

 

264

 

294

 

 

368

 

 

 

(30

)

 

Income (loss) from operations of discontinued businesses

 

 

34

 

(787

)

 

(34

)

 

 

821

 

 

Cumulative effect of accounting change

 

(2

)

 

41

 

 

(2

)

 

 

(41

)

 

Net income (loss)

 

$

630

 

$

298

 

$

(452

)

 

$

332

 

 

 

$

750

 

 

PER SHARE DATA:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic income (loss) per share from continuing operations

 

$

0.96

 

$

0.41

 

$

0.49

 

 

$

0.55

 

 

 

$

(0.08

)

 

Diluted income (loss) per share from continuing operations

 

$

0.95

 

$

0.41

 

$

0.49

 

 

$

0.54

 

 

 

$

(0.08

)

 


(1)          General and administrative expenses are corporate and business development expenses.

78




Overview

Revenue

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

Regulated Utilities

 

$

5,737

 

 

52%

 

 

 

$

4,897

 

 

 

52%

 

 

 

$

4,425

 

 

 

53%

 

 

Contract Generation

 

4,137

 

 

37%

 

 

 

3,546

 

 

 

37%

 

 

 

3,108

 

 

 

37%

 

 

Competitive Supply

 

1,212

 

 

11%

 

 

 

1,020

 

 

 

11%

 

 

 

880

 

 

 

10%

 

 

Non-Regulated

 

5,349

 

 

48%

 

 

 

4,566

 

 

 

48%

 

 

 

3,988

 

 

 

47%

 

 

Total

 

$

11,086

 

 

100%

 

 

 

$

9,463

 

 

 

100%

 

 

 

$

8,413

 

 

 

100%

 

 

 

Revenues increased approximately $1.6 billion, or 17%, to $11.1 billion in 2005 from $9.5 billion in 2004, primarily in the Regulated Utilities and Contract Generation segments. Regulated utilities revenues increased $840 million, or 17%, mostly due to favorable exchange rates at our Brazilian utilities while contract generation revenues increased $591 million, or 17%, due to increased contract pricing and favorable foreign exchange rates at our businesses in Brazil, Chile and Mexico.  Excluding the estimated impacts of foreign currency translation effect, revenues would have increased approximately 10% from 2004 to 2005. Excluding businesses that commenced commercial operations in 2005 or 2004, the revenue increase would remain at 17% in 2005.

Revenues increased approximately $1.1 billion, or 12%, to $9.5 billion in 2004 from $8.4 billion in 2003, primarily in the Regulated Utilities and Contract Generation segments. Regulated utilities revenues increased $472 million, or 11%, mostly due to increased tariffs at our Latin American utilities while contract generation revenues increased $438 million, or 14%, mainly due to higher contract prices and new projects coming on line in Qatar, Oman and the Dominican Republic. Excluding the estimated impacts of foreign currency translation effect, revenues would have increased approximately 11% from 2003 to 2004. Excluding businesses that commenced commercial operations in 2004 or 2003, revenues increased 11% to $9.3 billion in 2004.

Gross Margin

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

Regulated Utilities

 

 

$

1,237

 

 

 

39%

 

 

 

$

1,116

 

 

 

40%

 

 

 

$

976

 

 

 

40%

 

 

Contract Generation

 

 

1,603

 

 

 

50%

 

 

 

1,428

 

 

 

51%

 

 

 

1,262

 

 

 

51%

 

 

Competitive Supply

 

 

338

 

 

 

11%

 

 

 

238

 

 

 

9%

 

 

 

221

 

 

 

9%

 

 

Non-Regulated

 

 

1,941

 

 

 

61%

 

 

 

1,666

 

 

 

60%

 

 

 

1,483

 

 

 

60%

 

 

Total

 

 

$

3,178

 

 

 

100%

 

 

 

$

2,782

 

 

 

100%

 

 

 

$

2,459

 

 

 

100%

 

 

Gross Margin as a % of Revenue

 

 

28.7%

 

 

 

 

 

 

 

29.4%

 

 

 

 

 

 

 

29.2%

 

 

 

 

 

 

 

Gross margin increased $396 million, or 14%, to $3.2 billion in 2005 from $2.8 billion in 2004, with gross margin improvements in all segments during 2005 compared to 2004. Contract generation gross margin increased $175 million, or 12%, due to higher contract pricing while regulated utilities gross margin increased $121 million, or 11%, as a result of higher overall revenues and lower fixed expenses. Competitive supply gross margin increased $100 million, or 42%, due to higher prices and the sale of environmental allowances. Excluding businesses that commenced commercial operations in 2005 or 2004,

79




the gross margin increase in 2005 would remain at 14%. Gross margin as a percentage of revenues decreased to 28.7% in 2005 from 29.4% in 2004 due to higher fuel costs throughout most of our businesses, increased receivable reserves in our Brazilian utilities and higher unrecovered purchased electricity prices in our regulated utilities.

Gross margin increased $323 million, or 13%, to $2.8 billion in 2004 from $2.5 billion in 2003, as gross margin for all segments improved in 2004 compared to 2003. Contract generation gross margin increased $166 million, or 13%, due to higher contract pricing and new projects coming on line while regulated utilities gross margin increased $140 million, or 14%, as a result of increased tariffs. Competitive supply gross margin increased $17 million, or 8%, due to higher prices slightly offset by higher fuel costs. Excluding businesses that commenced commercial operations in 2004 or 2003, gross margin increased 10% to $2.7 billion in 2004. Gross margin as a percentage of revenues increased to 29.4% in 2004 from 29.2% in 2003.

Segment Analysis

Regulated Utilities Revenue

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

North America

 

 

$

951

 

 

 

9%

 

 

 

$

884

 

 

 

9%

 

 

 

$

832

 

 

 

10%

 

 

Latin America

 

 

4,276

 

 

 

38%

 

 

 

3,550

 

 

 

38%

 

 

 

3,219

 

 

 

38%

 

 

EMEA

 

 

510

 

 

 

5%

 

 

 

463

 

 

 

5%

 

 

 

374

 

 

 

5%

 

 

Total

 

 

$

5,737

 

 

 

52%

 

 

 

$

4,897

 

 

 

52%

 

 

 

$

4,425

 

 

 

53%

 

 

 

Regulated utilities revenues increased $840 million, or 17%, to $5.7 billion in 2005 from $4.9 billion in 2004, primarily due to higher revenues in our Latin America utilities, which experienced an increase in revenues of $726 million, or 20%, in 2005. Excluding the estimated impacts of foreign currency translation, regulated utilities revenues would have increased 5% from 2004 to 2005. This increase in Latin America utilities revenues was due to favorable exchange rates at AES Eletropaulo and Sul in Brazil, only partially offset by the negative impacts of foreign currency remeasurement at EDC in Venezuela. The Brazilian real appreciated 12% in 2005 while the Venezuelan bolivar devalued almost 11% for the same period. Recognition of a retroactive tariff increase, as well as an increase in the average customer tariff due to a rate increase at AES Eletropaulo in Brazil in 2005, also contributed to the year over year revenue increase in Latin America utilities revenues.

Regulated utilities revenues increased $472 million, or 11%, to $4.9 billion in 2004 from $4.4 billion in 2003, primarily due to higher revenues in our Latin America utilities, which experienced an increase in revenues of $331 million, or 10%, in 2004. Excluding the estimated impacts of foreign currency translation, regulated utilities revenues would have increased 10% from 2003 to 2004. This increase in Latin America utilities revenues was due to increased tariffs and favorable exchange rates at AES Eletropaulo and Sul in Brazil that were partially offset by lower sales volume. The average customer tariff at AES Eletropaulo increased in 2004 due to both a rate increase and an increase in residential consumption, although overall consumption decreased by 1%. Revenues at our Venezuelan subsidiary, EDC, also increased due to higher tariffs that were offset substantially by unfavorable exchange rates and reduced sales volumes.

80




Regulated Utilities Gross Margin

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

North America

 

 

$

305

 

 

 

10%

 

 

 

$

304

 

 

 

11%

 

 

 

$

282

 

 

 

11%

 

 

Latin America

 

 

816

 

 

 

25%

 

 

 

754

 

 

 

27%

 

 

 

653

 

 

 

27%

 

 

EMEA

 

 

116

 

 

 

4%

 

 

 

58

 

 

 

2%

 

 

 

41

 

 

 

2%

 

 

Total

 

 

$

1,237

 

 

 

39%

 

 

 

$

1,116

 

 

 

40%

 

 

 

$

976

 

 

 

40%

 

 

Regulated Utilities Gross Margin as a  % of Regulated Utilities Revenue

 

 

21.6%

 

 

 

 

 

 

 

22.8%

 

 

 

 

 

 

 

22.1%

 

 

 

 

 

 

 

Regulated utilities gross margin increased $121 million, or 11%, to $1.2 billion in 2005 from $1.1 billion in 2004, primarily due to higher gross margins in our Latin America and EMEA utilities. Gross margins in our Latin America utilities increased $62 million, or 8%, primarily as a result of higher overall revenues and favorable foreign currency translation impacts at AES Eletropaulo and Sul in Brazil offset by the recording of $192 million of gross bad debts reserve in the second quarter of 2005 related to the collectability of certain municipal receivables at our utilities in Brazil. Gross margins in our EMEA utilities increased $58 million, or 100%, as AES SONEL in Cameroon also showed positive results primarily due to higher revenues, better demand and lower fixed expenses. Gross margin for all regulated utilities as a percent of revenue decreased to 21.6% in 2005 compared to 22.8% in 2004 due to higher purchased electricity costs in all regions and the recording of the gross bad debts reserve mentioned earlier at our utilities in Brazil.

Regulated utilities gross margin increased $140 million, or 14%, to $1.1 billion in 2004 from $1.0 billion in 2003, primarily due to higher gross margins in our Latin America utilities, which experienced an increase in gross margin of $101 million, or 15%, in 2004. The increase in Latin America utilities gross margin was due to the increased tariffs and the favorable effect of exchange rates on revenues at AES Eletropaulo in Brazil partially offset by increased costs related to purchased electricity and bad debt provisions. Gross margin decreased at EDC in Venezuela due to the unfavorable effect of exchange rates and lower demand coupled with higher fixed costs in 2004 compared to 2003. Gross margin for regulated utilities as a percent of revenue increased slightly to 22.8% in 2004 compared to 22.1% in 2003 primarily due to increased tariffs in Latin America.

Contract Generation Revenue

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

North America

 

 

$

1,281

 

 

 

11%

 

 

 

$

1,258

 

 

 

13%

 

 

 

$

1,221

 

 

 

15%

 

 

Latin America

 

 

1,755

 

 

 

16%

 

 

 

1,286

 

 

 

14%

 

 

 

1,070

 

 

 

13%

 

 

EMEA

 

 

956

 

 

 

9%

 

 

 

882

 

 

 

9%

 

 

 

699

 

 

 

8%

 

 

Asia

 

 

145

 

 

 

1%

 

 

 

120

 

 

 

1%

 

 

 

118

 

 

 

1%

 

 

Total

 

 

$

4,137

 

 

 

37%

 

 

 

$

3,546

 

 

 

37%

 

 

 

$

3,108

 

 

 

37%

 

 

 

Contract generation revenues increased $591 million, or 17%, to $4.1 billion in 2005 from $3.5 billion in 2004 primarily due to increases at our Latin America and EMEA businesses, while North America and Asia showed slight improvements. Excluding the estimated impacts of foreign currency translation,

81




revenues would have increased approximately 15% from 2004 to 2005. The increase in Latin America is primarily due to higher contract prices at Tiete (a group of hydro-electric plants providing electricity primarily to AES Eletropaulo) and Uruguaiana in Brazil, Gener in Chile and Los Mina in the Dominican Republic. In addition, the Latin America region was impacted by favorable foreign currency translation in Brazil and Chile. Andres in the Dominican Republic experienced increased volume in addition to higher prices. The increase in EMEA revenues is primarily due to higher contract prices at Tisza in Hungary and a full year of operations at Ras Laffan in Qatar. The increase in revenues in Asia is due to higher contract prices and availability at Kelanitissa in Sri Lanka. The increase in North America revenues is primarily due to higher contract prices and favorable foreign currency impacts at Merida in Mexico and higher prices at our business in Puerto Rico, along with the acquisition of the SeaWest wind business in the first quarter of 2005. These increases are partially offset by a decrease in contract price at Shady Point in Oklahoma and outages at Thames in Connecticut.

Contract generation revenues increased $438 million, or 14%, to $3.5 billion in 2004 from $3.1 billion in 2003 primarily due to increases at our Latin America and EMEA businesses. Excluding the estimated impacts of foreign currency translation, revenues would have increased approximately 12% from 2003 to 2004. The increase in revenues in Latin America is primarily due to increased contract pricing at Tiete in Brazil and Gener in Chile, along with a full year’s operating results from Andres in the Dominican Republic. Additionally, the Latin America region was impacted by favorable foreign currency translation at Tiete and Gener. The increase in revenues in EMEA is primarily due to increased contract pricing at Kilroot in Northern Ireland and the completion of the Ras Laffan’s power and water desalination plant in Qatar, as well as the reporting of a full year’s operating results from Barka in Oman which came on line in 2003. These increases were slightly offset by lower volumes at Tisza in Hungary as a result of outages to perform plant upgrades in 2004. Additionally, the EMEA region was impacted favorably by foreign currency translation at Kilroot and Tisza. Slight increases in North America revenue is due to increased contract pricing at Merida in Mexico. Asia revenues remained fairly constant in 2003 and 2004.

Contract Generation Gross Margin

 

 

For the Years Ended December 31,

 

 

 

 

2005

 

2004

 

2003

 

 

 

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

 

North America

 

 

$

448

 

 

 

14%

 

 

 

$

511

 

 

 

18%

 

 

 

$

509

 

 

 

20%

 

 

Latin America

 

 

705

 

 

 

22%

 

 

 

512

 

 

 

18%

 

 

 

416

 

 

 

17%

 

 

EMEA

 

 

417

 

 

 

13%

 

 

 

380

 

 

 

14%

 

 

 

308

 

 

 

13%

 

 

Asia

 

 

33

 

 

 

1%

 

 

 

25

 

 

 

1%

 

 

 

29

 

 

 

1%

 

 

Total

 

 

$

1,603

 

 

 

50%

 

 

 

$

1,428

 

 

 

51%

 

 

 

$

1,262

 

 

 

51%

 

 

Contract Generation Gross Margin as a % of Contract Generation Revenue

 

 

38.7%

 

 

 

 

 

 

 

40.3%

 

 

 

 

 

 

 

40.6%

 

 

 

 

 

 

 

Contract generation gross margin increased $175 million, or 12%, to $1.6 billion in 2005 from $1.4 billion in 2004, with higher gross margin contributions from our Latin America businesses offset by lower gross margin contributions from our North American businesses. Gross margin in our Latin America generation businesses increased $193 million, or 38%, due to higher overall revenues at Tiete in Brazil and Gener in Chile and higher revenues and lower purchased electricity at Los Mina in the Dominican Republic. These increases were partially offset by unfavorable foreign currency translation and fixed costs at Tiete and higher fuel and variable costs at Gener. The North America gross margin decrease is primarily due to the decrease in the contract pricing at Shady Point in Oklahoma, outages incurred at Thames in

82




Connecticut and lower dispatch at Southland in California. The contract generation gross margin as a percentage of revenue decreased to 38.7% in 2005 from 40.3% in 2004.

Contract generation gross margin increased $166 million, or 13%, to $1.4 billion in 2004 from $1.3 billion in 2003 with higher gross margin contributions from our Latin America and EMEA businesses. Gross margin in the Latin America businesses increased primarily due to increased contract pricing escalations at Tietê and Uruguaiana in Brazil slightly offset by higher fuel costs at Gener in Chile. The inclusion of a full year’s operating results for Andres in the Dominican Republic also contributed to the gross margin increase. The EMEA gross margin increase is primarily due to pricing escalations at Kilroot in Northern Ireland which were partially offset by higher fuel costs in that same business. Gross margin in EMEA was positively impacted further by the completion of Ras Laffan’s power and water desalination plant in Qatar, as well as the reporting of a full year’s operating results for Barka in Oman which came on line in 2003. Gross margin in North America and Asia remained fairly constant during the period. The contract generation gross margin as a percentage of revenues slightly decreased to 40.3% in 2004 from 40.6% in 2003.

Competitive Supply Revenue

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

Revenue

 

% of Total
Revenue

 

North America

 

 

$

544

 

 

 

5%

 

 

 

$

447

 

 

 

5%

 

 

 

$

459

 

 

 

5%

 

 

Latin America

 

 

389

 

 

 

4%

 

 

 

300

 

 

 

4%

 

 

 

186

 

 

 

2%

 

 

EMEA

 

 

121

 

 

 

1%

 

 

 

136

 

 

 

1%

 

 

 

132

 

 

 

2%

 

 

Asia

 

 

158

 

 

 

1%

 

 

 

137

 

 

 

1%

 

 

 

103

 

 

 

1%

 

 

Total

 

 

$

1,212

 

 

 

11%

 

 

 

$

1,020

 

 

 

11%

 

 

 

$

880

 

 

 

10%

 

 

 

Competitive supply revenues increased $192 million, or 19%, to $1.2 billion in 2005 from $1.0 billion in 2004 primarily due to increases at our North America and Latin America businesses. Excluding the estimated impacts of foreign currency translation, revenues would have increased approximately 18% from 2004 to 2005. Asia showed slight increases in revenues which were almost entirely offset by declines from our businesses in EMEA. The increase in North America revenues is primarily due to higher prices and approximately $45 million in  sales of emission allowances at our business in New York and higher prices obtained by Deepwater in Texas. The increase in Latin America revenues is due to higher prices and volume increases at Alicura and Parana in Argentina and higher prices at our business in Panama. Revenues from our Asia businesses showed slight increases due to a mix of higher prices and increased volume at Ekibastuz, Altai and Maikuben, all located in Kazakhstan. Decreases in revenues from our EMEA businesses are due primarily to the sale of Ottana in Italy during 2005 partially offset by higher prices at Borsod in Hungary.

Competitive supply revenues increased $140 million, or 16%, to $1.0 billion in 2004 from $880 million in 2003 primarily due increases at our Latin America and EMEA businesses. Excluding the estimated impacts of foreign currency translation, revenues would have increased approximately 13% from 2003 to 2004. Asia also showed increases which were partially offset by declines at our North America businesses. The increase in Latin America is primarily due to higher prices and significantly higher than expected dispatch at CTSN in Argentina as a result of increased demand caused by gas shortages in Argentina and increased revenues from the completion of Esti, a greenfield hydroelectric project in Panama, along with the expansion of another hydroelectric project at Bayano in Panama. Additionally, higher competitive market prices for electricity sold at Parana in Argentina also contributed to the overall Latin America increase. The increase in Asia is primarily due to higher competitive prices at Ekibastuz in Kazakhstan and positive foreign currency impacts at Ekibastuz and Altai in Kazakhstan. The increase in revenues in

83




EMEA is mainly due to positive foreign currency impacts at Ottana in Italy and Borsod in Hungary. These increases were more than offset by declines in North America caused by lower revenues from our plants in New York.

Competitive Supply Gross Margin

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

Gross Margin

 

% of Total
Gross Margin

 

North America

 

 

$

145

 

 

 

5%

 

 

 

$

85

 

 

 

3%

 

 

 

$

110

 

 

 

5%

 

 

Latin America

 

 

165

 

 

 

5%

 

 

 

113

 

 

 

4%

 

 

 

83

 

 

 

3%

 

 

EMEA

 

 

(12

)

 

 

0%

 

 

 

4

 

 

 

0%

 

 

 

3

 

 

 

0%

 

 

Asia

 

 

40

 

 

 

1%

 

 

 

36

 

 

 

2%

 

 

 

25

 

 

 

1%

 

 

Total

 

 

$

338

 

 

 

11%

 

 

 

$

238

 

 

 

9%

 

 

 

$

221

 

 

 

9%

 

 

Competitive Supply Gross Margin as a % of Competitive Supply Revenue

 

 

27.9%

 

 

 

 

 

 

 

23.3%

 

 

 

 

 

 

 

25.1%

 

 

 

 

 

 

 

Competitive supply gross margin increased $100 million, or 42%, to $338 million in 2005 from $238 million in 2004 with higher gross margin contributions from the North America and Latin America businesses. Gross margin in our North America businesses increased primarily due to higher overall revenues at our businesses in New York which includes approximately $45 million in sales of emission allowances, and at Deepwater in Texas, offset slightly by higher fuel costs in New York and higher operating costs at Deepwater. Gross margin in our Latin America businesses increased due to higher overall revenues at Alicura and Parana in Argentina and lower purchased electricity costs at our business in Panama, offset slightly by higher fuel costs at Alicura and Parana and higher operating costs at Panama. Gross margin in our Asia region increased primarily due to higher overall revenues at Ekibastuz offset slightly by higher operating costs. Gross margin in the EMEA region decreased due to the sale of Ottana in Italy and higher fuel costs at Borsod which more than offset the higher overall revenues experienced. The competitive supply gross margin as a percentage of competitive supply revenues increased to 27.9% in 2005 from 23.3% in 2004.

Competitive supply gross margin increased $17 million, or 8%, to $238 million in 2004 from $221 million in 2003 primarily due to higher gross margin contributions from our Latin America and Asia businesses offset slightly by lower gross margin contributions from our North America businesses. Latin America increased due to higher overall revenues from CTSN and Parana in Argentina and the new plant and expansion project in Panama. These increases were partially offset by higher depreciation and fixed costs at our new operations in Panama and higher fuel costs at Parana in Argentina. The increase in Asia gross margin is primarily due to the overall revenue increase at Ekibastuz in Kazakhstan. The decrease in gross margin in North America is primarily due to higher fuel costs at our plants in New York. The competitive supply gross margin as a percentage of competitive supply revenues decreased to 23.3% in 2004 from 25.1% in 2003.

General and administrative expenses

General and administrative expenses increased $39 million, or 21%, to $221 million in 2005 from $182 million 2004. General and administrative expenses as a percentage of total revenues remained at 2% in 2005 and 2004. The increases are primarily the result of higher professional and consulting fees associated with the restatement of the company’s financial statements as well as increased compensation costs.

84




General and administrative expenses increased $25 million, or 16%, to $182 million in 2004 from $157 million in 2003. General and administrative expenses as a percentage of total revenues remained at 2% in 2004 and 2003. The increases are a result of additional corporate personnel and expensing of annual awards of stock options and other long-term incentive compensation. Additional personnel had been added at the parent company to support our key initiatives related to strategy, safety, compliance, information systems and controls. In addition, a higher level of consulting costs were incurred in 2004 and 2003 respectively related to our internal controls reviews as a result of Sarbanes-Oxley and other consulting costs related to implementation of our new corporate initiatives.

Interest expense

Interest expense decreased $36 million, or 2%, to $1,896 million in 2005 from $1,932 million in 2004. Interest expense as a percentage of revenues decreased from 20% in 2004 to 17% for 2005. Interest expense decreased primarily due to the benefits of debt retirements principally in the U.S. and Venezuela and lower interest rate hedge related costs, offset by negative impacts from foreign currency translation in Brazil and higher interest rates at certain of our businesses.

Interest expense decreased $52 million, or 3%, to $1,932 million in 2004 from $1,984 million in 2003. Interest expense as a percentage of revenues decreased from 24% in 2003 to 20% for 2004. Interest expense decreased primarily due to a reduction of debt associated with the Brazil debt restructuring completed at the end of 2003 and debt refinancings and paydowns offset by interest expense from new projects coming on-line in 2004, new project financings and unfavorable foreign currency translation and inflation adjustment impacts.

Interest income

Interest income increased $109 million, or 39%, to $391 million in 2005 from $282 million in 2004. Interest income as a percentage of revenues increased from 3% in 2004 to 4% in 2005. Interest income increased primarily due to favorable foreign currency translation due primarily to the Brazilian real and higher cash and short-term investment balances at certain of our subsidiaries combined with higher short-term interest rates.

Interest income increased $2 million to $282 million in 2004 from $280 million in 2003. Interest income as a percentage of revenues remained constant at 3% in 2004 and 2003. Interest income increased primarily due to favorable foreign currency translation and higher interest on spot market and customer receivables offset by a reclassification adjustment associated with the AES Eletropaulo settlement of certain outstanding municipal receivables.

Other income (expense), net

Net other income increased $7 million to $19 million in 2005 from $12 million in 2004. The increase was primarily due to the reduction of a Brazilian business tax liability no longer required, the favorable impact of foreign currency translation due to the appreciation of the Brazilian real offset by lower gains on debt extinguishment, and increased losses on the sale or disposal of fixed assets.

Net other income decreased $53 million to $12 million in 2004 from $65 million in 2003. The decrease was primarily due to lower gains on debt extinguishments and increased gains on settlement disputes, offset by decreased losses on the sale of assets.

Loss on sale of investments and asset impairments

There was no loss on sale of investments and asset impairment expense in 2005. Loss on sale of investments and asset impairment expense was $45 million in 2004 compared to $201 million in 2003 primarily from fewer impairment charges being taken in 2004. The amount of asset impairment expense for 2004 includes the write-off of $25 million of capitalized costs associated with a fertilizer development

85




project at our Deepwater facility in Texas. This project was terminated in the fourth quarter of 2004. It also includes a $15 million asset impairment charge taken to reflect the net realizable value of an investment in one of our Chinese businesses which we expect to sell.

In 2003, the following actions were taken which led to the recording of impairment charges:

·       In December 2003, we sold an approximate 39% ownership interest in AES Oasis Limited (“AES Oasis”) for cash proceeds of approximately $150 million. The loss realized on the transaction was approximately $36 million before income taxes. AES Oasis is an entity that owns an electric generation project in Oman (AES Barka) and two oil-fired generating facilities in Pakistan (AES Lal Pir and AES Pak Gen). AES Barka, AES Lal Pir, and AES Pak Gen are all contract generation businesses.

·       During the fourth quarter of 2003, we decided to discontinue the development of ZEG, a contract generation plant under construction in Poland. In connection with this decision, we wrote-off our investment in ZEG of approximately $23 million before income taxes.

·       In August 2003, we decided to discontinue the construction and development of AES Nile Power in Uganda (“Bujagali”). In connection with this decision, we wrote-off our investment in Bujagali of approximately $76 million before income taxes in the third quarter of 2003.

·       During the second quarter of 2003, we wrote off capitalized costs of approximately $20 million associated with our development project in Honduras when we elected to offer the project for sale after consideration of existing business conditions and future opportunities. The project consisted of a 580 MW combined-cycle power plant fueled by natural gas, a liquefied natural gas import terminal with storage capacity of one million barrels and transmission lines and line upgrades. The project was sold in January 2004.

·       Additionally, during 2003, we recorded $16 million of other losses which resulted from the sale of assets to third parties, and $29 million of other asset impairment charges taken to reflect the net realizable value of discontinued development projects and other non-recoverable assets.

Goodwill impairment expense

During 2003, we recorded a goodwill impairment charge of $11 million primarily related to all of the goodwill at Atlantis, an aragonite mining operation in the Caribbean. The write-off was due to a reduction in the fair value of the business below its carrying value due to a slow down of operations from the termination of sales contracts that have not been replaced.

Foreign currency transaction (losses) gains on net monetary position

 

 

Years Ended December 31,

 

 

 

  2005  

 

  2004  

 

  2003  

 

 

 

($ in millions)

 

Argentina

 

 

$

(6

)

 

 

$

(7

)

 

 

$

38

 

 

Brazil

 

 

(96

)

 

 

(58

)

 

 

124

 

 

Venezuela

 

 

54

 

 

 

(28

)

 

 

(40

)

 

Dominican Republic

 

 

1

 

 

 

(28

)

 

 

3

 

 

Pakistan

 

 

(22

)

 

 

(17

)

 

 

(15

)

 

Chile

 

 

(20

)

 

 

(3

)

 

 

(16

)

 

Spain

 

 

 

 

 

(18

)

 

 

 

 

Other

 

 

 

 

 

(6

)

 

 

5

 

 

Total(1)

 

 

$

(89

)

 

 

$

(165

)

 

 

$

99

 

 

 

86





(1)          Includes $(122) million, $(114) million and $(15) million of (losses) gains on foreign currency derivative contracts for December 31, 2005, 2004 and 2003, respectively.

The Company recognized foreign currency transaction losses of $89 million in 2005 compared to losses from foreign currency transactions of $165 million in 2004. The $76 million decrease in losses for 2005 as compared to 2004 was primarily related to gains in Venezuela and Dominican Republic partially offset by losses in Brazil and Chile. Foreign currency transaction losses decreased primarily due to lower annual depreciation in 2005 of the Venezuelan bolivar of 10.7% compared to 16.7% in 2004 contributing to $82 million of the change year over year. The Dominican peso depreciated 11.3% in 2005 as compared to a 31.2% appreciation in 2004 contributing to $29 million of the change year over year partially related to one of our Dominican businesses which has a net monetary liability position denominated in the Dominican peso. The Brazilian real appreciated 11.7% during 2005 compared to 7.5% in 2004 offsetting the overall decrease in foreign currency losses by $38 million. The Chilean peso appreciated 15.86% during 2005 compared to no change in 2004. The appreciation increased losses on foreign currency derivative contracts in our Chilean businesses offsetting the overall decrease in foreign currency losses by $14 million.

The Company recognized foreign currency transaction losses of $165 million in 2004 compared to gains from foreign currency transactions of $99 million in 2003. The decrease of $264 million for 2004 as compared to 2003 was primarily related to losses in Brazil, Argentina, and the Dominican Republic. Foreign currency transaction losses increased primarily due to lower annual appreciation in 2004 of the Brazilian real of 7.5% compared to 23.7% in 2003 contributing to $182 million of the change year over year. The Argentine peso devalued 1.7% during 2004 thereby contributing $45 million of losses to the overall change. Additionally, the Dominican peso appreciated 31.2% during 2004. This is related to one of our Dominican businesses which has a net monetary liability position denominated in the Dominican peso. This appreciation in the Dominican peso contributed to the change year over year by $31 million in losses. Foreign currency transaction losses in Spain resulted from the prospective loss of cash flow hedge accounting on foreign currency derivative contracts substantially settling by the end of 2004.

Equity in earnings (losses) of affiliates

Equity in earnings of affiliates increased $6 million, or 9%, to $76 million in 2005 from $70 million in 2004. The increase was primarily due to a plant fire causing lower earnings in 2004 at our affiliate in Canada, improved operations from our affiliates in India and the Netherlands, partially offset by reduced earnings due to higher coal prices at our affiliates in China.

Equity in earnings of affiliates decreased $24 million, or 26%, to $70 million in 2004 from $94 million in 2003. The decrease was primarily due to the sale of our ownership in Medway Power Ltd. in 2003 offset by slight increases from our affiliates in China.

Income taxes

Income tax expense related to continuing operations increased $106 million to $465 million in 2005 from $359 million in 2004. The Company’s effective tax rates were 32% for 2005 and 44% for 2004. The reduction in the 2005 effective tax rate is due, in part, to a reduction in the taxes imposed on earnings of and distributions from our foreign subsidiaries and adjustments derived from the Company’s 2004 income tax returns filed in 2005.

Income tax expense related to continuing operations increased $148 million to $359 million in 2004 from $211 million in 2003. The Company’s effective tax rates were 44% for 2004 and 33% for 2003. The effective tax rate increased in 2004 due to the impact of increasing certain deferred tax valuation allowances and the treatment of unrealized foreign currency gains on U.S. dollar debt held by certain of our Latin American subsidiaries.

87




Minority interest

Minority interest expense, net of tax, increased $162 million to $361 million in 2005 from $199 million in 2004. The increase is primarily due to higher earnings from our Brazilian companies, Cameroon subsidiaries and the 2004 sale of our interest in Oasis.

Minority interest expense, net of tax, increased $60 million to $199 million in 2004 from $139 million in 2003. The increase is primarily due to the sale of stock by our subsidiary in Brazil, the sale of a portion of our interest in Oasis and higher earnings for Ras Laffan allocated to the minority interest since the project came on-line in 2004.

Discontinued operations

Income from operations of discontinued businesses, net of tax, was $34 million in 2004 related to the sales of Whitefield, AES Communications Bolivia, Colombia I, Ede Este, Wolf Hollow, Carbones Internacionales del Cesar S.A. and Granite Ridge. All of these entities had originally been recorded in discontinued operation in either 2003 or 2002. Additionally, in 2004, as a result of filing our 2003 tax returns, previously recorded estimates of the tax effect of the discontinued businesses were adjusted to reflect the final tax returns. As a result, favorable tax adjustments are reflected in the net income of discontinued operations. As of December 31, 2004, no further businesses were classified as discontinued operations.

Loss from operations of discontinued businesses, net of tax, was $787 million in 2003. During 2003, we discontinued certain of our operations including Haripur, Meghnaghat, Barry, Telasi, Mtkvari, Khrami, Drax, Whitefield, AES Communications Bolivia, Granite Ridge, Ede Este, Wolf Hollow, and Colombia I. We closed the sale of Barry in September 2003, Telasi, Mtkvari, and Khrami in August 2003 and Haripur and Meghnaghat in December 2003.

Change in accounting principle

In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47 “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143,” which clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143 “Accounting for Asset Retirement Obligations.” The cumulative effect of the initial application of this Interpretation was recognized as a change in accounting principle in the amount of $2 million, net of income tax benefit of $1 million in 2005.

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” which requires companies to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The items that are part of the scope of SFAS No. 143 for our business primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. The adoption of SFAS No. 143 resulted in a cumulative reduction to income of $2 million, net of income tax effects, in 2003.

On October 1, 2003, we adopted Derivative Implementation Group (“DIG”) Issue C-20 which superseded and clarified DIG Issue C-11 regarding the treatment of power sales contracts. As a result of this adoption, we had a Power Purchase Agreement (“PPA”) that was previously treated as a “normal sales and purchase contract” that was treated as a derivative instrument under SFAS No. 133 and marked-to-market upon adoption of DIG Issue C-20. The prospective method of accounting for this PPA requires no further mark-to-market treatment, and the initial mark-to-market adjustment will be subsequently amortized over the life of the contract. The adoption of DIG Issue C-20, effective October 1, 2003 resulted in a cumulative increase to income of $43 million, net of income tax effects, in 2003.

CAPITAL RESOURCES AND LIQUIDITY

Overview

We are a holding company that conducts all of our operations through subsidiaries. We have, to the extent achievable, utilized non-recourse debt to fund a significant portion of the capital expenditures and

88




investments required to construct and acquire our electric power plants, distribution companies and related assets. This type of financing is non-recourse to other subsidiaries and affiliates and to us (as parent company), and is generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. At December 31, 2005, we had $4.9 billion of recourse debt and $12.8 billion of non-recourse debt outstanding. For more information on our long-term debt see Note 8 to the Consolidated Financial Statements included in Item 8 of this Form 10-K/A.

In addition to the non-recourse debt, if available, we, as the parent company, provide a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition. These investments have generally taken the form of equity investments or loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations and/or the proceeds from our issuances of debt, common stock, and other securities as well as proceeds from the sales of assets. For example in March 2006, AES sold its interest in Kingston for $110 million. Similarly, in certain of our businesses, we may provide financial guarantees or other credit support for the benefit of lenders or counterparties who have entered into contracts for the purchase or sale of electricity with our subsidiaries. In such circumstances, if a subsidiary defaults on its payment or supply obligation, we will be responsible for the subsidiary’s obligations up to the amount provided for in the relevant guarantee or other credit support.

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

As a result of AES parent’s below-investment-grade rating, counter-parties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, we may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. We may not be able to provide adequate assurances to such counter-parties. In addition, to the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At December 31, 2005, we had provided outstanding financial and performance related guarantees or other credit support commitments to or for the benefit of our subsidiaries, which were limited by the terms of the agreements, in an aggregate of approximately $802 million (including those collateralized by letters of credit and other obligations discussed below). Management believes that cash on hand, along with cash generated through operations, and our financing availability will be sufficient to fund normal operations, capital expenditures, and debt service requirements.

At December 31, 2005, we had $294 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. All of these letters of credit were provided under our revolver. We pay letter of credit fees ranging from 0.15% to 2.75% per annum on the outstanding amounts. In addition, we had $1 million in surety bonds outstanding at December 31, 2005.

Many of our subsidiaries including those in Central and South America depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may adversely affect those subsidiaries’ financial condition and results of operations. In addition, changes in the timing of tariff increases or delays in the regulatory

89




determinations under the relevant concessions could affect the cash flows and results of operations of our businesses in Brazil and Venezuela.

Capital Expenditures

We spent $1.1 billion, $0.9 billion and $1.2 billion on capital expenditures in 2005, 2004 and 2003, respectively. We anticipate capital expenditures during 2006 to approximate between $1.7 billion and $1.8 billion. Planned capital expenditures include new project construction costs, environmental pollution control construction and expenditures for existing assets to increase their useful lives. Capital expenditures for 2006 are expected to be financed using internally generated cash provided by operations and project level financing and possibly debt or equity financing at the AES parent company.

Cash Flows

At December 31, 2005, we had $1,390 million of cash and cash equivalents representing an increase of $109 million from December 31, 2004.

Operating Activities

Net cash provided by operating activities totaled $2,165 million during 2005, which was $594 million greater than 2004 due to a $360 million increase in net earnings (adjusted for non-cash items), a $243 million increase in other assets and liabilities, and a decrease in working capital of $9 million. 

The $28 million increase in adjustments to net income (loss) from $1,457 million in 2004 to $1,485 million in 2005 is primarily due to increased depreciation and amortization, minority interest expense and a loss on discontinued operations in 2004 which did not occur in 2005.  These increases were offset by decreases in the provision for deferred taxes and realized gains on investments in Venezuela and Brazil.  There was a gain on the sale of emission allowances in New York and additional amortization of deferred financing costs due to new debt issuances. In addition, there was a reversal of a contingent liability in 2005 at Brazil due to the expiration of the statute of limitations.

The $243 million increase in other assets and liabilities is primarily due to an increase in derivative liabilities, a decrease in a long-term receivable due to a reserve adjustment made in Brazil, and movements in regulatory liabilities. Regulatory liabilities increased due to lower costs than anticipated in the tariff as well as the market performance of the dollar. These increases were partially offset by settlement proceeds Gener received in 2004.

The $9 million decrease in working capital is due increases in inventory and accounts payable and accrued liabilities offset by decreases in accounts receivable prepaid expenses and other current assets.

 

 

2005

 

2004

 

Change

 

 

 

(in millions)   

 

Decrease (increase) in accounts receivable

 

$

26

 

 

$

(128

)

 

 

$

154

 

 

Increase in inventory

 

(73

)

 

(33

)

 

 

(40

)

 

Decrease in prepaid expenses and other current assets

 

41

 

 

7

 

 

 

34

 

 

(Increase) decrease in accounts payable and accrued liabilities

 

(79

)

 

78

 

 

 

(157

)

 

Total working capital

 

$

(85

)

 

$

(76

)

 

 

$

(9

)

 

 

Accounts receivable decreased in the current year due to enhanced collection efforts at Eletropaulo and Ras Laffan, partially offset by an increase in accounts receivable at our New York plant due to higher energy prices.

90




Inventory increased in the current year due to the resumption of normal activity in the Dominican Republic in the current year after a period of inactivity in the prior year; an increase in the price of coal at IPALCO and an increase in the purchase of fuel at Tisza offset by a reduction of inventory at Alicura.  

Prepaid expenses and other current assets decreased due to greater amortization of regulatory assets at Eletropaulo as the pass through costs are collected from the customers and lower VAT accruals at Cartagena for contractor invoices partially offset by higher year end purchase levels at SONEL.

Accounts payable and other liabilities declined in the current year mainly due to payments to Ras Laffan contractors, a reduction in payables to suppliers at SONEL and more timely payments at Barka. In addition, tax liabilities were reduced at IPALCO and other subsidiaries in the prior year due to our tax restatement.

Investing Activities

Net cash used in investing activities totaled $873 million during 2005 compared to $1,025 million during 2004. The cash used in investing activities includes $1,143 million for property additions and $85 million for acquisitions. This was offset by the proceeds from the sales of assets of $26 million, the proceeds from the sale of emission allowances of $41 million, the net sale of short term investments of $152 million and a decrease in restricted cash, debt service reserves and other assets and other investing of $136 million.

Property additions increased $251 million during 2005 as compared to 2004 due to additional expenditures of $103 million at Cartagena, our construction project in Spain, $137 million for Buffalo Gap, our wind power project in Texas, and $50 million in Brazil for the purchase and capitalized costs associated with the implementation of the enterprise resource planning software. Offsetting the increase in property additions is decreased spending of $45 million at Ras Laffan in Qatar due to large capital expenditures incurred prior to going into commercial operations at the end of 2004. The increase in property additions is also offset by a reduction in spending on environmental compliance projects of approximately $42 million at IPALCO in the U.S.

In the first quarter of 2005, we spent a total of $85 million related to the purchase of the SeaWest wind development business in the U.S., including $60 million for the existing net assets of the business and an additional $25 million advance payment for pre-construction costs for SeaWest's development of Buffalo Gap.

The increase in the net sales of short-term investments of $136 million during 2005 as compared to 2004 was primarily due to the release of collateral at EDC in Venezuela of $145 million which was as a result of a repayment of approximately $264 million of related debt.  This increase was offset by a decrease in sales of short-term investments at Gener of $29 million due to higher liquidations in the prior year to repay debt.

The decrease in the net proceeds from the sale of assets of $37 million during 2005 as compared to 2004 was primarily due to the sale in the prior year of the Nacimiento power plant at Gener for $22 million, the sale of discontinued businesses (primarily Mountainview) in 2004 for $13 million, net of expenses, as well as the sale of a substation property at IPALCO for $13 million in 2004.  These decreases were partially offset by increases at Brazil.

The change in restricted cash balances decreased $90 million during 2005 as compared to 2004 primarily due to a decrease in restricted cash of $127 million at Ras Laffan for construction payments made to the contractor, of $17 million at EDC for the release of restricted cash associated with letters of credit which were paid in September 2005, of $23 million due to debt related repayments at Gener and of $16 million due to debt related repayments at Ebute.  These decreases were offset by a $58 million increase

91




at the New York plants due to increased emission sales as well as $35 million increase at Barka due to major maintenance on their gas turbines planned for 2007.

The change in debt service reserves and other assets decreased $219 million in 2005 as compared to 2004 primarily due to the payment of $254 million of construction costs from a reserve account related to our Cartagena construction project in Spain, offset by an increase of $20 million in debt service reserves at our Ebute plant in Nigeria required to satisfy the debt requirements on $120 million of financing.

The change in other investing balances decreased $39 million primarily due to the collection of a receivable for a minority interest buyout in our contract generation segment in Asia.

Financing Activities

Net cash used in financing activities was $1,195 million for the year ended December 31, 2005 as compared to $936 million during the same period in 2004. The significant change was due to a decrease in debt, net of issuances, of $1,052 million in 2005 versus $734 million in 2004.

Debt issuances decreased by $1,051 million during the twelve months ended December 31, 2005 primarily due to parent company recourse debt issuances of $491 million in 2004 compared to $5 million in 2005.  The remaining decreases were attributable to our subsidiaries.  At Gener in Chile, there were bond issuances of approximately $570 million in 2004 and other debt refinancings of approximately $253 million during 2004 compared to $119 million in the current year.  At Cartagena in Spain, there was a $166 million decrease over the prior year in project debt financing.  At EDC in Venezuela, there was a decrease of $353 million over the prior year at EDC due to the issuance of debt in local currency in 2004 as part of its debt restructuring. These reductions in debt issuances were offset by increased borrowings at Eletropaulo of $656 million. Brazil issued a $200 million U.S. dollar equivalent bond issuance in June 2005, $348 million and $109 million of debentures in September and December 2005, respectively. The issuances in 2005 were used to pay off higher interest-bearing debt.

Debt repayments during the twelve months ended December 31, 2005 were $2,941 million compared to $3,674 million during the same period in 2004. The decrease of approximately $733 million was mainly due to repayment of corporate recourse debt of $1,140 million in 2004 compared to $259 million in 2005. The 2005 payments include the redemption of all of the Company’s 8.5% Senior Subordinated Notes and its 4.5% Convertible Junior Subordinated Debentures. In addition, Gener decreased debt repayments in 2005 by $907 million due to the completion of their debt restructuring and refinancing that occurred during 2004. This was offset by increased debt and debenture payments at Eletropaulo and Tiete in Brazil of $727 million in 2005 to pay off higher interest-bearing debt; increased debt repayments at Andres in the Dominican Republic of $112 million due to the debt restructuring in 2005 whereby the proceeds received were used to pay off short term debt; and increased debt repayments at EDC in Venezuela of $105 million due to the repayment of  200 million Euro debt in March 2005 and the repayment of debt in local currency of $66 million.

Payments for deferred financing costs decreased $88 million during the twelve months ended December 31, 2005 due to parent company debt issuances in the prior year that did not occur at the same level in the current year, higher deferred financing costs at Gener due to the size of the debt offering in 2004, higher deferred financing costs in 2004 at Brazil due to their reprofiling of debt in 2004, and higher deferred financing costs at Ebute due to the $120 million refinancing arrangement in September 2004.

92




Contractual Obligations

A summary of the Company’s contractual obligations, commitments and other liabilities as of December 31, 2005 is presented in the table below (in millions).

Contractual Obligations

 

 

 

Total

 

Less than
1 year

 

2-3
years

 

4-5
years

 

After
5 years

 

Footnote
Reference

 

Debt Obligations(1)

 

$

17,706

 

 

$

1,798

 

 

$

2,733

 

$

3,104

 

$

10,071

 

 

8

 

 

Interest payments on long-term debt(2)

 

9,696

 

 

1,352

 

 

2,551

 

2,019

 

3,774

 

 

n/a

 

 

Capital Lease Obligations(3)

 

75

 

 

5

 

 

9

 

7

 

54

 

 

10

 

 

Other Long-term Liabilities Reflected on AES’s Consolidated Balance Sheet under GAAP(4)

 

136

 

 

8

 

 

44 

 

21

 

63

 

 

n/a

 

 

Operating Lease Obligations(5)

 

146

 

 

12

 

 

22

 

20

 

92

 

 

10

 

 

Sale Leaseback Obligations(6)

 

1,376

 

 

61

 

 

125

 

128

 

1,062

 

 

10

 

 

Electricity Obligations(7)

 

7,809

 

 

1,088

 

 

2,412

 

2,766

 

1,543

 

 

10

 

 

Fuel Obligations(8)

 

7,605

 

 

803

 

 

1,269

 

982

 

4,551

 

 

10

 

 

Other(9)

 

1,009

 

 

196

 

 

180

 

142

 

491

 

 

 

 

 

Total

 

$

45,558

 

 

$

5,123

 

 

$

9,346

 

$

9,188

 

$

21,901

 

 

 

 

 


(1)          Debt Obligations—Debt obligations includes non-recourse debt and recourse debt presented on our consolidated financial statements. Non-recourse debt borrowings are not a direct obligation of The AES Corporation, the parent company, and are 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 subsidiaries. These non-recourse financings include structured project financings, acquisition financings, working capital facilities and all other consolidated debt of the subsidiaries. Recourse debt borrowings are the borrowings of The AES Corporation, the parent company. Note 8 to the Consolidated Financial Statements included in Item 8 of this Form 10-K provides disclosure of these obligations.

(2)          Interest payments—Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2005 and do not reflect anticipated future refinancing, early redemptions, new debt issuances or certain interest on liabilities other than debt. Variable rate interest obligations are estimated based on rates as of December 31, 2005.

(3)          Capital Lease Obligations—One of AES’s subsidiaries, AES Indian Queens Power Limited, conducts a major part of its operations from leased facilities. The plant lease is for 25 years expiring in 2022. In addition, several AES subsidiaries lease operating and office equipment, and vehicles. The total capital lease obligation of $75 million represents the future minimum lease commitments. The present value of the capital lease obligations included in the consolidated balance sheet totals $44 million. Imputed interest for these obligations total $31 million.

(4)          Other long-term liabilities reflected on AES’s consolidated balance sheet under GAAP include only those amounts in long-term liabilities reflected on the Company’s consolidated balance sheet that are contractual obligations. These amounts do not include (1) current liabilities on the consolidated balance sheet, (2) any taxes or regulatory liabilities, (3) contingencies, (4) pension and other than pension employee benefit liabilities (see Note 12 to the Consolidated Financial Statements included in Item 8 of this Form 10-K).

(5)          As of December 31, 2005, the Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. These amounts exclude amounts related to the sale/leaseback discussed below in item (6).

(6)          In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas (“NYSEG”). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the

93




unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment.

(7)          Some of our operating subsidiaries have entered into contracts for the purchase of electricity from third parties.

(8)          Some of our operating subsidiaries have entered into various contracts for the purchase of fuel subject to termination only in certain limited circumstances.

(9)          Amounts relate to other contractual obligations where the Company has an agreement to purchase goods or services that is enforceable and legally binding on the Company that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Included in the total amount is (1) $833 million of other contracts denoted in Note 10 to the Consolidated Financial Statements in Item 8 of this Form 10-K, (2) $84 million of costs related to supply of spare parts and maintenance, and (3) $92 million related to other service and fuel contracts. These amounts also exclude planned capital expenditures that are not contractually obligated.

Parent Company Liquidity

Because of the non-recourse nature of most of our indebtedness, we believe that unconsolidated parent company liquidity is an important measure of liquidity. Our principal sources of liquidity at the parent company level are:

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

·       proceeds from debt and equity financings at the parent company level, including borrowings under our Revolving Bank Loan; and

·       proceeds from asset sales.

Our cash requirements at the parent company level are primarily to fund:

·       interest and preferred dividends;

·       principal repayments of debt;

·       acquisitions;

·       construction commitments;

·       other equity commitments;

·       taxes; and

·       parent company overhead and development costs.

Since 2002, the Company has undertaken various initiatives to improve the credit and risk profile of both the parent and the consolidated company while continuing to pursue disciplined growth.

On June 1, 2005, the Company redeemed all outstanding 8.5% Senior Subordinated Notes due 2007, at a redemption price of 101.417%, and an aggregate principal amount of approximately $112 million.

On June 23, 2005, the Company amended its $450 million Senior Secured Bank Facilities. The interest rate on the $450 million Revolving Bank Loan was reduced to the London Interbank Offered Rate (“LIBOR”) plus 1.75%. Previously, the rate was LIBOR plus 2.5%. In addition, the Revolving Bank Loan maturity was extended from 2007 to 2010. The interest rate on the term $200 million Senior Secured Term Loan was also reduced to LIBOR plus 1.75%, from LIBOR plus 2.25%, while its maturity in 2011 remains unchanged. On September 30, 2005, the Company upsized the Revolving Bank Loan to a total commitment amount of $650 million from $450 million. As of December 31, 2005, $356 million was available from the $650 million Revolving Bank Loan. As of March 31, 2006, we are in default under our

94




senior bank credit facility due to the restatement of our 2003 financial statements. As a result, the debt under our senior bank credit facility has been classified as current on our balance sheet as of December 31, 2005. In addition, we need to obtain a waiver of this default and an amendment of the representation relating to our 2003 financial statements before we will be able to borrow additional funds under our revolving credit facility. The Company is pursuing an amendment and waiver with its senior bank lenders and expects to obtain it in the near term.

On August 15, 2005, the Company repaid at maturity all outstanding 4.5% Convertible Junior Subordinated Debentures (“the Debentures”) at par for an aggregate principal amount of $142 million.

During the first half of 2005, the Company also funded the purchase of the SeaWest wind development business and posted letters of credit to support ongoing construction and operating activities.

On March 3, 2006, the Company redeemed all of its outstanding 8.875% Senior Subordinated Debentures due 2027 (approximately $115 million aggregate principal amount). The redemption was made pursuant to the optional redemption provisions of the indenture governing the Debentures. The Debentures were redeemed at a redemption price equal to 100% of the principal amount thereof, plus a make-whole premium determined in accordance with the terms of the indenture, plus accrued and unpaid interest up to the redemption date.

On March 31, 2006, AES entered into a $600 million senior unsecured credit facility agreement with a maturity date of March 31, 2010. The credit facility is a syndicated loan and letter of credit facility lead arranged by Merrill Lynch. The credit facility will be used for general corporate purposes and to provide letters of credit to support AES’s investment commitment as well as the underlying funding for the equity portion of its investment in AES Maritza East 1 on an intermediate-term basis. AES Maritza East 1 is a coal-fired generation project that is expected to begin construction soon. Additional non-recourse financing has been committed to begin construction of AES Maritza East 1.

Parent liquidity was as follows at December 31, 2005, 2004 and 2003:

 

 

2005

 

2004

 

2003

 

 

 

(in millions)

 

Cash and cash equivalents

 

$

1,390

 

$

1,281

 

$

1,663

 

Less: Cash and cash equivalents at subsidiaries

 

1,128

 

994

 

798

 

Parent cash and cash equivalents

 

262

 

287

 

865

 

Borrowing available under revolving credit facility

 

356

 

352

 

180

 

Cash at qualified holding companies

 

6

 

4

 

25

 

Total parent liquidity .

 

$

624

 

$

643

 

$

1,070

 

 

Our parent recourse debt at year-end was approximately $4.9 billion, $5.2 billion, and $5.9 billion in 2005, 2004 and 2003, respectively. Our contingent contractual obligations were $802 million, $559 million, and $605 million at the end of 2005, 2004 and 2003, respectively.

The following table sets forth our parent company contingent contractual obligations as of December 31, 2005:

Contingent contractual obligations

 

 

 

Amount

 

Number of
Agreements

 

Exposure Range for
Each Agreement

 

 

 

($ in millions)

 

 

 

 

 

Guarantees

 

 

$

507

 

 

 

34

 

 

 

<$1 - $100

 

 

Letters of credit—under the Revolver

 

 

294

 

 

 

18

 

 

 

<$1 - $  74

 

 

Surety bonds

 

 

1

 

 

 

1

 

 

 

$1

 

 

Total

 

 

$

802

 

 

 

53

 

 

 

 

 

 

 

95




We have a varied portfolio of performance related contingent contractual obligations. Amounts related to the balance sheet items represent credit enhancements made by us at the parent company level and by other third parties for the benefit of the lenders associated with the non-recourse debt recorded as liabilities in the accompanying consolidated balance sheets. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power sales agreements for projects in development, under construction and operating. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2006 or beyond that are not recorded on the balance sheet, many of the events which would give rise to such an obligation are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

While we believe that our sources of liquidity will be adequate to meet our needs through the end of 2006, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, the operating and financial performance of our subsidiaries, exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our project subsidiaries’ ability to declare and pay cash dividends to us (at the parent company level) is subject to certain limitations contained in project loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the parent company level with a Revolving Bank Loan of $650 million. We did not have any outstanding borrowings under the revolving credit facility at December 31, 2005. At December 31, 2005, we had $294 million of letters of credit outstanding under the Revolving Bank Loan.

Various debt instruments at the parent company level, including our Senior Secured Credit Facilities contain certain restrictive covenants. The covenants provide for, among other items:

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

·       restrictions on dividends and redemptions and payments of unsecured and subordinated debt and the use of proceeds;

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

·       maintenance of certain financial ratios; and

·       timely filing of reports with SEC (of which we had defaults with respect to our 2nd and 3rd quarter 2005 Form 10-Qs and this annual report on Form 10-K.)

Non-Recourse Debt Financing

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

·       reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the parent level during the time period of any default;

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

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

96




·       triggering defaults in our outstanding debt at the parent level. For example, our Senior Secured Credit Facilities and outstanding debt securities at the parent level include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the parent level includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in the accompanying consolidated balance sheets related to such defaults was $138 million at December 31, 2005.

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

Off Balance Sheet Arrangements

In May 1999, one of our subsidiaries acquired six electric generating plants from New York State Electric and Gas. Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. We have accounted for this transaction as a sale/leaseback transaction with operating lease treatment. Accordingly, we have not recorded these assets on our books and we expense periodic lease payments, which amounted to $54 million in 2005, as incurred. The lease obligations bear an imputed interest rate of approximately 9% which approximates fair market value. We are not subject to any additional liabilities or contingencies if the arrangement terminates, and we believe that the dissolution of the off-balance sheet arrangement would have minimal effects on our operating cash flows. The terms of the lease include restrictive covenants such as the maintenance of certain coverage ratios. As of December 31, 2005, we fulfilled a lease requirement on the subsidiary’s behalf by funding an additional liquidity account, as defined in the lease agreement, in the form of a $36 million letter of credit, issued under our Revolving Bank Loan. However, the subsidiary is required to replenish or replace this letter of credit in the event it is drawn upon or requires replacement. Historically, the plants have satisfied the restrictive covenants of the lease, and there are no known trends or uncertainties that would indicate that the lease will be terminated early. See Note 10 to the Consolidated Financial Statements included in Item 8 of this Form 10-K for a more complete discussion of this transaction.

IPL, a subsidiary of the Company, formed IPL Funding Corporation (“IPL Funding”) in 1996 to purchase, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL. IPL Funding is not consolidated by IPL or IPALCO since it meets requirements set forth in SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” to be considered a qualified special-purpose entity. IPL Funding has entered into a purchase facility with unrelated parties (“the Purchasers”) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million of the receivables purchased from IPL. During 2005, this agreement was extended through May 30, 2006. As of December 31, 2005 and 2004, the aggregate amount of receivables IPL has sold to IPL Funding and IPL Funding has sold to the Purchasers pursuant to this facility was $50 million. Accounts receivable on the Company’s balance sheets are stated net of the $50 million sold.

97




The net cash flows between IPL and IPL Funding are limited to cash payments made by IPL to IPL Funding for interest charges and processing fees. These payments totaled approximately $2 million, $1 million and $1 million for each of the years ended December 31, 2005, 2004 and 2003, respectively. IPL retains servicing responsibilities through its role as a collection agent for the amounts due on the purchased receivables. IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of or otherwise relating to the purchase agreement, subject to certain limitations as defined in purchase agreement. The transfers of such accounts receivable from IPL to IPL Funding are recorded as sales; however, no gain or loss is recorded on the sale.

Under the receivables purchase facility, if IPL fails to maintain certain financial covenants regarding interest coverage and debt to capital, it would constitute a “termination event.” As of December 31, 2005, IPL was in compliance with such covenants.

As a result of IPL’s current credit rating, the facility agent has the ability to (i) replace IPL as the collection agent; and (ii) declare a “lock-box” event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. A termination event would also (i) give the facility agent the option to take control of the lock-box account, and (ii) give the Purchasers the option to discontinue the purchase of new receivables and cause all proceeds of the purchased receivables to be used to reduce the Purchaser’s investment and to pay other amounts owed to the Purchasers and the facility agent. This would have the effect of reducing the operating capital available to IPL by the aggregate amount of such purchased receivables (currently $50 million).

ITEM 7A.         QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

We are exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. We often utilize financial instruments and other contracts to hedge against such fluctuations. We also utilize financial and commodity derivatives for the purpose of hedging exposures to market risk. We generally do not enter into derivative instruments for trading or speculative purposes.

Interest Rate Risks

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable-rate debt, fixed-rate debt and trust preferred securities, as well as interest rate swap and option agreements. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.

Foreign Exchange Rate Risk

We are exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in U.S. dollars or currencies other than their own functional currencies. Primarily, we are exposed to changes in the U.S. dollar/Brazilian real exchange rate, the U.S. dollar/Venezuelan bolivar exchange rate and the U.S. dollar/Argentine peso exchange rate. Whenever possible, these subsidiaries and affiliates have

98




attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forward and swap agreements, where possible, to manage our risk related to certain foreign currency fluctuations.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, natural gas and coal. Although we primarily consist of businesses with long-term contracts or retail sales concessions, a portion of our current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These competitive supply businesses subject our results of operations to the volatility of electricity, coal and natural gas prices in competitive markets. Our businesses hedge certain aspects of their “net open” positions in the U.S. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy involves the use of commodity forward contracts, futures, swaps and options as well as long-term supply contracts for the supply of fuel and electricity.

Value at Risk

One approach we use to assess our risk and our subsidiaries’ risk is value at risk (“VaR”). VaR measures the potential loss in a portfolio’s value due to market volatility, over a specified time horizon, stated with a specific degree of probability. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. We adopted the VaR approach because we feel that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of a component of our risk exposure. Our use of VaR requires a number of key assumptions, including the selection of a confidence level for expected losses, the holding period for liquidation and the treatment of risks outside the VaR methodology, including liquidity risk and event risk. VaR, therefore, is not necessarily indicative of actual results that may occur. Additionally, VaR represents changes in fair value and not the economic exposure to AES and its affiliates.

Because of the inherent limitations of VaR, including those specific to Analytic VaR, in particular the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform stress and scenario analyses to estimate the economic impact of market changes to our portfolio of businesses. We use these results to complement the VaR methodology.

In addition, the relevance of the VaR described herein as a measure of economic risk is limited and needs to be considered in light of the underlying business structure. The interest rate component of VaR is due to changes in the fair value of our fixed rate debt instruments and interest rate swaps. These instruments themselves would expose a holder to market risk; however, utilizing these fixed rate debt instruments as part of a fixed price contract generation business mitigates the overall exposure to interest rates. Similarly, our foreign exchange rate sensitive instruments are often part of businesses which have revenues denominated in the same currency, thus offsetting the exposure.

We have performed a company-wide VaR analysis of all of our material financial assets, liabilities and derivative instruments. The VaR calculation incorporates numerous variables that could impact the fair value of our instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. We express Analytic VaR herein as a dollar amount of the potential loss in the fair value of our portfolio based on a 95% confidence level and a one-day holding period. Our commodity analysis is an Analytic VaR utilizing a variance-covariance analysis within the commodity transaction management system.

99




During the year ended December 31, 2005, our average daily VaR for interest rate-sensitive instruments was $114 million. The daily VaR for interest rate-sensitive instruments was highest at the end of the second quarter, and equaled $129 million. The daily VaR for interest rate-sensitive instruments was lowest at the end of the first quarter, and equaled $101 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items.

During the year ended December 31, 2005, our average daily VaR for foreign exchange rate-sensitive instruments was $34 million. The daily VaR for foreign exchange rate-sensitive instruments was highest at the end of the second quarter, and equaled $38 million. The daily VaR for foreign exchange rate-sensitive instruments was lowest at the end of the fourth quarter, and equaled $30 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items.

During the year ended December 31, 2005, our average daily VaR for commodity price-sensitive instruments was $19 million. The daily VaR for commodity price-sensitive instruments was highest at the end of the third quarter, and equaled $24 million. The daily VaR for commodity price-sensitive instruments was lowest at the end of the first quarter, and equaled $10 million. These amounts include the financial instruments that serve as hedges and do not include the underlying physical assets or contracts that are not permitted to be settled in cash.

Trending daily VaR can provide insight into market volatility or consistency of a company’s financial strategy. The table below details the average daily VaR for AES foreign exchange, interest rates and commodity activities over the past three years. In regards to interest rates, AES has made efforts during 2004 and 2005 to increase the percentage of its portfolio of fixed versus floating rate debt. This has in part led to the increase in VaR from $99 million in 2003 to $114 million in 2005. The AES commodity VaR is reported for financially settled derivative products at its competitive supply business in New York State. From 2004 to 2005 there has been an increase in term and magnitude of hedging activity which has led to the increase in the daily VaR from $9 million to $19 million.

Average Daily VAR

 

 

 

2005

 

2004

 

2003

 

 

 

(in millions)

 

Foreign Exchange

 

$

34

 

$

27

 

 

$

34

 

 

Interest Rate

 

$

114

 

$

110

 

 

$

99

 

 

Commodity

 

$

19

 

$

9

 

 

$

6

 

 

 

 

100




ITEM 8.                FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
The AES Corporation
Arlington, VA

We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedules listed on pages S-1 to S-9 of the Company’s annual report on Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The AES Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, in 2005 the Company adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” effective December 15, 2005. In 2003, the Company changed its method of accounting for certain contracts for the purchase or sale of electricity effective October 1, 2003 to conform to Derivative Implementation Group Issue C-20; the Company changed its method of accounting for certain contracts for the purchase or sale of electricity effective April 1, 2003 to conform to Derivative Implementation Group Issue C-15; the Company also changed its method of accounting for stock-based compensation effective January 1, 2003, to conform to the fair value recognition provisions of Statement of Financial Accounting Standard (SFAS) No. 123, as amended by Statement of Financial Accounting Standard No. 148, prospectively to all employee awards granted, modified or settled after January 1, 2003, and the Company adopted Statement of SFAS No. 143, “Accounting for Asset Retirement Obligations” effective January 1, 2003.

As discussed in Note 1 to the consolidated financial statements, the accompanying 2004 and 2003 consolidated financial statements and financial statement schedules have been restated.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 4, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an adverse opinion on the effectiveness of the Company’s internal control over financial reporting because of material weaknesses.

/s/ DELOITTE & TOUCHE LLP

McLean, VA
April 4, 2006

101




THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2005 AND 2004

 

 

     2005     

 

   2004   

 

 

 

 

 

(Restated)(1)

 

 

 

(in millions, except share data)

 

ASSETS

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

$

1,390

 

 

 

$

1,281

 

 

Restricted cash

 

 

420

 

 

 

395

 

 

Short-term investments

 

 

203

 

 

 

268

 

 

Accounts receivable, net of reserves of $279 and $303 respectively

 

 

1,615

 

 

 

1,530

 

 

Inventory

 

 

460

 

 

 

418

 

 

Receivable from affiliates

 

 

2

 

 

 

8

 

 

Deferred income taxes—current

 

 

267

 

 

 

218

 

 

Prepaid expenses

 

 

119

 

 

 

87

 

 

Other current assets

 

 

756

 

 

 

781

 

 

Total current assets

 

 

5,232

 

 

 

4,986

 

 

NONCURRENT ASSETS

 

 

 

 

 

 

 

 

 

Property, Plant and Equipment:

 

 

 

 

 

 

 

 

 

Land

 

 

860

 

 

 

788

 

 

Electric generation and distribution assets

 

 

22,440

 

 

 

21,729

 

 

Accumulated depreciation

 

 

(6,087

)

 

 

(5,259

)

 

Construction in progress

 

 

1,441

 

 

 

919

 

 

Property, plant and equipment, net

 

 

18,654

 

 

 

18,177

 

 

Other assets:

 

 

 

 

 

 

 

 

 

Deferred financing costs, net of accumulated amortization of $222 and $174, respectively

 

 

294

 

 

 

343

 

 

Investment in and advances to affiliates

 

 

670

 

 

 

655

 

 

Debt service reserves and other deposits

 

 

611

 

 

 

737

 

 

Goodwill, net

 

 

1,428

 

 

 

1,419

 

 

Deferred income taxes—noncurrent

 

 

807

 

 

 

774

 

 

Other assets

 

 

1,736

 

 

 

1,832

 

 

Total other assets

 

 

5,546

 

 

 

5,760

 

 

TOTAL ASSETS

 

 

$

29,432

 

 

 

$

28,923

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

 

 

 

 

Accounts payable

 

 

$

1,104

 

 

 

$

1,081

 

 

Accrued interest

 

 

382

 

 

 

335

 

 

Accrued and other liabilities

 

 

2,122

 

 

 

1,707

 

 

Recourse debt-current portion

 

 

200

 

 

 

142

 

 

Non-recourse debt-current portion

 

 

1,598

 

 

 

1,619

 

 

Total current liabilities

 

 

5,406

 

 

 

4,884

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

 

 

 

 

Non-recourse debt

 

 

11,226

 

 

 

11,817

 

 

Recourse debt

 

 

4,682

 

 

 

5,010

 

 

Deferred income taxes-noncurrent

 

 

721

 

 

 

678

 

 

Pension liabilities and other post-retirement liabilities

 

 

857

 

 

 

891

 

 

Other long-term liabilities

 

 

3,280

 

 

 

3,382

 

 

Total long-term liabilities

 

 

20,766

 

 

 

21,778

 

 

Minority Interest

 

 

1,611

 

 

 

1,305

 

 

Commitments and Contingent Liabilities (see Notes 10 and 11)

 

 

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

Common stock ($.01 par value, 1,200,000,000 shares authorized; 655,882,836 and 650,093,402 shares issued and outstanding at December 31, 2005 and 2004, respectively) 

 

 

7

 

 

 

7

 

 

Additional paid-in capital

 

 

6,517

 

 

 

6,434

 

 

Accumulated deficit

 

 

(1,214

)

 

 

(1,844

)

 

Accumulated other comprehensive loss

 

 

(3,661

)

 

 

(3,641

)

 

Total stockholders’ equity

 

 

1,649

 

 

 

956

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

$

29,432

 

 

 

$

28,923

 

 


(1)             See Note 1 related to the restated consolidated financial statements.

See notes to consolidated financial statements.

102




THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

 

 

2005

 

2004

 

2003

 

 

 

 

 

(Restated)(1)

 

(Restated)(1)

 

 

 

(in millions, except per share data)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Regulated

 

$

5,737

 

 

$

4,897

 

 

 

$

4,425

 

 

Non-Regulated

 

5,349

 

 

4,566

 

 

 

3,988

 

 

Total revenues

 

11,086

 

 

9,463

 

 

 

8,413

 

 

Cost of Sales:

 

 

 

 

 

 

 

 

 

 

 

Regulated

 

(4,500

)

 

(3,781

)

 

 

(3,449

)

 

Non-Regulated

 

(3,408

)

 

(2,900

)

 

 

(2,505

)

 

Total cost of sales

 

(7,908

)

 

(6,681

)

 

 

(5,954

)

 

Gross margin

 

3,178

 

 

2,782

 

 

 

2,459

 

 

General and administrative expenses

 

(221

)

 

(182

)

 

 

(157

)

 

Interest expense

 

(1,896

)

 

(1,932

)

 

 

(1,984

)

 

Interest income

 

391

 

 

282

 

 

 

280

 

 

Other income, net

 

19

 

 

12

 

 

 

65

 

 

Loss on sale of investments and asset impairment expense

 

 

 

(45

)

 

 

(201

)

 

Goodwill impairment expense

 

 

 

 

 

 

(11

)

 

Foreign currency transaction (losses) gains on net monetary position 

 

(89

)

 

(165

)

 

 

99

 

 

Equity in earnings of affiliates

 

76

 

 

70

 

 

 

94

 

 

INCOME BEFORE INCOME TAXES AND MINORITY INTEREST

 

1,458

 

 

822

 

 

 

644

 

 

Income tax expense

 

(465

)

 

(359

)

 

 

(211

)

 

Minority interest expense

 

(361

)

 

(199

)

 

 

(139

)

 

INCOME FROM CONTINUING OPERATIONS

 

632

 

 

264

 

 

 

294

 

 

Income (loss) from operations of discontinued businesses (net of income tax benefit of $0, $36 and $75, respectively)

 

 

 

34

 

 

 

(787

)

 

INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE

 

632

 

 

298

 

 

 

(493

)

 

Cumulative effect of accounting change (net of income tax (benefit) expense of $(1), $0 and $22, respectively)

 

(2

)

 

 

 

 

41

 

 

Net income (loss)

 

$

630

 

 

$

298

 

 

 

$

(452

)

 

BASIC EARNINGS (LOSS) PER SHARE:

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

0.96

 

 

$

0.41

 

 

 

$

0.49

 

 

Discontinued operations

 

 

 

0.06

 

 

 

(1.32

)

 

Cumulative effect of accounting change

 

 

 

 

 

 

0.07

 

 

BASIC EARNINGS (LOSS) PER SHARE:

 

$

0.96

 

 

$

0.47

 

 

 

$

(0.76

)

 

DILUTED EARNINGS (LOSS) PER SHARE:

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

$

0.95

 

 

$

0.41

 

 

 

$

0.49

 

 

Discontinued operations

 

 

 

0.05

 

 

 

(1.32

)

 

Cumulative effect of accounting change

 

 

 

 

 

 

0.07

 

 

DILUTED EARNINGS (LOSS) PER SHARE:

 

$

0.95

 

 

$

0.46

 

 

 

$

(0.76

)

 


(1)          See Note 1 related to the restated consolidated financial statements.

See notes to consolidated financial statements.

103




THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

 

 

2005

 

2004

 

2003

 

 

 

 

 

(Restated)(1)

 

(Restated)(1)

 

 

 

(in millions)

 

OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

630

 

 

$

298

 

 

 

$

(452

)

 

Adjustments to net income (loss):

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization of intangible assets

 

889

 

 

799

 

 

 

755

 

 

Loss from sale of investments and goodwill and asset impairment expense

 

43

 

 

45

 

 

 

215

 

 

Gain (loss) on disposal and impairment write-down associated with discontinued operations

 

 

 

(98

)

 

 

686

 

 

Provision for deferred taxes

 

100

 

 

190

 

 

 

(89

)

 

Minority interest expense

 

361

 

 

199

 

 

 

139

 

 

Other

 

92

 

 

322

 

 

 

(123

)

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable

 

26

 

 

(128

)

 

 

(101

)

 

Increase in inventory

 

(73

)

 

(33

)

 

 

(2

)

 

Decrease in prepaid expenses and other current assets

 

41

 

 

7

 

 

 

180

 

 

(Decrease) increase in accounts payable and accrued liabilities

 

(79

)

 

78

 

 

 

576

 

 

Other assets and liabilities

 

135

 

 

(108

)

 

 

(142

)

 

Net cash provided by operating activities

 

2,165

 

 

1,571

 

 

 

1,642

 

 

INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Property additions

 

(1,143

)

 

(892

)

 

 

(1,228

)

 

Acquisitions—net of cash acquired

 

(85

)

 

 

 

 

 

 

Proceeds from the sales of assets

 

26

 

 

63

 

 

 

1,086

 

 

Sale of short-term investments

 

1,496

 

 

1,387

 

 

 

1,970

 

 

Purchase of short-term investments

 

(1,344

)

 

(1,371

)

 

 

(1,972

)

 

Decrease (increase) in restricted cash

 

58

 

 

(32

)

 

 

(214

)

 

Proceeds from the sale of emisson allowances

 

41

 

 

 

 

 

 

 

Decrease (increase) in debt service reserves and other assets

 

68

 

 

(151

)

 

 

(28

)

 

Other investing

 

10

 

 

(29

)

 

 

(14

)

 

Net cash used in investing activities

 

(873

)

 

(1,025

)

 

 

(400

)

 

FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Borrowings (repayments) under the revolving credit facilities, net

 

53

 

 

 

 

 

(228

)

 

Issuance of recourse debt

 

5

 

 

491

 

 

 

2,503

 

 

Issuance of non-recourse debt and other coupon bearing securities

 

1,884

 

 

2,449

 

 

 

2,111

 

 

Repayments of recourse debt

 

(259

)

 

(1,140

)

 

 

(2,877

)

 

Repayments of non-recourse debt and other coupon bearing securities

 

(2,682

)

 

(2,534

)

 

 

(2,039

)

 

Payments for deferred financing costs

 

(21

)

 

(109

)

 

 

(146

)

 

Distributions to minority interests

 

(186

)

 

(139

)

 

 

(50

)

 

Contributions from minority interests

 

1

 

 

28

 

 

 

38

 

 

Issuance of common stock

 

26

 

 

16

 

 

 

337

 

 

Other financing

 

(16

)

 

2

 

 

 

(2

)

 

Net cash used in financing activities

 

(1,195

)

 

(936

)

 

 

(353

)

 

Effect of exchange rate changes on cash

 

12

 

 

8

 

 

 

34

 

 

Total increase (decrease) in cash and cash equivalents

 

109

 

 

(382

)

 

 

923

 

 

Cash and cash equivalents, beginning

 

1,281

 

 

1,663

 

 

 

740

 

 

Cash and cash equivalents, ending

 

$

1,390

 

 

$

1,281

 

 

 

$

1,663

 

 

SUPPLEMENTAL DISCLOSURES:

 

 

 

 

 

 

 

 

 

 

 

Cash payments for interest, net of amounts capitalized

 

$

1,674

 

 

$

1,759

 

 

 

$

1,827

 

 

Cash payments for income taxes, net of refunds

 

268

 

 

197

 

 

 

177

 

 

SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Common stock issued for debt retirement

 

 

 

168

 

 

 

63

 

 

Liabilities relieved due to sale of assets

 

 

 

 

 

 

1,296

 

 

Brasiliana Energia debt exchange (See Note 14)

 

 

 

773

 

 

 

 

 


(1)             See Note 1 related to the restated consolidated financial statements.

See notes to consolidated financial statements.

104




THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

 

 

 

 

 

 

 

 

Retained

 

Accumulated

 

 

 

 

 

 

 

 

 

Additional

 

Earnings

 

Other

 

 

 

 

 

Common Stock

 

Paid-In

 

(Accumulated

 

Comprehensive

 

Comprehensive

 

 

 

Shares

 

Amount

 

Capital

 

Deficit)

 

Loss

 

Income

 

 

 

(Amounts in Millions)

 

Balance at January 1, 2003

 

 

557.9

 

 

 

$

6

 

 

 

$

5,314

 

 

 

$

(1,672

)

 

 

$

(4,503

)

 

 

 

 

 

Effect of restatement*

 

 

 

 

 

 

 

 

 

 

 

(18

)

 

 

6

 

 

 

 

 

 

Balance at January 1, 2003 (Restated)*

 

 

557.9

 

 

 

6

 

 

 

5,314

 

 

 

(1,690

)

 

 

(4,497

)

 

 

 

 

 

Net loss (Restated)*

 

 

 

 

 

 

 

 

 

 

 

(452

)

 

 

 

 

 

$

(452

)

 

Foreign currency translation adjustment (net of reclassifications to earnings of $114 for the sale or write off of investments in foreign entities, no income tax effect) (Restated)*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

366

 

 

 

366

 

 

Minimum pension liability adjustment (net of income tax expense of $110)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

286

 

 

 

286

 

 

Change in derivative fair value (including a reclassification to earnings of $(124) million, net of income tax expense of $17) (Restated)*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

140

 

 

 

140

 

 

Comprehensive income (Restated)*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

340

 

 

Issuance of common stock through public offering

 

 

49.5

 

 

 

 

 

 

334

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock in exchange for cancellation of debt

 

 

12.2

 

 

 

 

 

 

63

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock under benefit plans and exercise of stock options and warrants

 

 

6.0

 

 

 

 

 

 

19

 

 

 

 

 

 

 

 

 

 

 

 

Stock option expense

 

 

 

 

 

 

 

 

9

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2003 (Restated)*

 

 

625.6

 

 

 

6

 

 

 

5,739

 

 

 

(2,142

)

 

 

(3,705

)

 

 

 

 

 

Net income (Restated)*

 

 

 

 

 

 

 

 

 

 

 

298

 

 

 

 

 

 

298

 

 

Subsidiary sale of stock

 

 

 

 

 

 

 

 

473

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustment (net of reclassifications to earnings of $(46) for the sale or write off of investments in foreign entities, no income tax effect) (Restated)*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

110

 

 

 

110

 

 

Minimum pension liability adjustment (net of income tax expense of $4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

18

 

 

 

18

 

 

Change in derivative fair value (including a reclassification to earnings of $(126) million, net of income tax benefit of $35) (Restated)*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(64

)

 

 

(64

)

 

Comprehensive income (Restated)*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

362

 

 

Issuance of common stock in exchange for cancellation of debt

 

 

19.7

 

 

 

1

 

 

 

168

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock under benefit plans and exercise of stock options and warrants

 

 

4.8

 

 

 

 

 

 

34

 

 

 

 

 

 

 

 

 

 

 

 

Stock compensation

 

 

 

 

 

 

 

 

20

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2004 (Restated)*

 

 

650.1

 

 

 

7

 

 

 

6,434

 

 

 

(1,844

)

 

 

(3,641

)

 

 

 

 

 

Net income

 

 

 

 

 

 

 

 

 

 

 

630

 

 

 

 

 

 

630

 

 

Foreign currency translation adjustment (net of reclassification to earnings of $1 for the sale or write off of investments in foreign entities, no income tax effect)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

57

 

 

 

57

 

 

Minimum pension liability adjustment (net of income tax benefit of $10)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(6

)

 

 

(6

)

 

Change in derivative fair value (including a reclassification to earnings of $(179) million, net of income tax benefit of $112)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(71

)

 

 

(71

)

 

Comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

610

 

 

Issuance of common stock under benefit plans and exercise of stock options and warrants (net of income tax benefit of $14 million)

 

 

5.8

 

 

 

 

 

 

61

 

 

 

 

 

 

 

 

 

 

 

 

Stock compensation

 

 

 

 

 

 

 

 

22

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2005

 

 

655.9

 

 

 

$

7

 

 

 

$

6,517

 

 

 

$

(1,214

)

 

 

$

(3,661

)

 

 

 

 

 


(*)             See Note 1 related to the restated consolidated financial statements.

See notes to consolidated financial statements.

105




THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2005, 2004 AND 2003

1.   GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The AES Corporation is a holding company that through its subsidiaries and affiliates, (collectively, “AES” or “the Company,”) operates a geographically diversified portfolio of electricity generation and distribution businesses.

PRINCIPLES OF CONSOLIDATION—The consolidated financial statements of the Company include the accounts of The AES Corporation, its subsidiaries, and controlled affiliates. Furthermore, variable interest entities in which the Company has an interest have been consolidated where the Company is identified as the primary beneficiary. In all cases, AES holds a majority ownership interest in those variable interest entities that have been consolidated. Investments in which the Company has the ability to exercise significant influence but not control are accounted for using the equity method. All intercompany transactions and balances have been eliminated in consolidation.

USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant items subject to such estimates and assumptions include the carrying value and estimated useful lives of long-lived assets; impairment of goodwill and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of deferred regulatory assets and the valuation of certain financial instruments, pension liabilities, environmental liabilities and potential litigation claims and settlements.

CASH AND CASH EQUIVALENTS—The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit, and short-term marketable securities with an original maturity of three months or less to be cash and cash equivalents.

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

ALLOWANCE FOR DOUBTFUL ACCOUNTS—The Company maintains an allowance for doubtful accounts for estimated uncollectible accounts receivable. The allowance is based on the Company’s assessment of known delinquent accounts, historical experience, and other currently available evidence of the collectability and the aging of accounts receivable.

INVESTMENTS—Short-term investments consist of investments with original maturities in excess of three months but less than one year.

Securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at historical cost. Other investments that the Company does not intend to hold to maturity are classified as available-for-sale or trading. Unrealized gains or losses on available-for-sale investments are recorded as a separate component of stockholders’ equity. Investments classified as trading are marked to market on a periodic basis through the statement of operations. Interest and dividends on investments are reported in interest income. Gains and losses on sales of investments are recorded using the specific identification method.

106




EQUITY INVESTMENTS—Investments in which the Company has the ability to exercise significant influence but not control are accounted for using the equity method. The Company evaluates its equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may not be recoverable. The difference between the carrying value of the equity method investment and its estimated fair value is recognized as an impairment when the loss in value is deemed other than temporary.

In accordance with Accounting Principles Board Opinion No. 18, the Company discontinues the application of the equity method when an investment is reduced to zero and does not provide for additional losses when the Company does not guarantee the obligations of the investee or is not otherwise committed to provide further financial support for the investee. The Company resumes the application of the equity method if the investee subsequently reports net income to the extent that the Company’s share of such net income equals the share of net losses not recognized during the period the equity method was suspended.

PROPERTY, PLANT, AND EQUIPMENT—Property, plant, and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are capitalized.

Construction progress payments, engineering costs, insurance costs, salaries, interest, and other costs relating to construction in progress are capitalized during the construction period, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, siting, financing, construction, permitting, and contract compliance. Construction in progress balances are transferred to electric generation and distribution assets when each asset is ready for its intended use.

Depreciation, after consideration of salvage value and asset retirement obligations, is computed using the straight-line method over the estimated composite useful lives of the assets. Maintenance and repairs are charged to expense as incurred. Emergency and rotable spare parts inventories are included in electric generation and distribution assets when placed in service and are depreciated over the useful life of the related components.

DEFERRED FINANCING COSTS—Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight-line method when it does not differ materially from the effective interest method.

GOODWILL—In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” the Company recognizes goodwill for the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill for impairment on an annual basis and whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company’s annual impairment testing date is October 1st.

LONG-LIVED ASSETS—In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under SFAS No. 144. These events or circumstances may include the relative pricing of wholesale electricity by region and the anticipated demand and cost of fuel. If the carrying amount is not recoverable, an impairment charge is recorded for the amount by which the carrying value of the long-lived asset exceeds its fair value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery was probable. For non-regulated assets, an impairment charge would be recorded as a charge against earnings.

107




The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for measurement, if available. In the absence of quoted market prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow projections or other indicators of fair value such as bids received, comparable sales or independent appraisals.

In connection with the periodic evaluation of long-lived assets in accordance with the requirements of SFAS No. 144, the fair value of the asset can vary if different estimates and assumptions would have been used in our applied valuation techniques. In cases of impairment described in Note 16, we made our best estimate of fair value using valuation methods based on the most current information at that time. We have been in the process of divesting certain assets and their sales values can vary from the recorded fair value as described in Note 19. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions, and management’s analysis of the benefits of the transaction.

ASSET RETIREMENT OBLIGATIONS—Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires the Company to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When a new liability is recorded the Company will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss.

The Company’s retirement obligations covered by SFAS No. 143 include primarily active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. As of December 31, 2005 and 2004, the Company had recorded liabilities of approximately $49 million and $26 million, respectively, related to asset retirement obligations. There are no assets that are legally restricted for purposes of settling asset retirement obligations. Upon adoption of SFAS No. 143, the Company recorded an additional liability of approximately $13 million, a net asset of approximately $9 million, and a cumulative effect of a change in accounting principle of approximately $2 million, after income taxes. Amounts recorded related to asset retirement obligations during the years ended December 31, 2005 and 2004 were as follows (in millions):

 

 

2005

 

2004

 

Balance at January 1

 

 

$

26

 

 

 

$

29

 

 

Additional liability recorded from cumulative effect of accounting change(1) 

 

 

18

 

 

 

 

 

Additional liabilities incurred in the current period

 

 

5

 

 

 

 

 

Accretion expense

 

 

2

 

 

 

2

 

 

Change in estimated cash flows

 

 

(1

)

 

 

(6

)

 

Translation adjustments

 

 

(1

)

 

 

1

 

 

Balance at December 31

 

 

$

49

 

 

 

$

26

 

 


(1)          See New Accounting Pronouncements for discussion on FASB Interpretation (“FIN”) No. 47 “Accounting for Conditional Asset Retirement Obligations”, an interpretation of FASB Statement No. 143.

GUARANTOR ACCOUNTING—Pursuant to the Financial Accounting Standards Board Interpretation No. (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” at the inception of a guarantee, the Company

108




records the fair value of a guarantee as a liability, with the offset dependent on the circumstances under which the guarantee was issued.

INCOME TAXES—Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Contingent liabilities related to income taxes are recorded when the criteria for loss recognition under SFAS No. 5, “Accounting for Contingencies,” as amended, have been met.

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

REVENUE RECOGNITION—The revenue of the regulated utilities segment is classified as regulated on the consolidated statement of operations. Revenues from the sale of energy are recognized in the period during which the sale occurs. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. The revenues from the contract generation and competitive supply segments are classified as non-regulated and are recorded based upon output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. Revenues from power sales contracts entered into after 1991 with decreasing scheduled rates are recognized based on the output delivered at the lower of the amount billed or the average rate over the contract term.

GENERAL AND ADMINISTRATIVE EXPENSES—The Company classifies corporate and business development expenses, including corporate depreciation and amortization, as General and Administrative.

DEFERRED REGULATORY ASSETS AND LIABILITIES—The Company accounts for certain of its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, AES records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred due to the probability of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income.

DERIVATIVES—The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. AES primarily uses derivative instruments to manage its interest rate, commodity, and foreign currency exposures. The Company does not enter into derivative transactions for trading purposes.

109




Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, the Company recognizes all derivatives as either assets or liabilities in the balance sheet and measures those instruments at fair value. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments are recorded in the same category as generated by the underlying asset or liability.

SFAS No. 133 enables companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with SFAS No. 133. If AES deems that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

For cash flow hedges of forecasted transactions, AES must estimate the future cash flows represented by the forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing for the reclassification of gains or losses on cash flow hedges from accumulated other comprehensive loss (“AOCI”) into earnings.

In June 2003, the FASB issued DIG Issue C-20, that superseded DIG Issue C-11 and provided additional guidance related to the impact of certain price adjustment features on the ability of a contract to qualify for the normal purchases and sales exemption. In order for contracts to qualify for the exemption, they must first meet certain criteria, including requirements that the underlying price adjustment may not be considered extraneous and that the magnitude and direction of the impact of the price adjustment is consistent with the relevancy of the underlying. Additionally, there are restrictions on certain contracts with an underlying associated with currency exchange rates qualifying for the exemption. Under the transition provisions of DIG Issue C-20, the Company was required to record a cumulative effect of change in accounting principle adjustment of $43 million, net of income taxes on October 1, 2003 for the fair value of a power sales contract. This contract subsequently qualified for the normal purchases and sales exemption and the contract’s carrying value is being amortized on a straight-line basis over the remaining life of the contract.

STOCK OPTIONS—Prior to 2003, the Company accounted for stock-based compensation plans under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations. Effective January 1, 2003, the Company adopted the fair value recognition provision of SFAS No. 123, as amended by SFAS No. 148, prospectively to all employee awards granted, modified or settled after January 1, 2003. Prior to 2002, awards under the Company’s plans generally vested over two years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for the years ended December 31, 2004 and 2003, is less than what would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. However, if SFAS No. 123 had been applied to all grants since the original effective date, the impact on net income would have been minimal since there were very few grants that would have had expense carried over to 2004 and 2003.

SALES OF STOCK BY A SUBSIDIARYSales of stock by a subsidiary of the Company are accounted for as capital transactions pursuant to the Securities and Exchange Commission’s Staff Accounting Bulletin No. 51 “Accounting for Sales of Stock by a Subsidiary” (“SAB 51”).

110




VARIABLE INTEREST ENTITIES—In January 2003, the FASB issued FIN 46 which addresses consolidation by business enterprises of variable interest entities (“VIE”). The primary objective of FIN 46 is to provide guidance on the identification of and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination.

On December 24, 2003, the FASB issued Financial Interpretation No. 46 (Revised 2003) Consolidation of Variable Interest Entities (“FIN 46(R)” or “Revised Interpretation”), which partially deferred the effective date of FIN 46 for certain entities and makes other changes to FIN 46, including a more complete definition of variable interest, and an exemption for many entities defined as businesses.

The Company applied FIN 46 in its financial statements relating to its interest in variable interest entities or potential variable interest entities as of December 31, 2003, and applied FIN 46(R) as of March 31, 2004. Application of FIN 46 as of December 31, 2003 resulted in the special purpose business trusts that issued Term Convertible Preferred Securities no longer being consolidated (see Note 8). The application of FIN 46(R) did not have any additional impact on the Company’s consolidated financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.   In May 2004, the FASB issued FASB Staff Position (“FSP”) 106-2, which provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) for employers that sponsor postretirement health care plans that provide prescription drug benefits. One of the Company’s subsidiaries maintains a retiree health benefit plan that currently includes a prescription drug benefit that is provided to retired employees. The enactment of the Act did not have a significant effect on the subsidiaries retirement plan. The accumulated pension benefit obligation and net periodic postretirement benefit costs associated with this retiree health plan currently reflect the effects of the Act. The effects of the Act, which were not material, were incorporated into the November 30, 2004 measurement of plan obligations as required by FSP 106-2.

Share-Based Payment.   In December 2004, the Financial Accounting Standards Board (“FASB”) issued a revised Statement of Financial Accounting Standard (“SFAS”) No. 123, “Share-Based Payment.” SFAS 123R eliminates the intrinsic value method as an alternative method of accounting for stock-based awards under Accounting Principles Board (“APB”) No. 25 by requiring that all share-based payments to employees, including grants of stock options for all outstanding years, be recognized in the financial statements based on their fair values. It also revises the fair-value based method of accounting for share-based payment liabilities, forfeitures and modifications of stock-based awards and clarifies the guidance under SFAS No. 123 related to measurement of fair value, classifying an award as equity or as a liability and attributing compensation to reporting periods. In addition, SFAS No. 123R amends SFAS No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as an operating cash flow.

Effective January 1, 2003, the Company adopted the fair value recognition provision of SFAS No. 123, as amended by SFAS No. 148, prospectively to all employee awards granted, modified or settled after January 1, 2003. We adopted SFAS No. 123R and related guidance on January 1, 2006, using the modified prospective transition method. Under this transition method, compensation cost will be recognized (a) based on the requirements of SFAS No. 123R for all share-based awards granted subsequent to January 1, 2006 and (b) based on the original provisions of SFAS No. 123 for all awards granted prior to

111




January 1, 2006, but not vested as of this date. Results for prior periods will not be restated. Management is currently evaluating the effect of the adoption of SFAS No. 123R under the modified prospective application transition method, but does not expect the adoption to have a material effect on the Company’s financial condition, results of operations or cash flows.

Conditional Asset Retirement Obligations   In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47 “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143,” which clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143 “Accounting for Asset Retirement Obligations.” Specifically, FIN 47 provides that an asset retirement obligation is conditional when the timing and/or method of settling the obligation is conditioned on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005

The Company’s asset retirement obligations covered by FIN 47 primarily include conditional obligations to demolish assets or return assets in good working condition at the end of the contractual or concession term, and for the removal of equipment containing asbestos and other contaminants. As of December 31, 2005, the Company recorded additional asset retirement obligations in the amount of $18 million as a result of the implementation of FIN 47. The cumulative effect of the initial application of this Interpretation was recognized as a change in accounting principle in the amount of $2 million, net of income tax benefit of $1 million.

The pro forma net income (loss) and earnings (loss) per share resulting from the adoption of  FIN 47 for the years ended December 31, 2005, 2004 and 2003, is not materially different from the actual amounts reported in the accompanying consolidated statement of operations for those periods. Had FIN 47 been applied during all periods presented, the asset retirement obligations at December 31, 2003 and December 31, 2004 would have been approximately $14 million and $15 million, respectively.

RESTATEMENTSubsequent to filing its restated annual report on Form 10-K/A with the Securities Exchange Commission on January 19, 2006, the Company discovered its previously issued restated annual report included certain errors in accounting for derivative instruments and hedging activities, minority interest expense and income taxes. The errors in accounting for derivative instruments and hedging activities resulted in differences in previously issued consolidated interim financial statements for certain quarterly periods in 2004 sufficient to require restatement of prior period interim results. The errors in accounting for income taxes and minority interest expense required restatement of previously issued consolidated annual financial statements.

The Company reduced its stockholders’ equity by $12 million as of January 1, 2003 as the cumulative effect of the correction of errors for all periods preceding January 1, 2003, and restated its consolidated statements of operations and cash flows for the years ended December 31, 2004 and 2003 and its consolidated balance sheet as of December 31, 2004.

112




The restatement adjustments resulted in an increase to previously reported net income of $6 million for the year ended December 31, 2004 and in a decrease to previously reported net income of $17 million for the year ended December 31, 2003. There was no impact on gross margin or net cash flow from operating activities of the Company for any years presented. Based upon management’s review it has been determined that these errors were inadvertent and unintentional. The errors relate to the following areas:

A.   Accounting for Derivative Instruments and Hedging Activities

The Company determined that it failed to perform adequate on-going effectiveness testing for three interest rate cash flow hedges and one foreign currency cash flow hedge during 2004 as required by SFAS No. 133. As a result, the Company should have discontinued hedge accounting and recognized changes in the fair value of the derivative instruments in earnings prospectively from the last valid effectiveness assessment until the earlier of either (1) the expiration of the derivative instrument or (2) the re-designation of the derivative instrument as a hedging activity.

The net impact related to the correction of these errors to previously reported net income resulted in a decrease of $4 million and an increase of $2 million for the years ending December 31, 2004 and 2003, respectively.

B.   Income Tax and Minority Interest Adjustments

As a result of the Company’s year end closing review process, the Company discovered certain other errors related to the recording of income tax liabilities and, in one case, the associated impact on minority interest expense. The adjustments include:

·       An increase in income tax expense related to the recording of  certain historical withholding tax liabilities at one of our El Salvador subsidiaries;

·       An increase in minority interest expense related to a correction of the allocation of income tax expense to minority shareholders. This allocation pertained to certain deferred tax adjustments recorded in the original restatement at one of our Brazilian generating companies; and

·       A reduction of 2004 income tax expense related to adjustments derived from 2004 income tax returns filed in 2005.

The net impact related to the correction of these errors to previously reported net income resulted in an increase of $10 million and a decrease of $19 million, for the years ended December 31, 2004 and 2003, respectively. In addition, the Company restated stockholders’ equity as of January 1, 2003, by $12 million as a correction for these errors in all periods preceding January 1, 2003.

C.   Other Balance Sheet Reclassifications

Certain other balance sheet reclassifications were recorded at December 31, 2004 including a $45 million reclassification which reduced Accounts Receivables and increased Other Current Assets (regulatory assets) to ensure consistency of accounting among our subsidiary businesses.

113




The following tables set forth the previously reported and restated amounts of selected items within the consolidated balance sheet as of December 31, 2004 and within the consolidated statements of comprehensive income and cash flows for the years ended December 31, 2004.

Selected Balance Sheet Data:

 

 

December 31, 2004

 

 

 

As Previously
Reported

 

As Restated

 

 

 

(in millions)

 

Assets

 

 

 

 

 

 

 

 

 

Accounts receivable, net of reserves

 

 

$

1,575

 

 

 

$

1,530

 

 

Other current assets

 

 

$

736

 

 

 

$

781

 

 

Total current assets

 

 

$

4,986

 

 

 

$

4,986

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

 

 

Accounts payable

 

 

$

1,142

 

 

 

$

1,081

 

 

Accrued and other liabilities

 

 

$

1,656

 

 

 

$

1,707

 

 

Total current liabilities

 

 

$

4,894

 

 

 

$

4,884

 

 

Deferred income taxes

 

 

$

685

 

 

 

$

678

 

 

Other long-term liabilities

 

 

$

3,375

 

 

 

$

3,382

 

 

Total long-term liabilities

 

 

$

21,778

 

 

 

$

21,778

 

 

Minority interest

 

 

$

1,279

 

 

 

$

1,305

 

 

Additional paid-in capital

 

 

$

6,423

 

 

 

$

6,434

 

 

Accumulated deficit

 

 

$

1,815

 

 

 

$

1,844

 

 

Accumulated other comprehensive loss

 

 

$

3,643

 

 

 

$

3,641

 

 

Total stockholders’ equity

 

 

$

972

 

 

 

$

956

 

 

 

114




 

Selected Operations and Comprehensive Income (Loss) Data:

 

 

For the Year Ended

 

 

 

December 31, 2004

 

December 31, 2003

 

 

 

As Previously
Reported

 

As Restated

 

As Previously
Reported

 

As Restated

 

 

 

(in millions, except per share amounts)

 

Interest expense

 

 

$

1,941

 

 

 

$

1,932

 

 

 

$

1,986

 

 

 

$

1,984

 

 

Foreign currency transaction (losses) gains on net monetary position

 

 

$

(147

)

 

 

$

(165

)

 

 

$

99

 

 

 

$

99

 

 

Income tax expense

 

 

$

375

 

 

 

$

359

 

 

 

$

211

 

 

 

$

211

 

 

Minority interest expense

 

 

$

198

 

 

 

$

199

 

 

 

$

120

 

 

 

$

139

 

 

Income from continuing operations

 

 

$

258

 

 

 

$

264

 

 

 

$

311

 

 

 

$

294

 

 

Net income (loss)

 

 

$

292

 

 

 

$

298

 

 

 

$

(435

)

 

 

$

(452

)

 

Foreign currency translation adjustment

 

 

$

113

 

 

 

$

110

 

 

 

$

370

 

 

 

$

366

 

 

Minimum pension liability adjustments

 

 

$

22

 

 

 

$

18

 

 

 

$

286

 

 

 

$

286

 

 

Unrealized derivative (losses) gains

 

 

$

(72

)

 

 

$

(64

)

 

 

$

141

 

 

 

$

140

 

 

Comprehensive income

 

 

$

355

 

 

 

$

362

 

 

 

$

362

 

 

 

$

340

 

 

BASIC EARNINGS (LOSS) PER SHARE:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 

$

0.40

 

 

 

$

0.41

 

 

 

$

0.52

 

 

 

$

0.49

 

 

Discontinued operations

 

 

0.06

 

 

 

0.06

 

 

 

(1.32

)

 

 

(1.32

)

 

Cumulative effect of accounting change

 

 

 

 

 

 

 

 

0.07

 

 

 

0.07

 

 

BASIC EARNINGS (LOSS) PER SHARE:

 

 

$

0.46

 

 

 

$

0.47

 

 

 

$

(0.73

)

 

 

$

(0.76

)

 

DILUTED EARNINGS (LOSS) PER SHARE:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

 

$

0.40

 

 

 

$

0.41

 

 

 

$

0.52

 

 

 

$

0.49

 

 

Discontinued operations

 

 

0.05

 

 

 

0.05

 

 

 

(1.32

)

 

 

(1.32

)

 

Cumulative effect of accounting change

 

 

 

 

 

 

 

 

0.07

 

 

 

0.07

 

 

DILUTED EARNINGS (LOSS) PER SHARE:

 

 

$

0.45

 

 

 

$

0.46

 

 

 

$

(0.73

)

 

 

$

(0.76

)

 

 

Selected Cash Flows Data:

 

 

For the Year Ended

 

 

 

 

December 31, 2004

 

December 31, 2003

 

 

 

As Previously
Reported

 

As Restated

 

As Previously
Reported

 

As Restated

 

 

 

($ in millions)

 

Cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

 

$

292

 

 

 

$

298

 

 

 

$

(435

)

 

 

$

(452

)

 

Adjustments to net income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization of intangible
assets

 

 

$

801

 

 

 

$

799

 

 

 

$

755

 

 

 

$

755

 

 

Provision for deferred taxes

 

 

$

200

 

 

 

$

190

 

 

 

$

(89

)

 

 

$

(89

)

 

Minority interest expense

 

 

$

198

 

 

 

$

199

 

 

 

$

120

 

 

 

$

139

 

 

Other

 

 

$

296

 

 

 

$

322

 

 

 

$

(123

)

 

 

$

(123

)

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Increase in accounts payable and accrued liabilities

 

 

$

226

 

 

 

$

78

 

 

 

$

697

 

 

 

$

576

 

 

Other assets and liabilities

 

 

$

(235

)

 

 

$

(108

)

 

 

$

(261

)

 

 

$

(142

)

 

Net cash provided by operating activities

 

 

$

1,571

 

 

 

$

1,571

 

 

 

$

1,642

 

 

 

$

1,642

 

 

 

115




2.   INVESTMENTS

The Company’s short-term investments were invested as follows (in millions):

 

 

December 31,

 

 

 

2005

 

2004

 

HELD-TO-MATURITY:

 

 

 

 

 

Certificates of deposit

 

$

15

 

$

141

 

Mutual funds

 

1

 

 

Government debt securities

 

7

 

 

Subtotal

 

23

 

141

 

AVAILABLE-FOR-SALE:

 

 

 

 

 

Money market funds

 

5

 

 

Mutual Funds

 

80

 

115

 

Government debt securities

 

87

 

 

Auction Rate Securities .

 

1

 

12

 

Other

 

5

 

 

Subtotal

 

178

 

127

 

TRADING:

 

 

 

 

 

Government debt securities

 

2

 

 

Subtotal

 

2

 

 

TOTAL

 

$

203

 

$

268

 

 

The investments are classified as held-to-maturity, available-for-sale or trading. The amortized cost and estimated fair value of the held-to-maturity investments were approximately the same at December 31, 2005 and 2004. The available-for-sale and trading investments are recorded at fair value. At December 31, 2005 and 2004, approximately $10 million and $136 million, respectively, of investments classified as held-to-maturity were restricted or pledged as collateral.

At December 31, 2005 and 2004, there were no amounts included in accumulated other comprehensive income for available-sale-securities. Proceeds from the sales of available-for-sale securities were $1.1 billion and $1.3 billion for the years ended December 31, 2005 and 2004, respectively. Gross realized gains on these sales were $31 million and $3 million for the years ended December 31, 2005 and 2004, respectively.

3.   INVENTORY

Most of the company’s inventories are valued on the average cost method (67%) or the first-in, first-out (“FIFO”) method (29%). Inventories stated under the last-in, first-out (“LIFO”) method represent 4% of total inventories in 2005. If the FIFO method, which approximates current replacement cost, had been used for these LIFO inventories, the total amount of these inventories would have increased by approximately $11 million. Inventory is accounted for at the lower of cost or market.

Inventory consists of the following (in millions):

 

 

December 31,

 

 

 

2005

 

2004

 

Coal, fuel oil and other raw materials

 

$

233

 

$

193

 

Spare parts and supplies

 

227

 

225

 

 

 

$

460

 

$

418

 

 

116




4.   DEFERRED REGULATORY ASSETS & LIABILITIES

The Company has recorded deferred regulatory assets and liabilities that it expects to pass through to its customers in accordance with and subject to regulatory provisions as follows (in millions):

 

 

December 31,

 

 

 

2005

 

2004

 

Current assets

 

$

441

 

$

390

 

Noncurrent assets

 

635

 

613

 

Total assets

 

$

1,076

 

$

1,003

 

Current liabilities

 

$

211

 

$

139

 

Noncurrent liabilities

 

506

 

455

 

Total liabilities

 

$

717

 

$

594

 

 

The current portion of the deferred regulatory asset and liability is recorded in other current assets or other current liabilities, respectively, on the accompanying consolidated balance sheets. The noncurrent portion of the deferred regulatory asset and liability is recorded in other assets and other long-term liabilities, respectively, in the accompanying consolidated balance sheets.

Recovery of certain regulatory assets at the Company’s subsidiaries is provided without a rate of return during the recovery period. All other regulatory assets are recovered with a rate of return. The amounts of regulatory assets probable of recovery without a rate of return at December 31, 2005 and 2004 are as follows (in millions):

 

 

2005

 

2004

 

Recovery Period

 

Current:

 

 

 

 

 

 

 

IPL Deferred fuel costs and other

 

$

41

 

$

2

 

Through 2006

 

Foreign subsidiary costs

 

12

 

4

 

Through 2006

 

Total current

 

$

53

 

$

6

 

 

 

Long Term (IPL):

 

 

 

 

 

 

 

Related to deferred income taxes

 

$

87

 

$

88

 

Various

 

Unamortized reacquisition premium on debt

 

15

 

15

 

Over remaining life of debt

 

Deferred Midwest ISO costs

 

21

 

8

 

To be determined (1)

 

Asset retirement obligation costs

 

9

 

 

Over book life of assets

 

NOx project expenses - Pete unit 2 precipitator

 

2

 

2

 

Through 2021

 

Total long term

 

$

134

 

$

113

 

 

 

Total

 

$

187

 

$

119

 

 

 


(1)          Deferred per specific rate order, recovery is probable but not yet determined

Deferred Fuel. Deferred fuel costs are a component of current regulatory assets and are expected to be recovered through future fuel adjustment charge proceedings. The Company records deferred fuel in accordance with standards prescribed by the United States Federal Energy Regulatory Commission. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in IPL’s fuel adjustment charge and actual fuel and purchased power costs. IPL is permitted to recover underestimated fuel and purchased power costs in future rates through the fuel adjustment charge proceedings and therefore the costs are deferred and amortized into fuel expense in the same period that IPL’s rates are adjusted.

117




Deferred Income Taxes: This amount represents the portion of deferred income taxes that are probable of recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. Accordingly, this regulatory asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period underlying book-tax timing differences reverse and become current taxes.

Deferred Midwest ISO costs: These consist of administrative costs for transmission services and other administrative and socialized costs from IPL’s participation in the Midwest ISO market. IPL received orders from the Indiana Utility Regulatory Commission that granted authority for the deferral of such costs for recovery in a future base rate case.

Asset Retirement Obligation Costs: This amount represents the portion of legal asset retirement obligation costs that are probable of recovery through future rates, based upon established regulatory practices.

5.   PROPERTY, PLANT & EQUIPMENT

The components of the electric generation and distribution assets and the related rates of depreciation are as follows:

 

 

Composite Rate

 

Useful Life

 

Electric Generation and Distribution Facilities

 

2.0% – 25.0%

 

4 – 50 yrs.

 

Other Buildings

 

2.0% – 20.0%

 

5 – 50 yrs.

 

Leasehold improvements

 

2.9% – 33.3%

 

3 – 34 yrs.

 

Furniture and Fixtures

 

3.3% – 33.3%

 

3 – 30 yrs.

 

 

Depreciation expense stated as a percentage of average cost of depreciable property, plant and equipment was, on a composite basis, 3.8%, 3.8% and 4.34% for the years ended December 31, 2005, 2004 and 2003, respectively. Interest capitalized during development and construction totaled $50 million, $48 million and $115 million in 2005, 2004 and 2003, respectively. Recoveries of liquidating damages from construction delays are recorded as a reduction in the related projects’ construction costs. Approximately $8.4 billion of property, plant and equipment, net of accumulated depreciation, was mortgaged, pledged or subject to lien as of December 31, 2005.

6.   INVESTMENTS IN AND ADVANCES TO AFFILIATES

US Wind Force, LLC.   In September 2004, the Company acquired an initial 15% of US Wind Force, LLC (“US Wind”), a private company that focuses on developing wind energy projects in the United States. As of December 31, 2005, the Company’s ownership of US Wind increased to 27.55%, from 17.82% as of December 31, 2004, as additional capital contributions were made to US Wind during 2005.

Medway Power Limited.   During the fourth quarter of 2003, the Company sold its 25% ownership interest in Medway Power Limited (“MPL”), a 688 MW natural gas-fired combined cycle facility located in the United Kingdom, and AES Medway Operations Limited (“AESMO”), the operating company for the facility, in an aggregate transaction valued at approximately $78 million. The sale resulted in a gain of $23 million which was recorded in continuing operations. MPL and AESMO were previously reported in the contract generation segment.

Companhia Energetica de Minas Gerais.   The Company is a party to a joint venture/consortium agreement through which the Company has an equity investment in Companhia Energetica de Minas Gerais (“CEMIG”), an integrated utility in Minas Gerais, Brazil. The agreement prescribes ownership and voting percentages as well as other matters. In the fourth quarter of 2002, a combination of events occurred related to the CEMIG investment. These events included consistent poor operating performance in part caused by continued depressed demand and poor asset management, the inability to adequately

118




service or refinance operating company debt and acquisition debt, and a continued decline in the market price of CEMIG shares. Additionally, a partner in one of the holding companies in the CEMIG ownership structure sold its interest in this holding company to an unrelated third party in December 2002 for a nominal amount. Upon evaluating these events in conjunction with each other, the Company concluded that an other than temporary decline in value of the CEMIG investment had occurred. Therefore, in December 2002, AES recorded an impairment charge related to the other than temporary decline in value of the investment in CEMIG, and the shares in CEMIG were written-down to fair market value. Additionally, AES recorded a valuation allowance against a deferred tax asset related to the CEMIG investment. The total amount of these charges, net of tax, was $587 million, of which $264 million relates to the other than temporary impairment of the investment and $323 million relates to the valuation allowance against the deferred tax asset. As a result of these charges, the Company’s investment in CEMIG, net of debt used to finance the CEMIG investment, is negative.

In the fourth quarter of 2002, AES lost voting control of one of the holding companies in the CEMIG ownership structure. This holding company indirectly owns the shares related to the CEMIG investment and indirectly holds the project financing debt related to CEMIG. As a result of the loss of voting control, AES stopped consolidating this holding company at December 31, 2002. The Company’s equity investment in CEMIG is $(484) million at December 31, 2005.

The financial information table below excludes information related to the CEMIG business because the Company has discontinued the application of the equity method investment in accordance with its accounting policy (disclosed in Note 1). The following tables summarize financial information (in millions) of the entities in which the Company has the ability to exercise significant influence but does not control and that are accounted for using the equity method.

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Revenues

 

$

1,051

 

$

945

 

$

1,111

 

Gross Margin

 

$

332

 

$

309

 

$

370

 

Net Income

 

$

163

 

$

170

 

$

154

 

 

 

 

December 31,

 

 

 

2005

 

2004

 

Current Assets

 

$

512

 

$

508

 

Noncurrent Assets

 

$

2,232

 

$

2,457

 

Current Liabilities

 

$

345

 

$

398

 

Noncurrent Liabilities

 

$

1,094

 

$

1,264

 

Stockholders’ Equity

 

$

1,305

 

$

1,303

 

 

Relevant effective equity ownership percentages for the Company’s investments are presented below:

Affiliate

 

 

 

Country

 

2005

 

2004

 

2003

 

Cemig

 

Brazil

 

9.57

 

9.57

 

9.57

 

Chigen affiliates

 

China

 

25.00

 

25.00

 

25.00

 

EDC affiliates

 

Venezuela

 

43.00

 

43.00

 

43.00

 

Elsta

 

Netherlands

 

50.00

 

50.00

 

50.00

 

Gener affiliates

 

Chile

 

49.00

 

49.00

 

49.00

 

Itabo

 

Dominican Republic

 

25.00

 

25.00

 

25.00

 

Kingston Cogen Ltd

 

Canada

 

50.00

 

50.00

 

50.00

 

OPGC

 

India

 

49.00

 

49.00

 

49.00

 

US Wind

 

United States

 

27.55

 

17.82

 

 

 

The Company’s after-tax share of undistributed earnings of affiliates included in consolidated retained earnings was $101 million, $81 million and $60 million at December 31, 2005, 2004 and 2003, respectively. The Company charged and recognized construction revenues, management fees and interest on advances

119




to its affiliates, which aggregated $7 million, $6 million and $8 million for the years ended December 31, 2005, 2004 and 2003, respectively.

In March 2006, AES’s wholly-owned subsidiary, AES Kingston Holdings, B.V., sold its indirect ownership interest in Kingston Cogeneration Limited Partnership (“KCLP”), a 110 MW cogeneration plant located in Ontario, Canada.  AES will receive approximately $110 million in proceeds for the sale of its investment.

7.   GOODWILL AND OTHER INTANGIBLES

SFAS No. 142 requires that goodwill be evaluated for impairment at a level referred to as a reporting unit. A reporting unit is an operating segment as defined by SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” or one level below an operating segment, referred to as a component. Generally, each AES business constitutes a reporting unit. Reporting units have been acquired generally in separate transactions. In the event that more than one reporting unit is acquired in a single acquisition, the fair value of each reporting unit is determined, and that fair value is allocated to the assets and liabilities of that unit. If the determined fair value of the reporting unit exceeds the amount allocated to the net assets of the reporting unit, goodwill is assigned to that reporting unit.

Changes in the carrying amount of goodwill, by segment, for the years ended December 31, 2005 and 2004 are as follows (in millions):

 

 

Contract

 

Competitive

 

Regulated

 

 

 

 

 

Generation

 

Supply

 

Utilities

 

Total

 

Carrying amount at December 31, 2003

 

 

$

1,236

 

 

 

$

46

 

 

 

$

139

 

 

$

1,421

 

Translation adjustments and other

 

 

          1

 

 

 

  —

 

 

 

     (3

)

 

        (2

)

Carrying amount at December 31, 2004

 

 

  1,237

 

 

 

  46

 

 

 

  136

 

 

  1,419

 

Goodwill acquired during the period

 

 

        35

 

 

 

  —

 

 

 

     —

 

 

        35

 

Translation adjustments and other

 

 

      (26

)

 

 

  —

 

 

 

     —

 

 

      (26

)

Carrying amount at December 31, 2005

 

 

$

1,246

 

 

 

$

46

 

 

 

$

136

 

 

$

1,428

 

 

There was no impairment of goodwill during the years ended December 31, 2005 and 2004. In 2003, the Company recognized goodwill impairment associated with certain acquisitions where the current fair market value of such businesses was less than the current carrying values. This primarily resulted from reductions in fair value associated with lower than expected growth in electricity consumption and lower electricity prices due in part to the significant devaluation of the local currencies relative to the original estimates made at the date of acquisition. The fair value of these businesses was estimated using the expected present value of future cash flows and comparable sales, when available.

At December 31, 2005 and 2004, other intangibles with a gross carrying amount of $497 million and $377 million, respectively, net of accumulated amortization of $167 million and $102 million, respectively, are included in other assets in the accompanying consolidated balance sheets. Other intangibles primarily consist of sales concessions, software costs, transmission rights, management rights, land use rights and power purchase agreements. For the years ended December 31, 2005 and 2004, the amortization expense was $34 million and $17 million, respectively. Estimated amortization expense is $32 million in 2006, $28 million in 2007, $21 million in 2008, $16 million in 2009 and $14 million in 2010.

120




8.   LONG-TERM DEBT

 

 

 

 

 

 

December 31,

 

NON-RECOURSE DEBT (IN MILLIONS)

 

 

 

Interest Rate(1)

 

Final Maturity

 

2005

 

2004

 

VARIABLE RATE(2):

 

 

 

 

 

 

 

 

 

 

 

 

 

Bank loans

 

 

6.61

%

 

 

2022

 

 

$

4,342

 

$

5,310

 

Notes and bonds

 

 

14.72

%

 

 

2023

 

 

867

 

312

 

Debt to (or guaranteed by) multilateral or export credit agencies or development banks

 

 

12.50

%

 

 

2018

 

 

538

 

745

 

Other

 

 

11.69

%

 

 

2022

 

 

817

 

728

 

FIXED RATE:

 

 

 

 

 

 

 

 

 

 

 

 

 

Bank loans

 

 

7.47

%

 

 

2024

 

 

268

 

276

 

Commercial paper

 

 

10.46

%

 

 

2006

 

 

5

 

26

 

Notes and bonds

 

 

8.83

%

 

 

2034

 

 

5,144

 

5,269

 

Debt to (or guaranteed by) multilateral or export credit agencies or development banks

 

 

10.57

%

 

 

2014

 

 

583

 

536

 

Other

 

 

8.17

%

 

 

2017

 

 

260

 

234

 

SUBTOTAL

 

 

 

 

 

 

 

 

 

12,824

 

13,436

 

Less: Current maturities

 

 

 

 

 

 

 

 

 

(1,598

)

(1,619

)

TOTAL

 

 

 

 

 

 

 

 

 

$

11,226

 

$

11,817

 

 


(1)          Weighted average interest rate at December 31, 2005.

(2)          The Company has interest rate swaps and interest rate collar agreements in an aggregate notional principal amount of approximately $3 billion at December 31, 2005. The swap agreements economically change the variable interest rates on the portion of the debt covered by the notional amounts to fixed rates ranging from approximately 3.22% to 7.49%. The collar agreements fix interest rates within a range from 5.44% to 7.0%. The agreements expire at various dates from 2006 through 2023.

 

 

 

 

 

 

December 31,

 

RECOURSE DEBT (IN MILLIONS)

 

 

 

Interest Rate(1)

 

Final Maturity

 

2005

 

2004

 

Senior Secured Term Loan

 

LIBOR + 2.25%

 

2011

 

$

 

$

200

 

Senior Secured Term Loan

 

LIBOR + 1.75%

 

2011

 

200

 

 

Second Priority Senior Secured Notes

 

8.75% – 9.00%

 

2013 – 2015

 

1,800

 

1,800

 

Senior Unsecured Notes

 

7.75% – 9.50%

 

2008 – 2014

 

2,046

 

2,064

 

Senior Subordinated Notes

 

8.33% – 8.88%

 

2007 – 2027

 

115

 

227

 

Convertible Junior Subordinated Debentures

 

6.0% – 6.75%

 

2008 – 2029

 

731

 

872

 

Unamortized discounts

 

 

 

 

 

(10

)

(11

)

SUBTOTAL

 

 

 

 

 

4,882

 

5,152

 

Less: Current maturities(2)

 

 

 

 

 

(200

)

(142

)

Total

 

 

 

 

 

$

4,682

 

$

5,010

 


(1)          Interest rate at December 31, 2005. Weighted average LIBOR rates at December 31, 2005 and 2004 were 3.63% and 2.10%, respectively.

(2)          Senior Secured Term Loan was classified as a current maturity as of December 31, 2005, because the loan was in default as of March 31, 2006.

NON-RECOURSE DEBT—Non-recourse debt borrowings are not a direct obligation of AES, the parent corporation and are 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

121




non-recourse financings include structured project financings, acquisition financings, working capital facilities and all other consolidated debt of the subsidiaries.

In October 2004, AES signed an assignment and release agreement with the lenders of La Plata Partners, a holding company of Edelap, a subsidiary located in Argentina. Under the agreement, the lenders agreed to sell and assign to AES all of their rights, title, interests and obligations under the loan documents. On November 2, 2004, AES paid $17 million to the original lenders to settle the outstanding principal and accrued interest. The debt extinguishment resulted in a pre-tax gain of approximately $64 million in the fourth quarter of 2004, which is included in other income in the accompanying consolidated statement of operations.

The terms of the Company’s non-recourse debt, which is debt held at subsidiaries, include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include but are not limited to maintenance of certain reserves, minimum levels of working capital and limitations on incurring additional indebtedness. Compliance with certain covenants may not be objectively determinable.

Subsidiary non-recourse debt in default as of December 31, 2005 and 2004 is as follows (in millions):

 

 

Primary Nature 

 

December 31, 2005

 

December 31,

 

Subsidiary

 

 

 

of Default

 

Default

 

Net Assets(1)

 

2004

 

Eden/Edes

 

Payment

 

 

$

98

 

 

 

$

(17

)

 

 

$

98

 

 

Parana

 

Material adverse change

 

 

33

 

 

 

(77

)

 

 

53

 

 

Hefei

 

Payment

 

 

4

 

 

 

26

 

 

 

4

 

 

Los Mina

 

Payment

 

 

 

 

 

 

 

 

24

 

 

Andres

 

Payment

 

 

 

 

 

 

 

 

112

 

 

Ekibastuz

 

Covenant

 

 

3

 

 

 

68

 

 

 

 

 

 

 

 

 

 

$

138

 

 

 

 

 

 

 

$

291

 

 


(1)          Net assets are presented only for those subsidiaries with secured debt in default at December 31, 2005.

Andres and Los Mina, both electricity generation companies which are wholly owned subsidiaries of the Company located in the Dominican Republic, entered into forbearance agreements with their respective lenders in December 2004. Pursuant to the forbearance agreements, the lenders agreed not to exercise any remedies under the respective credit agreements. The forbearance agreements for Andres and Los Mina expired on July 29, 2005 and June 10, 2005, respectively. Subsequently, in December 2005, AES Dominicana Energia Finance, S.A., a wholly owned subsidiary of the Company, issued a $160 million Senior Secured Corporate Bond in the international capital markets under Rule 144A/Regulation S. The 10-year notes, with final maturity in December 2015, were priced to yield 11%. The net proceeds of the issuance were used to retire the current bank debt at both Andres and Los Mina of $112 million and $24 million, respectively. As of December 31, 2005, the debt default for both of these subsidiaries was cured and new debt reported as long-term in the accompanying condensed consolidated balance sheet.

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

122




Principal payments required on non-recourse debt outstanding at December 31, 2005, are $1,598 million in 2006, $1,032 million in 2007, $1,286 million in 2008, $931 million in 2009, $1,283 million in 2010 and $6,694 million thereafter.

As of December 31, 2005, several AES subsidiaries had approximately $126 million of unused lines of credit available mainly as working capital facilities.

As of December 31, 2005 and 2004, approximately $629 million and $758 million, respectively, of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within Restricted Cash and Debt Service Reserves and Other Deposits in the accompanying consolidated balance sheets.

Various lender and governmental provisions restrict the ability of the Company’s subsidiaries to transfer their net assets to the parent company. Such restricted net assets of subsidiaries amounted to approximately $4.4 billion at December 31, 2005.

RECOURSE DEBT—Recourse debt obligations are direct borrowings of the AES parent corporation.

On June 1, 2005, the Company redeemed all outstanding 8.5% Senior Subordinated Notes due 2007, at a redemption price of 101.417%, and an aggregate principal amount of approximately $112 million.

On June 23, 2005, the Company amended its $450 million Senior Secured Bank Facilities. The interest rate on the $450 million Revolving Bank Loan was reduced to the London Interbank Offered Rate (“LIBOR”) plus 1.75%. Previously, the rate was LIBOR plus 2.5%. In addition, the Revolving Bank Loan maturity was extended from 2007 to 2010. The interest rate on the term $200 million Senior Secured Term Loan was also reduced to LIBOR plus 1.75%, from LIBOR plus 2.25%, while its maturity in 2011 remains unchanged. On September 30, 2005, the Company upsized the Revolving Bank Loan to a total commitment amount of $650 million from $450 million. At December 31, 2005, the Company had $294 million of letters of credit outstanding and $356 million available under the $650 million Revolving Bank Loan. As of March 31, 2006, the Company is in default under its senior bank credit facility due to the restatement of its 2003 consolidated financial statements. As a result, the debt under the senior bank credit facility has been classified as current on the consolidated balance sheet as of December 31, 2005.  In addition, the Company needs to obtain a waiver of this default and an amendment of the representation relating to our 2003 consolidated financial statements before the Company will be able to borrow additional funds under its revolving credit facility. The Company expects to obtain the amendment and waiver in the near term.

On August 15, 2005, the Company repaid at maturity all outstanding 4.5% Convertible Junior Subordinated Debentures (“the Debentures”) at par for an aggregate principal amount of $142 million.

During the first half of 2005, the Company also funded the purchase of the SeaWest wind development business and posted letters of credit to support ongoing construction and operating activities.

Senior Secured Bank Facilities (“Bank Facilities”) include the Senior Secured Term Loan (“Term Loan”) of $200 million and a Revolving Bank Loan with available borrowing up to $650 million. The Revolving Bank Loan matures in 2010 and interest accrues at LIBOR plus 1.75%.

Principal payments required on recourse debt outstanding at December 31, 2005, are $200 million in 2006, $415 million in 2008, $467 million in 2009, $423 million in 2010 and $3,377 million thereafter.

Certain of the Company’s obligations under the Bank Facilities are guaranteed by its direct subsidiaries through which the Company owns its interests in the Shady Point, Hawaii, Warrior Run and Eastern Energy businesses. The Company’s obligations under the Bank Facilities and Second Priority Senior Secured Notes are, subject to certain exceptions, substantially secured by: (i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign

123




subsidiaries owned directly or indirectly by the Company, and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.

The Bank Facilities are subject to mandatory prepayment as follows:

·       Net cash proceeds from sales of assets of or equity interests in IPALCO, a Guarantor or any of their subsidiaries must be applied pro rata to repay the Term Loan using 60% of net cash proceeds, provided that the 60% shall be reduced to 50% when and if the parent’s recourse debt to cash flow ratio is less than 5:1 and further provided that Lenders shall have the option to waive their pro rata redemption. In the case of sales of assets of or equity interests in IPALCO or any of its subsidiaries, asset sale net cash proceeds remaining after application to the Term Loan facility shall be used to reduce commitments under the Revolver, unless the supermajority banks otherwise agree or unless the facilities are rated at least Ba1 from Moody’s and AES’s corporate credit rating is at least BB- from S&P.

·       Net cash proceeds from the issuance of bridge debt by the parent must be offered to repay the Term Loan. With respect to the net cash proceeds from the issuance of debt by IPALCO or any Guarantor after $200 million of additional debt incurred after June 23, 2005 and 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 must be applied pro rata to repay the Term Loan. Lenders shall have the option to accept or refuse such prepayment.

The Bank Facilities contain customary covenants and restrictions on the Company’s ability to engage in certain activities, including, but not limited to:

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

·       restrictions on dividends and redemptions and payments of unsecured and subordinated debt and the use of proceeds;

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

·       maintenance of certain financial ratios; and

·       timely filing of reports to the Securities and Exchange Commission with the lenders (of which the Company had defaults with respect to its Forms 10-Q for the quarter periods ended June 30, 2005 and September 30, 2005).

The Bank Facilities also contain financial covenants requiring the Company to maintain certain financial ratios including:

·       cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company’s adjusted operating cash flow to the Company’s interest charges related to recourse debt must be maintained at all times;

·       recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company’s total recourse debt to the Company’s adjusted operating cash flow must not exceed a maximum at any time of calculation; and future borrowings and letter of credit issuances under the senior secured credit facilities will be subject to customary borrowing conditions, including the absence of an event of default and the absence of any material adverse change.

The terms of the Company’s Second Priority Senior Secured Notes, Senior Unsecured Notes and Senior Subordinated Notes contain certain restrictive covenants, including limitations on the Company’s ability to incur additional debt, pay dividends to stockholders, incur additional liens, provide guarantees and enter into sale and leaseback transactions.

124




On March 3, 2006, the Company redeemed all of its outstanding 8.875% Senior Subordinated Debentures due 2027 (approximately $115 million aggregate principal amount). The redemption was made pursuant to the optional redemption provisions of the indenture governing the Debentures. The Debentures were redeemed at a redemption price equal to 100% of the principal amount thereof, plus a make-whole premium determined in accordance with the terms of the indenture, plus accrued and unpaid interest up to the redemption date.

On March 31, 2006, AES entered into a $600 million senior unsecured credit facility agreement with a maturity date of March 31, 2010. The credit facility is a syndicated loan and letter of credit facility lead arranged by Merrill Lynch.  The credit facility will be used for general corporate purposes and to provide letters of credit to support AES’s investment commitment as well as the underlying funding for the equity portion of its investment in AES Maritza East 1 on an intermediate-term basis. AES Maritza East 1 is a coal-fired generation project that is expected to begin construction soon. Additional non-recourse financing has been committed to begin construction of AES Maritza East 1.

TERM CONVERTIBLE TRUST SECURITIES—During 1999, AES Trust III, a wholly owned special purpose business trust, issued 9 million of $3.375 Term Convertible Preferred Securities (“TECONS”) (liquidation value $50) for total proceeds of approximately $518 million and concurrently purchased approximately $518 million of 6.75% Junior Subordinated Convertible Debentures due 2029 (individually, the 6.75% Debentures).

During 2000, AES Trust VII, a wholly owned special purpose business trust, issued 9.2 million of $3.00 TECONS (liquidation value $50) for total proceeds of approximately $460 million and concurrently purchased approximately $460 million of 6% Junior Subordinated Convertible Debentures due 2008 (individually, the 6% Debentures and collectively with the 6.75% Debentures, the Junior Subordinated Debentures). The sole assets of AES Trust III and VII (collectively, the “TECON Trusts”) are the Junior Subordinated Debentures.

AES, at its option, can redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by AES Trust III, for $50.84 per TECON, reduced annually by $0.422 to a minimum of $50 per TECON. AES, at its option can redeem the 6% Debentures which would result in the required redemption of the TECONS issued by AES Trust VII, for $51.13 per TECONS, reduced annually by $0.375 to a minimum of $50 per TECON. The TECONS must be redeemed upon maturity of the Junior Subordinated Debentures.

The TECONS are convertible into the common stock of AES at each holder’s option prior to October 15, 2029 for AES Trust III and May 14, 2008 for AES Trust VII at the rate of 1.4216 and 1.0811 respectively, representing a conversion price of $35.171 and $46.25 per share, respectively.

Dividends on the TECONS are payable quarterly at an annual rate of 6.75% by AES Trust III and 6% by AES Trust VII. The Trusts are each permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the TECONS would accumulate quarterly and accrue interest, and the Company may not declare or pay dividends on its common stock.

AES Trust III and AES Trust VII are variable interest entities under FASB Interpretation No. 46, “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (“FIN 46”). AES is not the primary beneficiary of either AES Trust III or AES Trust VII and accordingly, does not consolidate their results. AES’s obligations under the Junior Subordinated Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by AES of the TECON Trusts’ obligations under the trust securities issued by each respective trust.

125




9.   DERIVATIVE INSTRUMENTS

AES utilizes derivative financial instruments to hedge interest rate risk, foreign exchange risk and commodity price risk. The Company utilizes interest rate swap, cap and floor agreements to hedge interest rate risk on floating rate debt. The majority of AES’s interest rate derivatives are designated and qualify as cash flow hedges. Currency forward, option and swap agreements are utilized by the Company to hedge foreign exchange risk. The Company utilizes electric and gas derivative instruments, including swaps, options, forwards and futures, to hedge the risk related to electricity and gas sales and purchases. The majority of AES’s electric and gas derivatives are designated and qualify as cash flow hedges.

Certain derivatives are not designated as hedging instruments, primarily because they do not qualify for hedge accounting treatment as defined by SFAS No. 133. The purpose of these instruments is to economically hedge interest rate risk, foreign exchange risk or commodity price risk. However, certain features of these contracts, primarily the inclusion of written options, cause them to not qualify for hedge accounting.

Amounts recorded in accumulated other comprehensive loss, after income taxes, during the years ended December 31, 2005, 2004, and 2003, respectively, are as follows (in millions):

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Balance, beginning of year

 

$

(334

)

$

(270

)

$

(410

)

Reclassification to earnings

 

179

 

126

 

124

 

Reclassification upon sale or disposal

 

 

12

 

130

 

Change in fair value

 

(250

)

(202

)

(114

)

Balance, December 31

 

$

(405

)

$

(334

)

$

(270

)

 

Approximately $128 million of other comprehensive loss related to derivative instruments as of December 31, 2005 is expected to be recognized as a reduction to income from continuing operations over the next twelve months. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for hedges of interest rate risk, as depreciation is recorded for hedges of capitalized interest, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure, and as electric and gas sales and purchases are recognized for hedges of forecasted electric and gas transactions.

The maximum length of time over which AES is hedging its exposure to variability in future cash flows for forecasted transactions, excluding forecasted transactions related to the payment of variable interest, is 25 years. For the years ended December 31, 2005, 2004 and 2003, gains (losses) of $1 million, $(11) million and $(14) million, respectively, were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur. For the years ended December 31, 2005 and 2004, no fair value hedges were discontinued. For the year ended December 31, 2002, two fair value hedges were discontinued because they failed to meet the hedge effectiveness criteria of SFAS No. 133. The discontinuance of hedge accounting for these contracts did not have an impact on earnings.

For the years ended December 31, 2005, 2004 and 2003, the impacts of changes in derivative fair value, net of income taxes, primarily related to derivatives that do not qualify for hedge accounting treatment, were charges of $6 million, $44 million, and $38 million respectively. These amounts include a net gain of $20 million, $2 million after income taxes, and net charges of $12 million after income taxes, related to the ineffective portion of derivatives qualifying as cash flow and fair value hedges for each of the years ended December 31, 2005, 2004 and 2003, respectively. The ineffective portion is primarily recorded in other expense.

126




10.   COMMITMENTS

OPERATING LEASES—As of December 31, 2005, the Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. Rental expense for operating leases, excluding amounts related to the sale/leaseback discussed below, was $12 million, $10 million and $13 million for the years ended December 31, 2005, 2004 and 2003, respectively. The future minimum lease commitments under these leases are as follows (in millions) at December 31, 2005:

2006

 

$

12

 

2007

 

11

 

2008

 

11

 

2009

 

9

 

2010

 

11

 

Thereafter

 

92

 

Total

 

$

146

 

 

CAPITAL LEASES—One of AES’s subsidiaries, AES Indian Queens Power Limited in the United Kingdom, conducts a major part of its operations from leased facilities. The plant lease is for 25 years expiring in 2022. In addition, several AES subsidiaries lease operating and office equipment and vehicles. These leases have been recorded as capital leases in Property, Plant and Equipment within “Electric generation and distribution assets.” Gross values of the leased assets are $52 million and $55 million as of December 31, 2005 and 2004, respectively. The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2005 (in millions):

2006

 

$

5

 

2007

 

5

 

2008

 

4

 

2009

 

4

 

2010

 

3

 

Thereafter

 

54

 

Total minimum lease payments

 

75

 

Less: Imputed interest

 

(31

)

Present value of total minimum lease payments

 

$

44

 

 

SALE/LEASEBACK—In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas (“NYSEG”). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment. Rental expense was $54 million in 2005, 2004 and 2003.

127




In connection with the lease of the two power plants, the subsidiary is required to maintain a rent reserve account equal to the maximum semi-annual payment with respect to the sum of the basic rent (other then deferrable basic rent) and fixed charges expected to become due in the immediately succeeding three-year period. At December 31, 2005, 2004 and 2003, the amount deposited in the rent reserve account approximated $32 million. This amount is included in restricted cash and can only be utilized to satisfy lease obligations. Future minimum lease commitments are as follows (in millions) at December 31, 2005:

2006

 

$

61

 

2007

 

62

 

2008

 

63

 

2009

 

63

 

2010

 

65

 

Thereafter

 

1,062

 

Total minimum lease payments

 

$

1,376

 

 

The lease agreements require the subsidiary to maintain an additional liquidity account. The required balance in the additional liquidity account was initially equal to the greater of $65 million less the balance in the rent reserve account, or $29 million. As of December 31, 2005, the subsidiary had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit issued by Bank of America (formerly Fleet Bank) in the stated amount of approximately $36 million. This letter of credit was established by AES for the benefit of the subsidiary. However, the subsidiary is obligated to replenish or replace this letter of credit in the event it is drawn upon or needs to be replaced.

CONTRACTS—Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties. Purchases in the years ended December 31, 2005, 2004 and 2003 were approximately $1.1 billion, $1.0 billion and $1.1 billion, respectively.

The future commitments under these electricity contracts are as follows (in millions) at December 31, 2005:

2006

 

$

1,088

 

2007

 

1,165

 

2008

 

1,247

 

2009

 

1,329

 

2010

 

1,437

 

Thereafter

 

1,543

 

Total

 

$

7,809

 

 

Operating subsidiaries of the Company have entered into various long-term contracts for the purchase of fuel subject to termination only in certain limited circumstances. Purchases in the years ended December 31, 2005, 2004 and 2003 were approximately $577 million, $510 million and $218 million, respectively.

128




The future commitments under these fuel contracts are as follows (in millions):

2006

 

$

803

 

2007

 

627

 

2008

 

642

 

2009

 

531

 

2010

 

451

 

Thereafter

 

4,551

 

Total

 

$

7,605

 

 

Beginning in 2003, several of the Company’s subsidiaries entered into other various long-term contracts. These contracts are mainly for a compliance construction project, minimum service and maintenance payments, transmission of electricity and other operation services. Purchases in the years ended December 31, 2005, 2004 and 2003 were approximately $78 million, $53 million and $102 million, respectively.

The future commitments under these other purchase contracts are as follows (in millions):

2006

 

$

144

 

2007

 

79

 

2008

 

54

 

2009

 

53

 

2010

 

55

 

Thereafter

 

448

 

Total

 

$

833

 

 

11.   CONTINGENCIES

ENVIRONMENTAL—The Company reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of December 31, 2005, the Company has recorded liabilities of $12 million for projected environmental remediation costs. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information and analysis, the Company believes that it is possible that costs associated with such liabilities or as yet unknown liabilities may exceed current reserves in amounts that could be material but cannot be estimated as of December 31, 2005.

129




GUARANTEES, LETTERS OF CREDIT—In connection with certain of its project financing, acquisition, and power purchase agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a subsidiary on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish the subsidiaries’ intended business purposes.

Contingent contractual obligations

 

 

 

Amount

 

Number of
Agreements

 

Maximum
Exposure Range
for Each
Agreement

 

 

 

(amounts in millions, except agreements and years)

 

Guarantees

 

 

$

507

 

 

 

34

 

 

 

<$1 – $100

 

 

Letters of credit—under the Revolving Bank Loan

 

 

294

 

 

 

18

 

 

 

<$1 – $ 74

 

 

Surety bonds

 

 

1

 

 

 

1

 

 

 

$1

 

 

Total

 

 

$

802

 

 

 

53

 

 

 

 

 

 

 

Most of the contingent obligations primarily represent future performance commitments which the Company expects to fulfill within the normal course of business. Amounts presented in the above table represent the Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure to the Company as of December 31, 2005. Guarantee termination provisions vary from less than 1 year to greater than 20 years. Some result from the end of a contract period, assignment, asset sale, change in credit rating or elapsed time. The amounts above include obligations made by the Company for the benefit of the lenders associated with the non-recourse debt of subsidiaries of $110 million.

The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power purchase agreements for projects in development, under construction and operating. While the Company does not expect to be required to fund any material amounts under these contingent contractual obligations during 2006 or beyond that are not recorded on the balance sheet, many of the events which would give rise to such an obligation are beyond the Company’s control. There can be no assurance that the Company would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder.

The Company pays letter of credit fees ranging from 0.15% to 2.75% per annum on the outstanding amounts.

In addition, several AES subsidiaries obtained letters of credit to guarantee certain requirements under debt or PPA agreements. As of December 31, 2005, $207 million in letters of credit were outstanding.

130




LITIGATION—The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is possible, however, that some matters could be decided unfavorably to the Company, and could require the Company to pay damages or to make expenditures in amounts that could be material but cannot be estimated as of December 31, 2005.

In September 1999, a Brazilian appellate state court of Minas Gerais granted a temporary injunction suspending the effectiveness of a shareholders’ agreement between Southern Electric Brasil Participacoes, Ltda. (“SEB”) and the state of Minas Gerais concerning CEMIG. AES’ investment in CEMIG is through SEB. This shareholders’ agreement granted SEB certain rights and powers in respect of CEMIG (“Special Rights”). In March 2000, a lower state court in Minas Gerais held the shareholders’ agreement invalid where it purported to grant SEB the Special Rights and enjoined the exercise of Special Rights. In August 2001, the state appellate court denied an appeal of the merits decision, and extended the injunction. In October 2001, SEB filed two appeals against the decision on the merits of the state appellate court, one to the Federal Superior Court and the other to the Supreme Court of Justice. The state appellate court denied access of these two appeals to the higher courts, and in August 2002, SEB filed two interlocutory appeals against such decision, one directed to the Federal Superior Court and the other to the Supreme Court of Justice. In December 2004, the Federal Superior Court declined to hear SEB’s appeal. However, the Supreme Court of Justice is considering whether to hear SEB’s appeal. SEB intends to vigorously pursue a restoration of the value of its investment in CEMIG by all legal means; however, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit SEB’s influence on the daily operation of CEMIG.

In November 2000, the Company was named in a purported class action suit along with six other defendants, alleging unlawful manipulation of the California wholesale electricity market, allegedly resulting in inflated wholesale electricity prices throughout California. The alleged causes of action include violation of the Cartwright Act, the California Unfair Trade Practices Act and the California Consumers Legal Remedies Act. In December 2000, the case was removed from the San Diego County Superior Court to the U.S. District Court for the Southern District of California. On July 30, 2001, the Court remanded the case to San Diego Superior Court. The case was consolidated with five other lawsuits alleging similar claims against other defendants. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which reasserted the claims raised in the earlier action and names the Company, AES Redondo Beach, LLC, AES Alamitos, LLC, and AES Huntington Beach, LLC as defendants. In May 2002, the case was removed by certain cross-defendants from the San Diego County Superior Court to the United States District Court for the Southern District of California. The plaintiffs filed a motion to remand the case to state court, which was granted on December 13, 2002. Certain defendants appealed aspects of that decision to the United States Court of Appeals for the Ninth Circuit. On December 8, 2004, a panel of the Ninth Circuit issued an opinion affirming in part and reversing in part the decision of the District Court, and remanding the case to state court. On July 8, 2005, defendants filed a demurrer in state court seeking dismissal of the case in its entirety. On October 3, 2005, the court sustained the demurrer and entered an order of dismissal. On December 2, 2005, plaintiffs filed a notice of appeal. The Company believes that it has meritorious defenses to any actions asserted against it and will defend itself vigorously against the allegations.

In August 2000, the Federal Energy Regulatory Commission (“FERC”) announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. The FERC requested documents from each of the AES Southland plants and AES Placerita. AES Southland and AES Placerita have

131




cooperated fully with the FERC investigation. AES Southland is not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. AES Placerita is currently subject to refund liability of $586,000 for sales to the California Power Exchange. The Ninth Circuit Court of Appeals addressed the appeal of the FERC’s decision not to impose refunds for the alleged failure to file rates including transaction specific data for sales during 2000 and 2001. Although in its order issued on September 9, 2004 the Ninth Circuit did not order refunds, the Ninth Circuit remanded the case to the FERC for a refund proceeding to consider remedial options. That remand order is stayed pending rehearing at the Ninth Circuit. In addition, in a separate case, the Ninth Circuit heard oral arguments on the time and scope of the refunds. Placerita made sales during the time period at issue in the appeals. Depending on the result of the appeals, the method of calculating refunds and the time period to which the method is applied, the alleged refunds sought from AES Placerita could approximate $23 million.

In November 2002, the Company was served with a grand jury subpoena issued on application of the United States Attorney for the Northern District of California. The subpoena sought, inter alia, certain categories of documents related to the generation and sale of electricity in California from January 1998 to the date of the subpoena. The Company cooperated in providing documents in response to the subpoena.

In August 2001, the Grid Corporation of Orissa, India (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to, and approved by, the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appears to seek approximately $188.5 million in damages plus undisclosed penalties and interest, but a detailed alleged damages analysis has yet to be filed by Gridco. The Company has counter-claimed against Gridco for damages. An arbitration hearing with respect to liability was conducted on August 3-9, 2005 in India. Final written arguments regarding liability were submitted by the parties to the arbitral tribunal in late October 2005. A decision on liability may be issued in the near future. A petition remains pending before the Indian Supreme Court concerning fees of the third neutral arbitrator and the venue of future hearings with respect to the CESCO arbitration. The Company believes that it has meritorious defenses to any actions asserted against it and will defend itself vigorously against the allegations.

132




In April 2002, IPALCO and certain former officers and directors of IPALCO were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana. On May 28, 2002, an amended complaint was filed in the lawsuit. The amended complaint asserts that IPALCO and former members of the pension committee for the Indianapolis Power & Light Company thrift plan breached their fiduciary duties to the plaintiffs under the Employees Retirement Income Security Act by investing assets of the thrift plan in the common stock of IPALCO prior to the acquisition of IPALCO by the Company. In December 2002, plaintiffs moved to certify this case as a class action. The Court granted the motion for class certification on September 30, 2003. On October 31, 2003, the parties filed cross-motions for summary judgment on liability. On August 11, 2005, the Court issued an Order denying the summary judgment motions, but striking one defense asserted by defendants. A trial addressing only the allegations of breach of fiduciary duty began on February 21, 2006 and concluded on February 28, 2006. Post trial briefs are due by April 6, 2006, and responses are due by April 20, 2006. A decision will follow sometime thereafter. If the Court rules against the IPALCO defendants, one or more trials on reliance, damages, and other issues will be conducted separately. IPALCO believes it has meritorious defenses to the claims asserted against it and intends to defend this lawsuit vigorously.

In November 2002, Stone & Webster, Inc. (“S&W”) filed a lawsuit against AES Wolf Hollow, L.P. (“AESWH”) and AES Frontier, L.P. (“AESF,” and, collectively with AESWH, “sub-subsidiaries”) in the District Court of Hood County, Texas. At the time of filing, AESWH and AESF were two indirect subsidiaries of the Company, but in December 2004, the Company finalized agreements to transfer the ownership of AESWH and AESF. S&W contracted with AESWH and AESF in March 2002 to perform the engineering, procurement and construction of the Wolf Hollow project, a gas-fired combined cycle power plant in Hood County, Texas. In its initial complaint, filed in November 2002, S&W requested a declaratory judgment that a fire that took place at the project on June 16, 2002 constituted a force majeure event, and that S&W was not required to pay rebates assessed for associated delays. As part of the initial complaint, S&W also sought to enjoin AESWH and AESF from drawing down on letters of credit provided by S&W. The Court refused to issue the injunction, and the sub-subsidiaries drew down on the letters of credit and withheld milestone payments from S&W. S&W has since amended its complaint five times and joined additional parties, including the Company and Parsons Energy & Chemicals Group, Inc. In addition to the claims already mentioned, the current claims by S&W include claims for breach of contract, breach of warranty, wrongful liquidated damages, foreclosure of lien, fraud and negligent misrepresentation. S&W appears to assert damages against the sub-subsidiaries and the Company in the amount of $114 million in recently filed expert reports and seeks exemplary damages. S&W filed a lien against the ownership interests of AESWH and AESF in the property, with each lien allegedly valued, after amendment on March 14, 2005, at approximately $87 million. In January 2004, the Company filed a counterclaim against S&W and its parent, the Shaw Group, Inc. (“Shaw”). AESWH and AESF filed answers and counterclaims against S&W, which since have been amended. The amount of AESWH and AESF’s counterclaims are approximately $215 million, according to calculations of the sub-subsidiaries and of an expert retained in connection with the litigation, minus the Contract balance, not earned as of December 31, 2005, to the knowledge of the Company, in the amount of $45.8 million. In March 2004, S&W and Shaw each filed an answer to the counterclaims. The counterclaims and answers subsequently were amended. In March 2005, the Court rescheduled the trial date for October 24, 2005. In September 2005, the trial date was re-scheduled for June 2006. In November 2005, the Company filed a motion for summary judgment to dismiss the claims asserted against it by S&W. On February 21, 2006 the Court issued a letter ruling granting the Company’s motion for summary judgment and directing the Company to submit a proposed order. On February 22, 2006 the Company submitted a proposed order, which has been objected to by S&W and Shaw. On March 15, 2006, S&W moved to reconsider the Court’s decision granting the Company’s summary judgment motion. A decision on the proposed order and the motion for reconsideration are pending; the Court has yet to enter a final order on the Company’s

133




summary judgment motion. The Company believes that the allegations in S&W’s complaint are meritless, and that it has meritorious defenses to the claims asserted by S&W. The Company intends to defend the lawsuit and pursue its claims vigorously.

In March 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil (“MPF”) notified AES Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgas and the rationing loan provided to AES Eletropaulo, changes in the control of AES Eletropaulo, sales of assets by AES Eletropaulo and the quality of service provided by AES Eletropaulo to its customers, and requested various documents from AES Eletropaulo relating to these matters. In October 2003 this inquiry was sent to the MPF for continuing investigation. Also in March 2003, the Commission for Public Works and Services of the Sao Paulo Congress requested AES Eletropaulo to appear at a hearing concerning the alleged default by AES Elpa and AES Transgas on the BNDES financings and the quality of service rendered by AES Eletropaulo. This hearing was postponed indefinitely. In addition, in April 2003, the office of the MPF notified AES Eletropaulo that it is conducting an inquiry into possible errors related to the collection by AES Eletropaulo of customers’ unpaid past-due debts and requesting the company to justify its procedures. In December 2003, ANEEL answered, as requested by the MPF, that the issue regarding the past-due debts are to be included in the analysis to the revision of the “General Conditions for the Electric Energy Supply.”

In May 2003, there were press reports of allegations that in April 1998 Light Serviços de Eletricidade S.A. (“Light”) colluded with Enron in connection with the auction of AES Eletropaulo. Enron and Light were among three potential bidders for AES Eletropaulo. At the time of the transaction in 1998, AES owned less than 15% of the stock of Light and shared representation in Light’s management and Board with three other shareholders. In June 2003, the Secretariat of Economic Law for the Brazilian Department of Economic Protection and Defense (“SDE”) issued a notice of preliminary investigation seeking information from a number of entities, including AES Brasil Energia, with respect to certain allegations arising out of the privatization of AES Eletropaulo. On August 1, 2003, AES Elpa responded on behalf of AES-affiliated companies and denied knowledge of these allegations. The SDE began a follow-up administrative proceeding as reported in a notice published on October 31, 2003. In response to the Secretary of Economic Law’s official letters requesting explanations on such accusation, AES Eletropaulo filed its defense on January 19, 2004. On April 7, 2005 AES Eletropaulo responded to a SDE request for additional information. On July 11, 2005, the SDE ruled that the case was dismissed due to the passing of the statute of limitations and was subsequently sent to the Superior Council of the SDE for final review of the decision.

AES Florestal, Ltd., (“Florestal”), a wooden utility pole manufacturer located in Triunfo, in the state of Rio Grande do Sul, Brazil, has been operated by Sul since October 1997 as part of the original privatization transaction by the Government of the State of Rio Grande do Sul, Brazil, that created Sul. From 1997 to the present, the chemical compound chromated copper arsenate was used by Florestal to chemically treat the poles under an operating license issued by the Brazilian government. Prior to 1997, another chemical, creosote, was used to treat the poles. After becoming the operator of Florestal, Sul discovered approximately 200 barrels of solid creosote waste on the Florestal property. In 2002, a civil inquiry (Civil Inquiry No. 02/02) was initiated and a criminal lawsuit was filed in the city of Triunfo’s Judiciary both by the Public Prosecutors’ office of the city of Triunfo. The civil lawsuit was settled in 2003, and on June 27, 2005, the criminal lawsuit was dismissed. Florestal hired an independent environmental assessment company to perform an environmental audit of the operational cycle at Florestal. Florestal submitted an action plan that was accepted by the environmental authority under which it voluntarily offered to do containment work at the site. Companhia Estadual de Energia Elétrica (“CEEE”), which controlled Florestal prior to the privatization, has disputed the transfer of Florestal in the privatization, and has sought its return. A court decision recently determined that CEEE has rights of ownership in

134




Florestal, and the company will be returned to CEEE. AES Sul will demand the return of that portion of the purchase price paid in the privatization for Florestal.

On January 27, 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A., Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A.) in the Dominican Republic, violates certain cross ownership restrictions contained in the General Electricity law of the Dominican Republic. On February 10, 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic (“Court”) an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). On or about February 24, 2004, the Court granted the Constitutional Injunction and ordered the immediate cease of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. On March 1, 2004, the Superintendence of Electricity appealed the Court’s decision. The appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and intends to defend this lawsuit vigorously.

In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”), which is the government entity that currently owns 50% of Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), filed two lawsuits against Itabo, an AES affiliate, and another lawsuit against Ede Este, a former indirect subsidiary of AES. The lawsuits against Itabo also name the former president of Itabo as a defendant. In one of the lawsuits against Itabo, CDEEE requested an accounting of all transactions between Itabo and related parties. On November 29, 2004, the First Room of the Court of First Instance of the National District dismissed the case. CDEEE appealed the dismissal to the Second Room of the Court of Appeal of the National District. A hearing was held on May 12, 2005, and Itabo requested that the Court of Appeal of the National District declare that it lacked jurisdiction to decide the matter, in light of the arbitration clause set forth in the contracts executed between Itabo and CDEEE during the Capitalization Process. The Court of Appeal of the National District denied Itabo’s request and ordered that the claims be heard on the merits, but reserved judgment on Itabo’s arguments that the matter should be resolved in an arbitration proceeding. On May 25, 2005, Itabo appealed before the Court of Appeals of Santo Domingo and requested a stay of the May 12, 2005 decision. On October 14, 2005 the Court of Appeals of Santo Domingo upheld Itabo’s request of jurisdictional incompetence, accepting Itabo’s argument that the International Chamber of Commerce (“ICC”) had exclusive jurisdiction over the matter. In the other Itabo lawsuit, CDEEE requested that the Second Room of the Court of Appeal of the National District order Itabo to deliver its accounting books and records for the period from September 1999 to July 2004 to CDEEE. At a hearing on March 30, 2005, Itabo argued that the Court of Appeal of the National District did not have jurisdiction to hear the case, and that the case should be decided in an arbitration proceeding. On October 6, 2005 the Court of Appeal of the National District upheld Itabo’s petition of jurisdictional incompetence and declared that the lawsuit should be decided in an arbitral proceeding. CDEEE filed an appeal of the decision with the First Room of the Court of Appeal of the National District, which is pending. In the Ede Este lawsuit, CDEEE requests an accounting of all of Ede Este’s commercial and financial operations with affiliate companies since August 5, 1999. This lawsuit was dismissed by the First Instance Tribunal of the National District for lack of jurisdiction. CDEEE then filed an identical lawsuit in the First Instance Tribunal of the Santo Domingo Province, which is pending. In a related proceeding, on May 26, 2005, Itabo filed a lawsuit in the United States District Court for the Southern District of New York, seeking to compel CDEEE to arbitrate its claims against Itabo. The petition was denied on July 18, 2005, and Itabo appealed that decision on September 6, 2005. The appeal  is pending. In another related proceeding, on February 9, 2005, Itabo initiated arbitration against CDEEE and the Fondo Patrimonial para el Desarrollo (“FONPER”) in the Arbitral Court of the ICC seeking, among other relief, to enforce

135




the arbitration/dispute resolution provisions in the contracts among the parties. FONPER submitted an answer and a counterclaim while CDEEE submitted only an answer. On March 28, 2006, Itabo and FONPER executed an agreement resolving all of their respective claims in the arbitration.   The settlement agreement will be submitted to the ICC. The arbitration continues as between Itabo and CDEEE. Itabo believes it has meritorious defenses to the allegations asserted against it and will defend itself vigorously against those allegations.

On February 18, 2004, AES Gener S.A. (“Gener SA”), a subsidiary of the Company, filed a lawsuit against Coastal Itabo, Ltd. (“Coastal”), Gener SA’s co-venturer in Itabo, a Dominican Republic power generation company, in the Federal District Court for the Southern District of New York. The lawsuit sought to enjoin the efforts initiated by Coastal to hire an alleged “independent expert,” purportedly pursuant to the Shareholders Agreement between the parties, to perform a valuation of Gener SA’s aggregate interests in Itabo. Coastal asserted that Gener SA had committed a material breach under the parties’ Shareholders Agreement, and therefore, Gener SA was required if requested by Coastal to sell its aggregate interests in Itabo to Coastal at a price equal to 75% of the independent expert’s valuation. Coastal claimed a breach occurred based on alleged violations by Gener SA of purported antitrust laws of the Dominican Republic and breaches of fiduciary duty. Gener SA disputed that any default had occurred. On March 11, 2004, upon motion by Gener SA, the court enjoined disclosure of the valuation performed by the “expert” and ordered the parties to arbitration. On March 11, 2004, Gener SA commenced arbitration proceedings seeking, among other things, a declaration that it had not breached the Shareholders Agreement. Coastal then filed a counterclaim alleging that Gener SA had breached the Shareholders Agreement. On January 4, 2006, Coastal filed a “Withdrawal of Counterclaim” with a “Withdrawal of Notice of Defaults” withdrawing with prejudice its allegations that Gener SA had violated the Shareholders Agreement. On January 25, 2006, the arbitration tribunal heard arguments on the form of the final award and whether to award fees and costs to Gener SA. The arbitration tribunal’s decision on those matters is pending.

Pursuant to the pesification established by the Public Emergency Law and related decrees in Argentina, since the beginning of 2002, the Company’s subsidiary TermoAndes has converted its obligations under its gas supply and gas transportation contracts into pesos. In accordance with the Argentine regulations, payments were made in Argentine pesos at a 1:1 exchange rate. Certain gas suppliers (Tecpetrol, Mobil and Compañía General de Combustibles S.A.), which represented 50% of the gas supply contract, have objected to the payment in pesos. On January 30, 2004, such gas suppliers filed for arbitration with the ICC requesting the re-dollarization of the gas price. TermoAndes replied on March 10, 2004 with a counter-lawsuit related to:  (i) the default of suppliers regarding the most favored nation clause; (ii) the unilateral modification of the point of gas injection by the suppliers; (iii) the obligations to supply the contracted quantities; and (iv) the ability of TermoAndes to resell the gas not consumed. On January 26, 2006, the parties reached agreement resolving all reciprocal claims, including those submitted for arbitration. The settlement agreement was submitted to the arbitration court for it to issue a decision based on the agreed settlement. The arbitration court has yet to issue a decision.

On or about October 27, 2004, Raytheon Company (“Raytheon”) filed a lawsuit against AES Red Oak LLC (“Red Oak”) in the Supreme Court of the State of New York, County of New York. The complaint purports to allege claims for breach of contract, fraud, interference with contractual rights and equitable relief concerning alleged issues related to the construction and/or performance of the Red Oak project. The complaint seeks the return from Red Oak of approximately $30 million that was drawn by Red Oak under a letter of credit that was posted by Raytheon related to the construction and/or performance of the Red Oak project. Raytheon also seeks $110 million in purported additional expenses allegedly incurred by Raytheon in connection with the guaranty and construction agreements entered with Red Oak. In December 2004, Red Oak answered the complaint and filed counterclaims against Raytheon. In January 2005, Raytheon moved for dismissal of Red Oak’s counterclaims. In March 2005, the motion to

136




dismiss was withdrawn and a partial motion for summary judgment was filed by Raytheon seeking return of approximately $16 million of the letter of credit draw. Red Oak submitted its opposition to the partial motion for summary judgment in April 2005. Meanwhile, Raytheon re-filed its motion to dismiss the fraud allegations in the counterclaim. In late April 2005, Red Oak filed its response opposing the renewed motion to dismiss. In December 2005, the Court granted a dismissal of Red Oak’s fraud claim. The Court also ordered the return of approximately $16 million of the letter of credit draw that had yet to be utilized for the performance/construction issues. At the Court’s suggestion, the parties are negotiating whether to deposit the $16 million into a new letter of credit by Raytheon. The parties are conducting discovery. The discovery cut-off is December 15, 2006. Raytheon also filed a related action against Red Oak in the Superior Court of Middlesex County, New Jersey, on May 27, 2005, seeking to foreclose on a construction lien filed against property allegedly owned by Red Oak, in the amount of $31 million. Red Oak was served with the Complaint in September of 2005, and filed its answer, affirmative defenses, and counterclaim in October of 2005. Raytheon has stated that it wishes to stay the New Jersey action pending the outcome of the New York action. Red Oak has not decided whether it wishes to oppose the lien or consent to a stay. Red Oak believes it has meritorious defenses to the claims asserted against it and expects to defend itself vigorously in the lawsuits.

On January 26, 2005, the City of Redondo Beach (“City”), California, sent Williams Power Co., Inc., (“Williams”) and AES Redondo Beach, LLC (“AES Redondo”), an indirect subsidiary of the Company, a notice of assessment for allegedly overdue utility users’ tax (“UUT”) for the period of May 1998 through September 2004, taxing the natural gas used at AES Redondo’s plant to generate electricity during that period. The original assessment included alleged amounts owing of $32.8 million for gas usage and $38.9 million in interest and penalties. The City lowered the total assessment to $56.7 million on July 13, 2005, based on an admitted calculation error. An administrative hearing before the Tax Administrator was held on July 18-21, 2005, to hear Williams’ and AES Redondo’s respective objections to the assessment. On September 23, 2005, the Tax Administrator issued a decision holding AES Redondo and Williams jointly and severally liable for approximately $56.7 million, over $20 million of which is interest and penalties (“September 23 Decision”). On October 7, 2005, AES Redondo and Williams filed an appeal of that decision with the City Manager of Redondo Beach. Under its Ordinance, the City of Redondo Beach was required to hold the appeal hearing within 45 days of the filing of the appeal. The City’s hearing officer, however, has issued a tentative schedule stating that any hearing will be completed by April 21, 2006, and that the “appeal determination” will be issued by May 19, 2006. In addition, in July 2005, AES Redondo filed a lawsuit in Los Angeles Superior Court seeking a refund of UUT that was paid from February 2005 through final judgment of that case, and an order that the City cannot charge AES Redondo UUT going forward. At a February 6, 2006 status conference, the Los Angeles Superior Court stayed AES Redondo’s July 2005 lawsuit until May 22, 2006, after ordering the City and AES Redondo to agree on dates by which the administrative appeal of the September 23 Decision should be finalized. On May 22, 2006, the Court will hold a status conference to determine whether the Court should proceed with AES Redondo’s July 2005 lawsuit. Furthermore, on December 13, 2005, the Tax Administrator sent AES Redondo and Williams two itemized bills for allegedly overdue UUT on the gas used at the facility. The first bill was for $1,274,753.49 in UUT, interest, and penalties on the gas used at the facility from October 1, 2004, through February 1, 2005. The second bill was for $1,757,242.12 in UUT, interest, and penalties on the gas used at the facility from February 2, 2005, through September 30, 2005. Subsequently, on January 21, 2006, the Tax Administrator sent AES Redondo and Williams another itemized bill that assessed $269,592.37 in allegedly overdue UUT, interest, and penalties on gas used at the facility from October 1, 2005, through December 31, 2005. On December 30, 2005, AES Redondo filed objections with the Tax Administrator to the City’s December 13, 2005, January 21, 2006, and any future UUT assessments. A hearing has not been scheduled on those objections, but the City’s Tax Administrator has denied AES Redondo’s objections to the December 13, 2005 UUT assessments based on the findings of his September 23 Decision, which, as noted above, is on appeal. If there is a hearing on the December 13, 2005, and January 21, 2006, UUT

137




assessments, the City’s Tax Administrator has indicated that he will only address the amount of those assessments, but not the merits of them. The Company believes that it has meritorious defenses to the allegations asserted against it and will defend itself vigorously against the allegations.

12.   BENEFIT PLANS

DEFINED CONTRIBUTION PLAN—The Company sponsors one defined contribution plan, qualified under section 401 of the Internal Revenue Code, which is available to eligible AES employees. The plan provides for Company matching contributions in Company stock, other Company contributions at the discretion of the Compensation Committee of the Board of Directors in Company stock, and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company’s matching contributions. Participants vest in other Company contributions ratably over a five-year period ending on the 5th anniversary of their hire date. Company contributions to the plans were approximately $17 million, $16 million and $14 million for the years ended December 31, 2005, 2004 and 2003, respectively.

DEFINED BENEFIT PLANS—Certain of the Company’s subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings. Of the twenty one defined benefit plans, two are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.

 

 

2005

 

2004

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

 

 

($ in millions)

 

CHANGE IN BENEFIT OBLIGATION:

 

 

 

 

 

 

 

 

 

Benefit obligation at beginning of year

 

$

475

 

$

2,409

 

$

470

 

$

2,039

 

Service cost

 

5

 

5

 

4

 

4

 

Interest cost

 

28

 

296

 

27

 

232

 

Employee Contributions

 

 

15

 

 

10

 

Plan amendments

 

7

 

3

 

2

 

1

 

Plan curtailments

 

 

(1

)

 

 

Benefits paid

 

(30

)

(251

)

(30

)

(194

)

Effect of plan combinations

 

 

20

 

 

9

 

Actuarial loss

 

39

 

20

 

2

 

119

 

Effect of foreign currency exchange rate change

 

 

277

 

 

189

 

Benefit obligation as of December 31

 

$

524

 

$

2,793

 

$

475

 

$

2,409

 

 

 

 

2005

 

2004

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

 

 

($ in millions)

 

CHANGE IN PLAN ASSETS:

 

 

 

 

 

 

 

 

 

Fair value of plan assets at beginning of year

 

$

354

 

$

1,549

 

$

341

 

$

1,162

 

Actual return on plan assets

 

27

 

263

 

32

 

297

 

Employer contributions

 

21

 

207

 

11

 

146

 

Employee contributions

 

 

15

 

 

10

 

Benefits paid

 

(30

)

(251

)

(30

)

(194

)

Effect of foreign currency exchange rate change

 

 

184

 

 

127

 

Fair value of plan assets as of December 31

 

$

372

 

$

1,967

 

$

354

 

$

1,548

 

 

138




 

 

2005

 

2004

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

 

 

($ in millions)

 

RECONCILIATION OF FUNDED STATUS

 

 

 

 

 

 

 

 

 

Fair value of plan assets

 

$

372

 

$

1,967

 

$

354

 

$

1,548

 

Benefits obligations

 

524

 

2,793

 

475

 

2,409

 

Funded status

 

(152

)

(826

)

(121

)

(861

)

Unrecognized transistion asset

 

 

(11

)

(1

)

(16

)

Unrecognized prior service cost

 

22

 

6

 

17

 

2

 

Unrecognized net actuarial loss

 

118

 

281

 

80

 

310

 

Net amount recognized at end of year

 

$

(12

)

$

(550

)

$

(25

)

$

(565

)

 

 

 

2005

 

2004

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

 

 

($ in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

AMOUNTS RECOGNIZED ON THE
CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

 

 

 

Accrued benefit liability

 

$

(152

)

 

$

(855

)

 

$

(121

)

 

$

(905

)

 

Intangible asset

 

22

 

 

 

 

17

 

 

20

 

 

Equity of minority shareholders

 

 

 

48

 

 

 

 

40

 

 

Accumulated other comprehensive income

 

118

 

 

257

 

 

79

 

 

280

 

 

Net amount recognized at end of year

 

$

(12

)

 

$

(550

)

 

$

(25

)

 

$

(565

)

 

 

 

 

2005

 

2004

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

 

 

($ in millions)

 

Accumulated Benefit Obligation

 

$

520

 

$

2,756

 

$

471

 

$

2,386

 

Information for pension plans with an accumulated benefit obligation inexcess of plan assets:

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

$

524

 

$

2,697

 

$

475

 

$

2,315

 

Accumulated benefit obligation

 

$

520

 

$

2,662

 

$

471

 

$

2,295

 

Fair value of plan assets

 

$

372

 

$

1,839

 

$

354

 

$

1,450

 

Information for pension plans with a projected benefit obligation in excess of plan assets:

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

$

524

 

$

2,698

 

$

475

 

$

2,317

 

Fair value of plan assets

 

$

372

 

$

1,839

 

$

354

 

$

1,450

 

 

139




All but three of the Company’s subsidiaries use a December 31 measurement date. The remaining three subsidiaries use either a November 30 or October 31 measurement date. Significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost are as follows:

 

 

2005

 

2004

 

2003

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

Benefit Obligation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rates

 

5.82

%

 

12.43

%

 

5.98

%

 

11.98

%

 

6.01

%

 

11.80

%

 

Rates of compensation increase

 

4.75

%

 

6.96

%

 

4.75

%

 

6.97

%

 

4.75

%

 

6.80

%

 

Periodic Benefit Cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

5.98

%

 

11.98

%

 

6.01

%

 

12.09

%

 

6.75

%

 

10.70

%

 

Expected long-term rate of return on plan assets 

 

8.00

%

 

11.81

%

 

8.49

%

 

11.76

%

 

8.51

%

 

14.30

%

 

Rate of compensation increase

 

4.75

%

 

6.97

%

 

4.75

%

 

7.10

%

 

4.75

%

 

7.40

%

 

 

A subsidiary of the Company has a defined benefit obligation of $494 million and $446 million at December 31, 2005 and 2004, respectively, and uses salary bands to determine future benefit costs rather than a rate of compensation increases. Rates of compensation increases in the table above do not include amounts related to this specific defined benefit plan.

 

 

2005

 

2004

 

2003

 

Components of Net Periodic Benefit Cost:

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

 

 

 

 

($ in millions)

 

Service cost

 

$

5

 

 

$

5

 

 

$

4

 

 

$

4

 

 

$

4

 

 

$

8

 

 

Interest cost

 

28

 

 

296

 

 

27

 

 

232

 

 

27

 

 

207

 

 

Expected return on plan assets

 

(28

)

 

(195

)

 

(28

)

 

(134

)

 

(23

)

 

(110

)

 

Amortization of intital net obligation (asset)

 

(1

)

 

(3

)

 

(1

)

 

(3

)

 

(1

)

 

 

 

Amortization of prior service cost

 

1

 

 

 

 

2

 

 

 

 

1

 

 

 

 

Amortization of net (gain) loss

 

3

 

 

5

 

 

4

 

 

8

 

 

3

 

 

32

 

 

Total pension cost

 

$

8

 

 

$

108

 

 

$

8

 

 

$

107

 

 

$

11

 

 

$

137

 

 

 

For the years ended December 31, 2005, 2004 and 2003, $(6) million, $18 million and $286 million, respectively, were included in other comprehensive income arising from a change in the additional minimum pension liability.

The Company’s target allocation for 2006 and pension plan asset allocation at December 31, 2005 and 2004 are as follows:

 

 

 

 

 

 

Percentage of Plan Assets

 

 

 

 

 

as of December 31,

 

 

 

Target Allocation

 

2005

 

2004

 

Asset Category

 

 

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

U.S.

 

Foreign

 

Equity Securities

 

0% – 63%

 

0% – 20%

 

62.76

%

24.96

%

63.27

%

20.75

%

Debt Securities

 

0% – 33%

 

0% – 77%

 

33.50

%

70.49

%

36.26

%

75.21

%

Real Estate

 

0% – 4%

 

0% – 2%

 

3.74

%

2.98

%

0.00

%

2.54

%

Other

 

0%

 

0% – 1%

 

0.00

%

1.57

%

0.47

%

1.50

%

Total

 

 

 

 

 

100.00

%

100.00

%

100.00

%

100.00

%

 

The U.S. Plans seek to achieve the following long-term investment objectives:

·       Maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;

140




·       Long-term rate of return in excess of the annualized inflation rate;

·       Long-term rate of return (net of relevant fees that meet or exceed the assumed actuarial rate);

·       Long term competitive rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates.

Consistent with the above, the allocation is reviewed intermittently to determine a suitable asset allocation which seeks to control risk through portfolio diversification and takes into account, among possible other factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends.

The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk. Our assumed asset allocation uses a lower exposure to equities to closely match market conditions and near term forecasts.

The scheduled cash flows for U.S. and foreign expected employer contributions and expected future benefit payments are as follows (in millions):

 

 

U.S.

 

Foreign

 

Expected employer contribution in 2006

 

$

3

 

$

206

 

Expected benefit payments for fiscal year ending:

 

 

 

 

 

2006

 

$

30

 

$

252

 

2007

 

$

30

 

$

259

 

2008

 

$

31

 

$

271

 

2009

 

$

31

 

$

281

 

2010

 

$

32

 

$

291

 

2011 – 2015

 

$

173

 

$

1,637

 

 

13.   FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of current financial assets, current financial liabilities, and debt service reserves and other deposits are estimated to be equal to their reported carrying amounts. The fair value of non-recourse debt, excluding capital leases, is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow analyses. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards and swaps, and energy derivatives is the estimated net amount that the Company would receive or pay to terminate the agreements as of the balance sheet date.

The estimated fair values of the Company’s assets and liabilities have been determined using available market information. The estimates are not necessarily indicative of the amounts the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

141




The estimated fair values of the Company’s short-term investments, debt and derivative financial instruments as of December 31, 2005 and 2004 are as follows (in millions):

 

 

2005

 

2004

 

 

 

Current
Carrying
Amount

 

Noncurrent
Carrying
Amount

 

Fair
Value

 

Current

Carrying
Amount

 

Noncurrent
Carrying
Amount

 

Fair
Value

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term investments

 

 

$

203

 

 

 

$

 

 

$

203

 

 

$

268

 

 

 

$

 

 

$

268

 

Energy derivatives

 

 

$

19

 

 

 

$

136

 

 

$

155

 

 

$

26

 

 

 

$

161

 

 

$

187

 

Foreign currency forwards and swaps

 

 

$

3

 

 

 

$

 

 

$

3

 

 

$

52

 

 

 

$

 

 

$

52

 

Interest rate swaps

 

 

$

2

 

 

 

$

3

 

 

$

5

 

 

$

4

 

 

 

$

2

 

 

$

6

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-recourse debt

 

 

$

1,598

 

 

 

$

11,226

 

 

$

13,670

 

 

$

1,619

 

 

 

$

11,817

 

 

$

14,355

 

Recourse debt

 

 

$

200

 

 

 

$

4,682

 

 

$

5,139

 

 

$

142

 

 

 

$

5,010

 

 

$

5,621

 

Energy derivatives

 

 

$

201

 

 

 

$

118

 

 

$

319

 

 

$

82

 

 

 

$

38

 

 

$

120

 

Foreign currency forwards and swaps

 

 

$

47

 

 

 

$

57

 

 

$

104

 

 

$

66

 

 

 

$

42

 

 

$

108

 

Interest rate swaps

 

 

$

31

 

 

 

$

140

 

 

$

171

 

 

$

69

 

 

 

$

183

 

 

$

252

 

Interest rate caps and floors

 

 

$

3

 

 

 

$

14

 

 

$

17

 

 

$

8

 

 

 

$

18

 

 

$

26

 

 

Amounts in the table above include the carrying amount and fair value of financial instruments of discontinued operations and assets held for sale.

The fair value estimates presented herein are based on pertinent information as of December 31, 2005 and 2004. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2005.

14.   STOCKHOLDERS’ EQUITY

SALE OF STOCK—In June 2003, the Company sold 49.5 million shares of common stock at $7.00 per share. Net proceeds from the offering were $334 million.

SHARES ISSUED FOR DEBT—During 2004, the Company issued 19.7 million shares of common stock at an average price of $8.52 per share, in exchange for approximately $165 million in Senior Subordinated Notes. This resulted in a gain on retirement of debt of approximately $5 million for the year ended December 31, 2004.

During 2003, the Company issued 12.2 million shares of common stock at an average price of $5.12 per share, in exchange for approximately $77 million in Senior Subordinated Notes. This resulted in a gain on retirement of debt of approximately $14 million for the year ended December 31, 2003.

SUBSIDIARY SALE OF STOCK FOR FORGIVENESS OF DEBT—On December 22, 2003, the Company concluded negotiations with the Brazilian National Development Bank (“BNDES”) and its wholly owned subsidiary, BNDES Participações S.A. (“BNDESPAR”), to restructure the outstanding indebtedness of the Company’s Brazilian subsidiaries AES Transgas and AES Elpa, the holding companies of AES Eletropaulo (“BNDES Debt Restructuring”). On January 19, 2004 and on January 23, 2004, approvals were received on the BNDES Debt Restructuring from ANEEL and the Brazilian Central Bank, respectively. The transaction became effective on January 30, 2004 after the required approvals were obtained and a payment of $90 million was made by AES to BNDES.

142




Under the BNDES Debt Restructuring, all of the Company’s equity interests in AES Eletropaulo, AES Uruguaiana Empreendimentos Ltda. (“AES Uruguaiana”) and AES Tietê S.A. (“AES Tietê”) were transferred to Brasiliana Energia, S.A. (“Brasiliana Energia”), a holding company created for the debt restructuring. The debt at AES Elpa and AES Transgas was also transferred to Brasiliana Energia.

In exchange for the termination of $863 million of outstanding Brasiliana Energia debt and accrued interest during 2004, the Brazilian National Development Bank (“BNDES”) received $90 million in cash, 53.85% ownership of Brasiliana Energia and a one-year call option (“Sul Option”) to acquire a 53.85% ownership interest of Sul. The Sul Option, which would require the Company to contribute its equity interest in Sul to Brasiliana Energia, became exercisable on December 22, 2005. The probability of BNDES exercising the Sul Option is unknown at this time. BNDES’s ability to exercise the Sul Option is contingent upon several factors. The most significant factor requires BNDES to obtain consent for the exercise of the option from the Sul syndicated lenders. In the event BNDES exercises its option, 100% of the Company’s ownership in Sul would be transferred to Brasiliana Energia and the Company would be required to recognize a non-cash estimated loss on its investment in Sul currently estimated at approximately $521 million. This amount primarily includes the recognition of currency translation losses and recording minority interest for BNDES’s share of Sul offset by the recorded estimated fair value of the Sul Option. If the Company’s ownership in Sul was transferred to Brasiliana Energia, the Company’s ownership share would be reduced from approximately 100% to 46%.  The debt refinancing was accounted for as a modification of a debt instrument; therefore, the $20 million of face value of remaining debt due in excess of carrying value will be amortized using the effective interest rate method over the life of the debt.

To effect the new ownership structure, Brasiliana Energia issued 50.01% of its common shares to AES and the remainder to BNDES. It also issued a majority of its non-voting preferred shares to BNDES. As a result, BNDES effectively owns 53.85% of the total capital of Brasiliana Energia. Pursuant to the shareholders’ agreement, AES controls Brasiliana Energia through its ownership of a majority of the voting shares of the company.

As a result of the stock issuance, AES recorded minority interest of $189 million for BNDES’s share of Brasiliana Energia. In addition, the estimated fair value of the Sul Option of $37 million was recorded as a liability and will be marked-to-market in future quarters to reflect the changes in the underlying value of AES Sul, prior to BNDES’s exercise or the expiration of its call option. The value of the Sul Option as of December 31, 2005 remained $37 million.

AES treated the issuance of new shares in Brasiliana Energia to BNDES as a capital transaction in accordance with SAB 51. The net gain of $473 million has been reported as an adjustment to AES’s additional paid-in capital on the accompanying consolidated balance sheet. The remaining outstanding debt owed to BNDESPAR by Brasiliana Energia includes approximately $510 million of convertible debentures, non-recourse to AES (“Convertible Debentures”). The U.S. dollar denominated Convertible Debentures bear interest at a nominal stated rate of 9.0% per annum, an effective rate of 9.32%, and will amortize over an 11 year period with principal repayments beginning in 2007. Principal payments of $20 million, $45 million and $445 million will be due in 2007, 2008 and thereafter, respectively. Brasiliana Energia may not pay any dividends until 2007, at which point it may pay dividends up to 10% of its available cash to its shareholders.

In the event of a default under the Convertible Debentures, the debentures can be converted by BNDESPAR into common shares of Brasiliana Energia in an amount sufficient to give BNDESPAR operational and managerial control of Brasiliana Energia. Under the terms of the BNDES Debt Restructuring, the Company will, subject to certain protective rights granted to BNDESPAR under the Restructuring Documents, retain operational and managerial control of AES Eletropaulo, AES Uruguaiana and AES Tietê as long as no default under the Convertible Debentures occurs. In the event of a default, a provision for default and penalty interest would be payable to BNDESPAR.

143




RESTRICTED STOCK—The Company issued restricted stock units under its long-term compensation plan during 2004 and 2005. The restricted stock units are generally granted based upon a percentage of the participant’s base salary. The units have a three-year vesting schedule and vest in one-third increments over the three year period. The units are then required to be held for an additional two years before they can be redeemed for shares, and thus become transferable. Shares issued to officers of the Company are issued at a premium since the vesting is subject to meeting specific performance objectives. The Company issued 1,031,082 restricted stock units in 2005 and 1,847,670 in 2004, and recorded approximately $10 million and $5 million in compensation expense related to these awards for 2005 and 2004, respectively.

STOCK OPTIONS—The Company grants options to purchase shares of common stock under three stock option plans. Under the terms of the plans, the Company may issue options to purchase shares of the Company’s common stock at a price equal to 100% of the market price at the date the option is granted. Generally, stock options issued under this plan become exercisable by employees in as little as one year (100% in one year), or as many as four years (25% each year). At December 31, 2005, 13,878,639 shares were remaining for award under the plans. The maximum term of the options granted is 10 years.

A summary of the option activity follows (in thousands of shares):

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

Weighted-

 

 

 

Weighted-

 

 

 

Weighted-

 

 

 

 

 

Average

 

 

 

Average

 

 

 

Average

 

 

 

 

 

Exercise

 

 

 

Exercise

 

 

 

Exercise

 

 

 

Shares

 

Price

 

Shares

 

Price

 

Shares

 

Price

 

Outstanding—beginning of year

 

39,162

 

 

$

14.19

 

 

40,816

 

 

$

13.59

 

 

33,244

 

 

$

16.37

 

 

Exercised during the year

 

(4,772

)

 

5.70

 

 

(3,251

)

 

4.50

 

 

(570

)

 

5.18

 

 

Forfeited and expired during the year

 

(847

)

 

16.40

 

 

(1,133

)

 

10.12

 

 

(976

)

 

12.61

 

 

Granted during the year

 

1,514

 

 

16.80

 

 

2,730

 

 

8.98

 

 

9,118

 

 

2.97

 

 

Outstanding—end of year

 

35,057

 

 

$

15.51

 

 

39,162

 

 

$

14.19

 

 

40,816

 

 

$

13.59

 

 

Eligible for exercise—end of year

 

31,960

 

 

$

15.82

 

 

32,737

 

 

$

15.96

 

 

31,910

 

 

$

16.56

 

 

 

The following table summarizes information about stock options outstanding at December 31, 2005 (in thousands of shares):

 

 

Options Outstanding

 

Options Exercisable

 

 

 

 

 

Weighted-

 

Weighted-

 

 

 

Weighted-

 

 

 

 

 

Average

 

Average

 

 

 

Average

 

 

 

Total

 

Remaining

 

Exercise

 

Total

 

Exercise

 

Range of Exercise Prices

 

 

 

Outstanding

 

Life

 

Price

 

Exercisable

 

Price

 

 

 

 

 

(In Years)

 

 

 

 

 

 

 

$ 0.78 – $ 3.24

 

 

5,581

 

 

 

7.0

 

 

 

$

2.74

 

 

 

5,431

 

 

 

$

2.74

 

 

$ 3.25 – $ 9.88

 

 

2,597

 

 

 

7.3

 

 

 

8.62

 

 

 

1,115

 

 

 

8.18

 

 

$ 9.89 – $14.40

 

 

18,274

 

 

 

5.4

 

 

 

13.04

 

 

 

18,265

 

 

 

13.04

 

 

$14.41 – $22.85

 

 

4,225

 

 

 

4.8

 

 

 

17.49

 

 

 

2,771

 

 

 

17.85

 

 

$22.86 – $58.00

 

 

4,371

 

 

 

4.7

 

 

 

44.26

 

 

 

4,369

 

 

 

44.26

 

 

$58.01 – $80.00

 

 

9

 

 

 

4.7

 

 

 

61.42

 

 

 

9

 

 

 

61.42

 

 

Total

 

 

35,057

 

 

 

5.6

 

 

 

$

15.51

 

 

 

31,960

 

 

 

$

15.82

 

 

 

144




The weighted average fair value of each option grant has been estimated as of the date of grant primarily using the Black-Scholes option-pricing model with the following weighted average assumptions:

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Interest rate (risk-free)

 

4.47

%

3.83

%

4.25

%

Volatility

 

53

%

62

%

69

%

Dividend yield

 

 

 

 

 

Using these assumptions, and an expected option life of approximately 10 years, the weighted average fair value of each stock option granted was $11.51, $6.58 and $2.65, for the years ended December 31, 2005, 2004 and 2003, respectively.

ACCUMULATED OTHER COMPREHENSIVE LOSS—The balances comprising accumulated other comprehensive loss are as follows (in millions):

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

Foreign currency translation adjustment

 

$

3,029

 

$

3,086

 

Unrealized derivative losses

 

405

 

334

 

Minimum pension liability

 

227

 

221

 

TOTAL

 

$

3,661

 

$

3,641

 

 

15.   OTHER INCOME (EXPENSE)

The components of other income are summarized as follows (in millions):

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Gain on sale of assets

 

$

10

 

$

14

 

$

 

Gain on extinguishment of liabilities

 

70

 

78

 

141

 

Legal/dispute settlement

 

9

 

11

 

 

Other income

 

72

 

60

 

30

 

Total other income

 

$

161

 

$

163

 

$

171

 

 

The components of other expense are summarized as follows (in millions):

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Marked-to-market loss on commodity derivatives

 

$

 

$

(5

)

$

(23

)

Loss on sale and disposal of assets

 

(39

)

(23

)

 

Loss on extinguishment of liabilities

 

(17

)

(38

)

(39

)

Legal/dispute settlement

 

(2

)

(5

)

 

Other expenses

 

(84

)

(80

)

(44

)

Total other expense

 

$

(142

)

$

(151

)

$

(106

)

 

16.   OTHER SALES OF ASSETS AND ASSET IMPAIRMENT EXPENSES

All of the gains (losses) discussed below are included in loss on sale of investments and asset impairment expense in the accompanying consolidated statements of operations.

During the fourth quarter of 2004, AES made a decision to sell Aixi, a coal-fired power plant located in China, due to circumstances surrounding its operational performance. In accordance with

145




SFAS No. 144, the recoverability of this asset group was tested and as a result, a pre-tax impairment charge of $15 million was recorded. Aixi is included in continuing operations and is reported in the contract generation segment.

In November 2004, AES wrote off $25 million of capitalized costs associated with emission-related improvements constructed at Deepwater, a petroleum coke-fire cogeneration plant, when it was determined that a different strategy would be used to reduce emissions and that the improvements had no alternative uses. Deepwater is reported in the competitive supply segment.

In December 2003, AES sold an approximate 39% ownership interest in AES Oasis Limited (“AES Oasis”) for cash proceeds of approximately $150 million. The loss realized on the transaction was approximately $36 million before and after income taxes. AES Oasis is an entity that owns an electric generation project in Oman (AES Barka) and two oil-fired generating facilities in Pakistan (AES Lal Pir and AES Pak Gen). AES Barka, AES Lal Pir, and AES Pak Gen are all contract generation businesses.

During the fourth quarter of 2003, the Company decided to discontinue the development of ZEG, a contract generation plant under construction in Poland. In connection with this decision, the Company wrote off its investment in ZEG of approximately $23 million before income taxes ($21 million after tax).

On August 8, 2003, the Company decided to discontinue the construction and development of AES Nile Power in Uganda (“Bujagali”). In connection with this decision, the Company wrote off its investment in Bujagali of approximately $76 million before income taxes ($67 million after tax) in the third quarter of 2003. Bujagali was a developing contract generation business.

During April 2003, after consideration of existing business conditions and future opportunities associated with the El Faro development project in Honduras, the Company decided to sell this project. The project was reported in the contract generation segment. The carrying amount of the investment in El Faro exceeded its fair value. As a result during the second quarter of 2003, AES wrote off its investment of approximately $20 million, before income taxes ($13 million after tax). In January 2004, the Company completed the sale of the project for nominal consideration.

17.   INCOME TAXES

INCOME TAX PROVISIONThe expense for income taxes on continuing operations consists of the following (in millions):

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Federal:

 

 

 

 

 

 

 

Current

 

$

3

 

$

7

 

$

5

 

Deferred

 

20

 

32

 

(56

)

State:

 

 

 

 

 

 

 

Current

 

1

 

 

1

 

Deferred

 

(11

)

36

 

(24

)

Foreign:

 

 

 

 

 

 

 

Current

 

351

 

200

 

233

 

Deferred

 

101

 

84

 

52

 

Total

 

$

465

 

$

359

 

$

211

 

 

146




EFFECTIVE AND STATUTORY RATE RECONCILIATIONA reconciliation of the U.S. statutory Federal income tax rate to the Company’s effective tax rate as a percentage of income before taxes is as follows:

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Statutory Federal tax rate

 

 

35

%

 

 

35

%

 

 

35

%

 

State taxes, net of Federal tax benefit

 

 

 

 

 

4

 

 

 

(3

)

 

Taxes on foreign earnings

 

 

 

 

 

8

 

 

 

16

 

 

Valuation allowance

 

 

(3

)

 

 

(3

)

 

 

(8

)

 

Taxes on Domesticated Entities

 

 

1

 

 

 

1

 

 

 

2

 

 

Other—net

 

 

(1

)

 

 

(1

)

 

 

(9

)

 

Effective tax rate

 

 

32

%

 

 

44

%

 

 

33

%

 

 

DEFERRED INCOME TAXESDeferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) operating loss and tax credit carry forwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.

As of December 31, 2005, the Company had Federal net operating loss carry forwards for tax purposes of approximately $1.9 billion expiring from 2018 to 2024   Federal general business tax credit carry forwards for tax purposes of approximately $30 million, $28 million of which  expire in year 2006 and $2 million expiring from 2017 to 2020. Federal alternative minimum tax credits of approximately $7 million that carry forward without expiration. As of December 31, 2005, the Company had foreign net operating loss carry forwards of approximately $3.3 billion that expire at various times beginning in 2006 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $52 million, $1 million of which expire in 2008, $33 million of which expire in 2009 to 2017 and $18 million of which carry forward without expiration. The Company had state net operating loss carry forwards as of December 31, 2005 of approximately $2.0 billion expiring in years 2006 to 2025.

The valuation allowance decreased by $26 million during 2005 to $1,380 million at December 31, 2005. This net decrease was primarily the result of the removal of valuation allowance against deferred tax assets at foreign subsidiaries.

The valuation allowance decreased by $225 million during 2004 to $1,406 at December 31, 2004. This net decrease was primarily the result of the removal of valuation allowances attributable to capital loss carry forwards that no longer existed after the capital losses were reclassified to ordinary losses. The valuation allowance also increased due to certain foreign net operating loss carry forwards, the ultimate realization of which is not known at this time.

The valuation allowance increased $215 million during 2003 to $1,631 million at December 31, 2003. This net increase was primarily the result of certain investment tax credits and increases in the Company’s capital loss carry forwards and foreign net operating losses whose ultimate realization is not known at this time.

The Company believes that it is more likely than not that the remaining deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income.

147




Deferred tax assets and liabilities are as follows (in millions):

 

 

December 31,

 

 

 

2005

 

2004

 

Differences between book and tax basis of property

 

$

1,660

 

$

1,358

 

Other taxable temporary differences

 

143

 

333

 

Total deferred tax liability

 

1,803

 

1,691

 

Operating loss carry forwards

 

(1,795

)

(1,700

)

Capital loss carry forwards

 

(233

)

(255

)

Bad debt and other book provisions

 

(504

)

(412

)

Retirement costs

 

(203

)

(258

)

Tax credit carry forwards

 

(86

)

(107

)

Cumulative transaction allowances

 

(276

)

(276

)

Other deductible temporary differences

 

(439

)

(403

)

Total gross deferred tax asset

 

(3,536

)

(3,411

)

Less: valuation allowance

 

1,380

 

1,406

 

Total net deferred tax asset

 

(2,156

)

(2,005

)

Net deferred tax asset

 

$

(353

)

$

(314

)

 

The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.

On October 22, 2004, the American Jobs Creation Act (“the AJCA”) was signed into law. The AJCA includes a deduction of 85% of certain foreign earnings that are repatriated, as defined in the AJCA. The Company conducted an evaluation of the effects of the repatriation provision in accordance with recently issued Treasury Department guidance. As a result, the Company has elected not to apply this provision to qualifying earnings repatriations in 2005.

The Company and certain of its subsidiaries are under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the provision for income taxes. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amount of the tax estimates is reasonable, it is possible that the ultimate outcome of current or future examinations may exceed current reserves in amounts that could be material but cannot be estimated as of December 31, 2005.

Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The Company’s income tax benefits related to the tax status of these operations are estimated to be $79 million, $34 million and $50 million for the years ended December 31, 2005, 2004 and 2003, respectively.

148




Income (loss) from continuing operations before income taxes and minority interest consisted of the following (in millions):

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

U.S.

 

$

(75

)

$

(131

)

$

(158

)

Non-U.S.

 

1,533

 

953

 

802

 

Total

 

$

1,458

 

$

822

 

$

644

 

 

18.   SUBSIDIARY PREFERRED STOCK

Minority interest includes $60 million of cumulative preferred stock of subsidiaries at December 31, 2005 and 2004. The total annual dividend requirement was approximately $3 million at December 31, 2005 and 2004. Each series of preferred stock is redeemable solely at the option of the issuer at prices between $101 and $118 per share.

19.   DISCONTINUED OPERATIONS

Consistent with one of its 2003 strategic initiatives, the Company continued its efforts to sell certain subsidiaries during 2004, all of which were sold as of December 31, 2004. No operations qualified for classification as discontinued operations as of and for the year ended December 31, 2005. All of the business components and gains (losses) discussed below are classified as discontinued operations in the accompanying consolidated statements of operations.

The income (loss) on disposal and impairment, before income taxes is as follows for the years ended December 31, 2004 and 2003 (in millions):

 

 

Years Ended
December 31,

 

Subsidiary

 

 

 

2004

 

2003

 

Wolf Hollow

 

 

$

27

 

 

$

(132

)

EDE Este

 

 

17

 

 

(60

)

Granite Ridge

 

 

30

 

 

(208

)

Gener/Carbones del Cesar

 

 

2

 

 

 

Whitefield

 

 

(1

)

 

 

Columbia I

 

 

(5

)

 

(19

)

Bolivia

 

 

(4

)

 

(29

)

Haripur/Meghnaghat

 

 

(2

)

 

(59

)

Ecogen

 

 

 

 

32

 

Mt. Stuart

 

 

 

 

(2

)

Mountainview

 

 

23

 

 

7

 

CILCORP

 

 

4

 

 

(24

)

Mtkvari/Khrami/Telasi

 

 

(1

)

 

(210

)

Songas/Kelvin Power

 

 

 

 

11

 

Drax

 

 

 

 

148

 

Other

 

 

(3

)

 

14

 

Income (loss) on disposal and impairment, before taxes(1)

 

 

$

87

 

 

$

(531

)


(1)          In 2004, as a result of filing the 2003 tax returns, previously recorded estimates of the tax effect of discontinued businesses were adjusted to reflect the final tax returns.

In December 2003, AES classified its investment in Wolf Hollow, a competitive supply business located in the United States, as held for sale and recorded an impairment charge to reduce the carrying

149




value of Wolf Hollow’s assets to their estimated fair value in accordance with SFAS No. 144. In December 2004, AES reached an agreement to sell 100% of its ownership interest in Wolf Hollow and recorded a net gain, including accruals based on certain contingencies related to the disposal.

In December 2003, the Company classified its investment in the holding company that owns 50% of Empresa Distribuidora de Electricidad de Este (“EDE Este”), a growth distribution company located in Santo Domingo, Dominican Republic, as an asset held for sale. As a result, the Company recorded an impairment charge to reduce the carrying value of the assets to their estimated fair value in accordance with SFAS No. 144. A pre-tax goodwill impairment expense of approximately $68 million was also recorded, as the current fair market value of the business was less than its carrying value. The decline in fair value during 2003 was due, in part, to the continuing devaluation of the Dominican peso and operating losses. In November 2004, AES sold EDE Este and recorded a net gain on the sale.

In December 2003, AES Granite Ridge, a competitive supply business located in the United States, was classified as held for sale. As a result, AES has recorded an impairment charge to reduce the carrying value of the assets to the estimated fair value in accordance with SFAS No. 144. In November 2004, AES disposed of Granite Ridge by transferring ownership of the project to its lenders and recorded a net gain.

In August 2004, AES Gener S.A. (“Gener”), a contract generation subsidiary of the Company, reached an agreement to sell its interest in Carbones del Cesar, a coal mine located in Colombia. The sale resulted in a net gain.

In September 2003, AES reached an agreement to sell 100% of its ownership interest in AES Whitefield, a competitive supply business located in the United States. At December 31, 2003, this business was classified as held for sale in accordance with SFAS No. 144. The sale of AES Whitefield was completed in March 2004 and AES recorded a net loss.

In December 2003, AES classified its interest in AES Colombia I (“Colombia I”), a competitive supply business located in Colombia, as held for sale and recorded an impairment charge to reduce the carrying value of the assets to the estimated fair value in accordance with SFAS No. 144. In September 2004, the Company sold its ownership interest in Colombia I and recorded a net loss.

During the third quarter of 2003, AES Communications Bolivia (“Bolivia”), a competitive supply business, was reported as an asset held for sale and an impairment charge was recorded to reduce the carrying value of the assets to the estimated fair value in accordance with SFAS No. 144. During June 2004, AES completed the sale of its ownership in Bolivia and recorded a net loss.

In December 2003, AES sold 100% of its ownership interest in both AES Haripur Private Ltd. and AES Meghnaghat Ltd., contract generation businesses in Bangladesh. AES recognized a loss on the sale.

In the first quarter of 2003, the Company sold its investment in AES Mt. Stuart and AES Ecogen, both contract generation businesses in Australia.

In December 2002, AES classified its investment in Mountainview Power Company (“Mountainview”), a competitive supply business located in the United States, as held for sale and recorded a pre-tax impairment charge to reduce the carrying value of Mountainview’s assets to estimated fair value in accordance with SFAS No. 144. The determination of the fair value was based on available market information obtained through discussions with potential buyers. In January 2003, the Company entered into an agreement to sell Mountainview for $30 million with another $20 million payment contingent on the achievement of project specific milestones. The transaction closed in March 2003 and resulted in a net gain. In March 2004, the contingencies were resolved, the final payment was received and AES recognized a net gain.

In April 2002, AES reached an agreement to sell 100% of its ownership interest in CILCORP, a utility holding company whose largest subsidiary is Central Illinois Light Company (“CILCO”) and Medina

150




Valley Cogen, a gas-fired cogeneration facility located in CILCO’s service territory. During 2002, goodwill impairment expense was recorded to reduce the carrying amount of the Company’s investment to its estimated fair market value. The fair market value of AES’s investment in CILCORP was estimated using the expected sale price under the related sales agreement. The sale of CILCORP closed in January 2003, and resulted in a loss. In the fourth quarter of 2004, a gain was recorded as a result of the settlement of remaining liabilities. CILCORP was previously reported in the large utilities segment.

In June 2003, AES Mtkvari, AES Khrami and AES Telasi were classified as held for sale and the Company recorded an impairment charge to reduce the carrying value of the assets to their estimated fair value in accordance with SFAS No. 144. In August 2003 these businesses were sold and a net loss was recorded. AES Mtkvari and AES Khrami were previously reported in the contract generation segment and AES Telasi was previously reported in the growth distribution segment.

In December 2002, AES reached an agreement to sell 100% of its ownership interests in Songas Limited (“Songas”) a competitive supply business located in Tanzania and AES Kelvin Power (Pty.) Ltd. a contract generation business located in South Africa. The sales of AES Kelvin, which closed in March 2003, and the sale of Songas, which closed in April 2003, resulted in a gain on sale.

In the fourth quarter of 2002, Drax Power Limited (“Drax”), a competitive supply business, terminated an agreement with TXU EET as a result of TXU EET’s bankruptcy. The agreement had provided Drax above-market prices for the contracted output (equal to approximately 60% of the total output of the plant). This change in circumstance indicated that the carrying value of Drax’s net assets may not be recoverable, thus the Company recorded a pre-tax impairment charge to reduce the net assets of Drax to the estimated fair value in accordance with SFAS No. 144. In September 2003, as a result of TXU EET’s bankruptcy, the Company’s voting rights in the shares in AES Drax Acquisition Limited, Drax’s parent company, were revoked. AES discontinued consolidating Drax and recorded a pre-tax gain in 2003. AES has no continuing involvement in Drax.

In July 2003, the Company sold substantially all the physical assets and operations of AES Barry, a competitive supply business, for £40 million (approximately $62 million). Additionally, the credit agreement was amended to reflect the sale of the AES Barry assets and AES discontinued consolidating the remaining activities of the business. The sale proceeds were used to discharge part of AES Barry’s debt and to pay certain transaction costs and fees. The results of operations of the plant assets sold, which constitute a component, are included in income (loss) from operations of discontinued operations. Interest expense on the debt, which was not part of the disposal group, was included in income from continuing operations during 2003. The interest on the debt was suspended in 2004, in accordance with an agreement reached with the lender. AES Barry is pursuing a £60 million (approximately $93 million) claim (the amount of which is disputed) against TXU Europe Energy Trading Limited (“TXU EET”), which is currently in bankruptcy administration. AES Barry will receive 20% of amounts recovered in excess of £7 million ($11 million) from the administrator. Under the amended credit agreement, AES Barry may pay any excess to its immediate holding company AES Electric. If the proceeds from TXU EET are not sufficient to repay the bank debt, the banks have recourse to the shares of AES Barry, but have no recourse to the Company for a default by AES Barry. In 2002, the Company recorded a pre-tax impairment charge to reduce the net assets of AES Barry as a result of the TXU EET bankruptcy and an assessment of the recoverability of the assets of AES Barry.

151




Information for business components included in discontinued operations is as follows (in millions):

 

 

For the years ended
December 31,

 

 

 

2004

 

2003

 

Revenues

 

$

472

 

$

1,234

 

Loss from operations of discontinued businesses (before taxes)

 

$

(2

)

$

(862

)

Income tax benefit

 

36

 

75

 

Income (loss) from operations of discontinued businesses

 

$

34

 

$

(787

)

 

There were no assets and liabilities associated with discontinued operations or held for sale at December 31, 2005 and 2004.

20.   EARNINGS PER SHARE

Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period, after giving effect to stock splits. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive stock options, warrants, deferred compensation arrangements, and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income from continuing operations. In the table below, income represents the numerator (in millions) and shares represent the denominator (in millions):

 

 

December 31, 2005

 

December 31, 2004

 

December 31, 2003

 

 

 

 

 

 

 

$ per

 

 

 

 

 

$ per

 

 

 

 

 

$ per

 

 

 

Income

 

Shares

 

Share

 

Income

 

Shares

 

Share

 

Income

 

Shares

 

Share

 

BASIC EARNINGS PER SHARE:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 

$

632

 

 

 

653.6

 

 

$

0.96

 

 

$

264

 

 

 

640.6

 

 

 

$

0.41

 

 

 

$

294

 

 

 

594.7

 

 

 

$

0.49

 

 

EFFECT OF DILUTIVE SECURITIES:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock options and warrants

 

 

 

 

 

9.7

 

 

(0.01

)

 

 

 

 

6.9

 

 

 

 

 

 

 

 

 

3.5

 

 

 

 

 

Restricted stock units

 

 

 

 

 

1.1

 

 

 

 

 

 

 

0.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock units allocated to deferred compensation plans

 

 

 

 

 

0.2

 

 

 

 

 

 

 

0.2

 

 

 

 

 

 

 

 

 

0.1

 

 

 

 

 

DILUTED EARNINGS PER SHARE

 

 

$

632

 

 

 

664.6

 

 

$

0.95

 

 

$

264

 

 

 

648.1

 

 

 

$

0.41

 

 

 

$

294

 

 

 

598.3

 

 

 

$

0.49

 

 

 

There were approximately 8,397,912, 26,614,974 and 28,035,227 options outstanding in 2005, 2004 and 2003 that were omitted from the earnings per share calculation because they were anti-dilutive. In 2005, 2004 and 2003, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive.

21.   SEGMENT AND GEOGRAPHIC INFORMATION

AES previously reported its financial results in four business segments of the electricity industry: large utilities, growth distribution, contract generation and competitive supply. After careful review and consideration of the Company’s operating segments during the second quarter, it was determined that the businesses within the large utilities and growth distribution segments were similar in terms of exposure to government regulation of their tariffs and the type of customer base served. The Company further determined that the similarities now outweigh the characteristics of size, location and growth potential that previously differentiated the two regulated distribution segments. Beginning in the second quarter of 2005, the large utilities and growth distribution segments were merged into one segment entitled “regulated utilities.”  The Company’s 2004 and 2003 information has been restated to conform to the 2005 segment presentation.

152




Although the nature of the product is the same in all three segments, the segments are differentiated by the nature of the customers, operational differences, cost structure, regulatory environment and risk exposure.

·       The regulated utilities segment primarily consists of 14 distribution companies in seven countries that maintain a monopoly franchise within a defined service area.

·       The contract generation segment consists of facilities that have contractually limited their exposure to electricity price volatility by entering into long-term (five years or longer) power sales agreements for 75% or more of their output capacity. Exposure to fuel supply risks is also limited through long-term fuel supply contracts or through tolling arrangements. These contractual agreements generally reduce exposure to fuel commodity and electricity price volatility, and thereby increase the predictability of their cash flows and earnings.

·       The competitive supply segment consists primarily of power plants selling electricity to wholesale customers through competitive markets, and as a result, the cash flows and earnings of such businesses are more sensitive to fluctuations in the market price of electricity, natural gas, coal, oil and other fuels.

All income statement information for businesses that were discontinued is segregated and is shown in the line “Income (loss) from operations of discontinued businesses” in the accompanying consolidated statements of operations.

The accounting policies of the three business segments are the same as those described in Note 1. The Company uses gross margin as one of the measures to evaluate the performance of its business segments. Depreciation and amortization at the business segments are included in the calculation of gross margin. Corporate depreciation and amortization is reported within “General and administrative expenses” in the consolidated statements of operations. Equity in earnings is used to evaluate the performance of businesses that are significantly influenced by the Company. Sales between the segments are accounted for at fair value as if the sales were to third parties. All intersegment activity has been eliminated with respect to revenue and gross margin.

153




Information about the Company’s operations and assets by segment is as follows (in millions):

 

 

 

 

 

 

 

 

 

 

 

 

Investment

 

 

 

 

 

 

 

Depreciation

 

 

 

Equity in

 

 

 

in and

 

 

 

 

 

 

 

and

 

Gross

 

Earnings

 

Total

 

Advances to

 

Property

 

 

 

Revenues(1)

 

Amortization

 

Margin(2)

 

(Loss)(3)

 

Assets

 

Affiliates

 

Additions

 

Year Ended December 31, 2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contract Generation

 

 

$

4,137

 

 

 

$

357

 

 

 

$

1,603

 

 

 

$

75

 

 

$

14,289

 

 

$

654

 

 

 

$

577

 

 

Competitive Supply

 

 

1,212

 

 

 

72

 

 

 

338

 

 

 

1

 

 

2,180

 

 

6

 

 

 

52

 

 

Regulated Utilities

 

 

5,737

 

 

 

453

 

 

 

1,237

 

 

 

 

 

12,284

 

 

1

 

 

 

470

 

 

Corporate

 

 

 

 

 

7

 

 

 

 

 

 

 

 

679

 

 

9

 

 

 

44

 

 

Total

 

 

$

11,086

 

 

 

$

889

 

 

 

$

3,178

 

 

 

$

76

 

 

$

29,432

 

 

$

670

 

 

 

$

1,143

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Investment

 

 

 

 

 

 

 

Depreciation

 

 

 

Equity in

 

 

 

in and

 

 

 

 

 

 

 

and

 

Gross

 

Earnings

 

Total

 

Advances to

 

Property

 

 

 

Revenues(1)

 

Amortization

 

Margin(2)

 

(Loss)(3)

 

Assets

 

Affiliates

 

Additions

 

Year Ended December 31, 2004

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contract Generation

 

 

$

3,546

 

 

 

$

329

 

 

 

$

1,428

 

 

 

$

71

 

 

$

13,970

 

 

$

621

 

 

 

$

361

 

 

Competitive Supply

 

 

1,020

 

 

 

66

 

 

 

238

 

 

 

(2

)

 

2,156

 

 

6

 

 

 

53

 

 

Regulated Utilities

 

 

4,897

 

 

 

393

 

 

 

1,116

 

 

 

1

 

 

11,610

 

 

1

 

 

 

445

 

 

Discontinued Businesses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9

 

 

Corporate

 

 

 

 

 

7

 

 

 

 

 

 

 

 

1,187

 

 

27

 

 

 

24

 

 

Total

 

 

$

9,463

 

 

 

$

795

 

 

 

$

2,782

 

 

 

$

70

 

 

$

28,923

 

 

$

655

 

 

 

$

892

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Investment

 

 

 

 

 

 

 

Depreciation

 

 

 

Equity in

 

 

 

in and

 

 

 

 

 

 

 

and

 

Gross

 

Earnings

 

Total

 

Advances to

 

Property

 

 

 

Revenues(1)

 

Amortization

 

Margin(2)

 

(Loss)(3)

 

Assets

 

Affiliates

 

Additions

 

Year Ended December 31, 2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contract Generation

 

 

$

3,108

 

 

 

$

292

 

 

 

$

1,262

 

 

 

$

94

 

 

$

13,267

 

 

$

619

 

 

 

$

583

 

 

Competitive Supply

 

 

880

 

 

 

53

 

 

 

221

 

 

 

 

 

2,147

 

 

7

 

 

 

126

 

 

Regulated Utilities

 

 

4,425

 

 

 

366

 

 

 

976

 

 

 

 

 

11,597

 

 

 

 

 

387

 

 

Discontinued Businesses

 

 

 

 

 

 

 

 

 

 

 

 

 

863

 

 

 

 

 

111

 

 

Corporate

 

 

 

 

 

4

 

 

 

 

 

 

 

 

1,263

 

 

22

 

 

 

21

 

 

Total

 

 

$

8,413

 

 

 

$

715

 

 

 

$

2,459

 

 

 

$

94

 

 

$

29,137

 

 

$

648

 

 

 

$

1,228

 

 


(1)          Intersegment revenues for the years ended December 31, 2005, 2004, and 2003 were $792 million, $431 million and $318 million, respectively. These amounts have been eliminated in consolidation and are excluded from amounts reported.

(2)          For consolidated subsidiaries, the measure of profit or loss used for the Company’s reportable segments is gross margin. Gross margin equals revenues less cost of sales on the consolidated statement of operations for each year presented.

(3)          For equity method investments, the measure of profit or loss used for the Company’s reportable segments is equity in earnings.

154




Revenues are recorded in the country in which they are earned and assets are recorded in the country in which they are located. Information about the Company’s consolidated operations and long-lived assets by country are as follows (in millions):

 

 

 

 

 

 

 

 

Property, Plant and

 

 

 

Revenues

 

Equipment, net

 

 

 

2005

 

2004

 

2003

 

2005

 

2004

 

United States

 

$

2,335

 

$

2,213

 

$

2,158

 

$

5,613

 

$

5,502

 

Non-U.S:

 

 

 

 

 

 

 

 

 

 

 

Brazil

 

3,823

 

2,925

 

2,528

 

3,990

 

3,544

 

Argentina

 

517

 

382

 

228

 

544

 

520

 

Chile

 

542

 

436

 

411

 

796

 

837

 

Venezuela

 

613

 

619

 

608

 

1,847

 

1,873

 

Dominican Republic

 

231

 

168

 

141

 

476

 

483

 

El Salvador

 

377

 

356

 

345

 

233

 

225

 

Pakistan

 

219

 

210

 

186

 

288

 

288

 

United Kingdom

 

219

 

225

 

186

 

332

 

378

 

Cameroon

 

293

 

273

 

209

 

354

 

407

 

Mexico

 

226

 

186

 

169

 

195

 

200

 

Puerto Rico

 

213

 

188

 

178

 

643

 

658

 

Hungary

 

230

 

192

 

218

 

214

 

253

 

Ukraine

 

217

 

190

 

164

 

97

 

89

 

Other Non-U.S.

 

1,031

 

900

 

684

 

3,032

 

2,920

 

Total Non-U.S

 

8,751

 

7,250

 

6,255

 

13,041

 

12,675

 

Total

 

$

11,086

 

$

9,463

 

$

8,413

 

$

18,654

 

$

18,177

 

 

22.   RISKS AND UNCERTAINTIES

POLITICAL AND ECONOMIC RISKS

Brazil

In Brazil, AES has subsidiaries that operate in contract generation and regulated utilities segments of the electricity business. AES Eletropaulo is the Company’s regulated utility business in Sao Paulo, Brazil while Sul is a regulated utility business operating in the state of Rio Grande do Sul. Contract generation facilities include Uruguaiana in Rio Grande do Sul and Tietê in the State of Sao Paulo.

The Brazilian economy continued to show positive results in 2005, especially with respect to inflation and foreign trade balances. However, the economy did not reach the growth levels of other emerging markets such as China and India. The trade balance surplus reached its highest level in history while increased liquidity in the international markets has been positive to the Brazilian economy. In 2006, Brazil is expected to be classified as investment grade by the risk agencies such as Standard & Poor’s and Moody’s.

As a result of these positive economic indicators, the exchange rate improved from 2.66 Brazilian reals per U.S. dollar as of December 31, 2004 to 2.33 Brazilian reals per U.S. dollar as of December 31, 2005. Domestic interest rates started to gradually decrease in September 2005 and are expected to continue to decrease through 2006. The Brazilian Central Bank took advantage of these rates and bought U.S. dollars in order to increase the Brazilian reserves and decrease the portion of the Central Bank’s debt linked to the U.S. dollar.

The crisis in the political environment in 2005 was triggered by corruption allegations involving the president’s Lula party. Consequently, the majority of the activities in Congress concentrated on

155




investigating these allegations. The positive results in the Brazilian economy minimized the possible negative effects of this political crisis.

Despite the growth of Brazilian economy in 2005, there is some uncertainty regarding the country’s ability to sustain this growth over the next few years, especially in the power sector.

Since the beginning of a broad institutional reform (end of 2003), relevant changes have been implemented in the Brazilian power sector regulatory environment, which included the following: the emergence of a dual commercialization environment with a regulated environment for distribution companies, and a free contractual environment for traders and free consumers; the requirement, as of January 2005, for every distribution company to serve 100% of its load, subject to certain penalties; amendments to concession agreements, which modified the pass-through methodology in annual tariff adjustments and periodic tariff resets and excluded taxes on revenues from the regulated tariffs; and the public auction of energy carried out by the new Electric Energy Commercialization Chamber.

The Brazilian power sector continues to be the subject of several measures relating to the development of the New Power Sector Model, which may have a significant impact on AES’s businesses in Brazil. Therefore, there is still some uncertainty regarding the effect of these changes on the power sector as well as on AES’s business interests in Brazil.

Venezuela

In January 2003, the Venezuelan government and the Central Bank of Venezuela (“Central Bank”) agreed to suspend the trading of foreign currencies and to establish new standards for the exchange of foreign currency. Subsequently, in February 2003, the Venezuelan government and the Central Bank entered into a Currency Exchange Agreement (“Exchange Agreement”). The terms of the Exchange Agreement provided for the establishment of an applicable exchange rate, the centralization of the purchase and sale of currencies within the country by the Central Bank, and the incorporation of the Foreign Currency Management Commission (“CADIVI”). CADIVI governs the provisions of the exchange agreement, defines the requirements for the administration of foreign currencies for imports and exports, and authorizes purchases of currencies in the country. From 2003 through 2005, CADIVI authorized exchanges for the majority of EDC’s debt service and U.S. dollar operational obligations.

In March 2005, the Venezuelan government and the Central Bank amended the exchange rates that were established in February 2004 to 2,147 bolivars per U.S. dollar for purchases and 2,150 bolivars per U.S. dollar for sales. The previous exchange rates established in February 2004 were 1,916 bolivars per U.S. dollar for purchases and 1,920 bolivars per U.S. dollar for sales. These actions, combined with potential regulatory or tariff changes, may impact the ability of EDC to distribute cash to the Company in the future. As of December 31, 2004 and 2005, EDC was in compliance with all of its debt covenants.

These circumstances create significant uncertainty surrounding the performance, cash flow and profitability of EDC. However, AES is not required to support any potential cash flow shortfalls or debt service obligations of EDC. AES’s total investment in EDC at December 31, 2005 and 2004 was approximately $1.5 billion and $1.6 billion, respectively, which is net of foreign currency translation losses.

Argentina

AES has several subsidiaries in Argentina operating in the contract generation, competitive supply and regulated utilities segments of the electricity business. Eden/Edes and Edelap are regulated utilities businesses that operate in the province of Buenos Aires. Generating facilities include Alicura, Parana, CTSN, Rio Juramento, TermoAndes and several other smaller hydro facilities. These businesses are experiencing reduced cash flows and certain subsidiaries are in default with respect to all or a portion of their outstanding indebtedness.

156




In 2002, Argentina experienced a political, social and economic crisis that has resulted in significant changes in economic policies and regulations, as well as specific changes in the energy sector. As a result, many new economic measures were adopted by the Argentine government, including abandonment of the country’s fixed dollar-to-peso exchange rate, converting U.S. dollar-denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government also adopted new regulations in the energy sector that repealed U.S. dollar-denominated pricing under existing distribution concessions in Argentina by fixing all prices to consumers in pesos. As a result, the Company changed the functional currency for its businesses in Argentina to the peso effective January 1, 2002. From 2003 through 2005 the political and social situation in Argentina showed signs of stabilization, the Argentine peso appreciated relative to the U.S. dollar and the economy and electricity demand started to recover. In May 2003, a new government was established that introduced changes to the regulations governing the electricity industry. During 2005, the new government was confirmed by the results of the national elections for Congress and new changes to the regulations governing the electricity industry were introduced. These circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES.

The effects of the crisis are not expected to have a significant negative impact on AES’s parent cash flow, due primarily to the non-recourse financing structure in place at most of AES’s Argentine businesses. The effects of the current circumstances on future earnings are much more uncertain and difficult to predict. As of December 31, 2005, AES’s total investment in the competitive supply business in Argentina was approximately $62 million and the total investment in the regulated utilities business was approximately $56 million. These investment amounts are net of foreign currency translation losses.

Dominican Republic

The electricity sector in the Dominican Republic has evolved from a state owned system, to a system regulated from 1997 through 1999 by the Ministry of Industry and Commerce, but without an overall electricity sector plan, and finally, with the passage of the General Electricity Law No. 125-01 (“Law 125-01”), into a system with more concise rules, governed by the Superintendancy of Electricity (“SIE”). However, some of the new resolutions adopted by SIE are in conflict with the regulations created by the Ministry of Industry and Commerce prior to enactment of Law 125-01. The enactment of Law 125-01 should lead to the promotion and development of the national electric infrastructure, and to support the population’s economic growth expectations. The law provides reinforcement and support for most of the rights acquired both prior to and during the reform and capitalization of the formerly state owned energy consortium.

During 2003 and beginning of 2004, the Dominican Republic was shaken by a severe economic, financial and political crisis, caused mainly by the status of the public finances and the bankruptcy of the three main commercial banks. Although the electricity sector has been vulnerable for years, it was this economic downturn and an increase in fuel prices that essentially caused a financial crisis in the Dominican Republic electricity sector. Specifically, the inability to pass through higher fuel prices and the costs of devaluation led to a gap between collections at the distribution companies and the amounts required to pay generators for electricity generated. Some of the regulatory problems included (i) the failure to provide for full pass through of the costs of electricity supply to consumers, and (ii) the failure of the regulator to follow through on subsidy commitments, which has put the distribution companies in the position of effectively financing portions of the subsidy programs.

In January 2005, the Dominican Republic government and the International Monetary Fund (“IMF”) entered into a letter of intent, which describes the policies the Dominican Republic intends to implement in the context of its request for financial support from the IMF. The letter of intent provided, among other things, for a series of steps to be taken by the Dominican Republic government to reform the electricity

157




sector and improve collection rates of the distribution companies from their customers. At the beginning of 2005, the IMF approved a Stand-By Arrangement with the Dominican Republic. Credits from the World Bank and the Inter-American Development Bank were also granted to the Dominican Republic in 2005.

In March 2005, the generators and distributors entered into a Sector Agreement with the Ministry of Finance, Comisión Nacional de Energía (“CNE”), and Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”), whereby the Dominican Republic government committed to stay current with its electricity bills in 2005 and cover the potential deficit of the distribution companies for this period, and the generators agreed to be available to be dispatched. By means of that agreement, the Dominican Republic government provided the distribution companies the amounts needed to remain current on the monthly power payments to generators for most of 2005, but in late 2005, distribution companies began to fall behind on these payments to generators. The electricity sector in the Dominican Republic is currently highly dependent on assistance provided by international lending agencies and multilateral institutions. Consequently, the financial condition of our businesses in the Dominican Republic could be affected by the Dominican Republic government’s ability to comply with these agreements.

RISKS RELATED TO FOREIGN CURRENCIES—AES operates businesses in many foreign environments and such investments in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. The Company’s financial position and results of operations have been significantly affected by fluctuations in the value of the Argentine peso, the Brazilian real, the Dominican Republic peso, the Pakistani rupee, the Venezuelan bolivar, the Euro, and the Chilean peso relative to the U.S. dollar.

RISKS RELATED TO POWER SALES CONTRACTS—Several of the Company’s power plants rely on power sales contracts with one or a limited number of entities for the majority of, and in some case all of, the relevant plant’s output over the term of the power sales contract. The remaining term of the power sales contracts related to the Company’s power plants range from 1 to 26 years. No single customer accounted for 10% or more of total revenues in 2005, 2004 or 2003. The cash flows and results of operations of such plants are dependent on the credit quality of the purchasers and the continued ability of their customers and suppliers to meet their obligations under the relevant power sales contract. If a substantial portion of the Company’s long-term power sales contracts were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company’s business, results of operations and financial condition.

23.   OFF-BALANCE SHEET ARRANGEMENTS AND RELATED PARTY TRANSACTIONS

IPL, a subsidiary of the Company, formed IPL Funding Corporation (“IPL Funding”) in 1996 to purchase, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL. IPL Funding is not consolidated by IPL or IPALCO since it meets requirements set forth in SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” to be considered a qualified special-purpose entity. IPL Funding has entered into a purchase facility with unrelated parties (“the Purchasers”) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million of the receivables purchased from IPL. During 2005, this agreement was extended through May 30, 2006. As of December 31, 2005 and 2004, the aggregate amount of receivables IPL has sold to IPL Funding and IPL Funding has sold to the Purchasers pursuant to this facility was $50 million. Accounts receivable on the Company’s balance sheets are stated net of the $50 million sold.

The net cash flows between IPL and IPL Funding totaled approximately $2 million, $1 million and $1 million for each of the years ended December 31, 2005, 2004 and 2003, respectively. IPL retains

158




servicing responsibilities through its role as a collection agent for the amounts due on the purchased receivables. IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of or otherwise relating to the purchase agreement, subject to certain limitations as defined in purchase agreement. The transfers of such accounts receivable from IPL to IPL Funding are recorded as sales; however, no gain or loss is recorded on the sale.

Under the receivables purchase facility, if IPL fails to maintain certain financial covenants regarding interest coverage and debt to capital, it would constitute a “termination event.” As of December 31, 2005, IPL was in compliance with such covenants.

As a result of IPL’s current credit rating, the facility agent has the ability to (i) replace IPL as the collection agent; and (ii) declare a “lock-box” event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. A termination event would also (i) give the facility agent the option to take control of the lock-box account, and (ii) give the Purchasers the option to discontinue the purchase of new receivables and cause all proceeds of the purchased receivables to be used to reduce the Purchaser’s investment and to pay other amounts owed to the Purchasers and the facility agent. This would have the effect of reducing the operating capital available to IPL by the aggregate amount of such purchased receivables (currently $50 million).

159




24.   SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly Financial Data

The following table summarizes the unaudited quarterly statements of operations for the Company for 2005 and 2004 (in millions, except per share amounts). See footnote 1 for a discussion of the nature of the errors in previously issued consolidated financial statements.

 

 

Quarter ended 2005

 

 

 

March 31

 

June 30

 

September 30

 

December 31

 

Revenues

 

 

$

2,663

 

 

$

2,668

 

 

$

2,782

 

 

 

$

2,973

 

 

Gross Margin

 

 

$

824

 

 

$

526

 

 

$

899

 

 

 

$

929

 

 

Income from continuing operations

 

 

$

124

 

 

$

85

 

 

$

244

 

 

 

$

179

 

 

Discontinued operations

 

 

 

 

 

 

 

 

 

 

 

Cumulative effect of change in accounting principle

 

 

 

 

 

 

 

 

 

(2

)

 

Net income

 

 

$

124

 

 

$

85

 

 

$

244

 

 

 

$

177

 

 

Basic income per share(1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 

$

0.19

 

 

$

0.13

 

 

$

0.38

 

 

 

$

0.27

 

 

Discontinued operations

 

 

 

 

 

 

 

 

 

 

 

Cumulative effect of change in accounting principle

 

 

 

 

 

 

 

 

 

 

 

Basic income per share

 

 

$

0.19

 

 

$

0.13

 

 

$

0.38

 

 

 

$

0.27

 

 

Diluted income per share(1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 

$

0.19

 

 

$

0.13

 

 

$

0.37

 

 

 

$

0.27

 

 

Discontinued operations

 

 

 

 

 

 

 

 

 

 

 

Cumulative effect of change in accounting principle

 

 

 

 

 

 

 

 

 

 

 

Diluted income per share

 

 

$

0.19

 

 

$

0.13

 

 

$

0.37

 

 

 

$

0.27

 

 

 

 

 

Quarter ended 2004

 

 

 

March 31

 

June 30

 

September 30

 

December 31

 

 

 

As Previously

 

As

 

As Previously

 

As

 

As Previously

 

As

 

As Previously

 

As

 

 

 

Reported

 

Restated

 

Reported

 

Restated

 

Reported

 

Restated

 

Reported

 

Restated

 

Revenues

 

 

$

2,256

 

 

 

$

2,256

 

 

 

$

2,262

 

 

 

$

2,262

 

 

 

$

2,422

 

 

 

$

2,422

 

 

 

$

2,523

 

 

 

$

2,523

 

 

Gross Margin

 

 

$

684

 

 

 

$

684

 

 

 

$

656

 

 

 

$

656

 

 

 

$

736

 

 

 

$

736

 

 

 

$

706

 

 

 

$

706

 

 

Income from continuing operations

 

 

$

42

 

 

 

$

36

 

 

 

$

103

 

 

 

$

143

 

 

 

$

86

 

 

 

$

66

 

 

 

$

27

 

 

 

$

19

 

 

Discontinued operations

 

 

(26

)

 

 

(26

)

 

 

(29

)

 

 

(29

)

 

 

7

 

 

 

7

 

 

 

82

 

 

 

82

 

 

Net income

 

 

$

16

 

 

 

$

10

 

 

 

$

74

 

 

 

$

114

 

 

 

$

93

 

 

 

$

73

 

 

 

$

109

 

 

 

$

101

 

 

Basic income per share (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations

 

 

$

0.07

 

 

 

$

0.06

 

 

 

$

0.16

 

 

 

$

0.22

 

 

 

$

0.13

 

 

 

$

0.10

 

 

 

$

0.04

 

 

 

$

0.03

 

 

Discontinued operations

 

 

(0.04

)

 

 

(0.04

)

 

 

(0.04

)

 

 

(0.04

)

 

 

0.01

 

 

 

0.01

 

 

 

0.13

 

 

 

0.13

 

 

Basic income per share

 

 

$

0.03

 

 

 

$

0.02

 

 

 

$

0.12

 

 

 

$

0.18

 

 

 

$

0.14

 

 

 

$

0.11

 

 

 

$

0.17

 

 

 

$

0.16

 

 

Diluted income per share(1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 

$

0.07

 

 

 

$

0.06

 

 

 

$

0.16

 

 

 

$

0.22

 

 

 

$

0.13

 

 

 

$

0.10

 

 

 

$

0.04

 

 

 

$

0.03

 

 

Discontinued operations

 

 

(0.04

)

 

 

(0.04

)

 

 

(0.05

)

 

 

(0.04

)

 

 

0.01

 

 

 

0.01

 

 

 

0.13

 

 

 

0.13

 

 

Diluted income per share

 

 

$

0.03

 

 

 

$

0.02

 

 

 

$

0.11

 

 

 

$

0.18

 

 

 

$

0.14

 

 

 

$

0.11

 

 

 

$

0.17

 

 

 

$

0.16

 

 


(1)             The sum of these amounts does not equal the annual amount due to rounding or because the quarterly calculations are based on varying numbers of shares outstanding.

160




ITEM 9.                 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There were no changes in or disagreements on any matters of accounting principles or financial disclosure between us and our independent auditors.

ITEM 9A.        CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the chief executive officer (“CEO”) and chief financial officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures.

The Company carried out the evaluation required by paragraph (b) of the Exchange Act Rules 13a 15 and 15d 15, under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a 15(e) and 15d 15(e)). Based upon this evaluation, as a result of the material weaknesses described below, the CEO and CFO concluded that as of December 31, 2005, our disclosure controls and procedures were not effective.

To address the control weaknesses described below, the Company performed additional analysis and other post-closing procedures in order to prepare the consolidated financial statements in accordance with generally accepted accounting principles in the United States of America. Accordingly, management believes that the consolidated financial statements included in this 2005 Form 10-K fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Controls over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America and includes those policies and procedures that:

·      pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

·      provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

·      provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of

161




controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Management assessed the effectiveness of our internal controls over financial reporting as of December 31, 2005. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

A material weakness is a significant deficiency (within the meaning of PCAOB Auditing Standard No. 2), or combination of significant deficiencies, that result in there being a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

As reported in Item 9 of the Company’s 2004 Form 10 K/A, management reported that material weaknesses existed in our internal control over financial reporting as of December 31, 2004. Management determined that the following material weaknesses in internal control over financial reporting existed as of December 31, 2005 (which includes material weaknesses reported as of December 31, 2004 that have not been remediated):

Income Taxes:

The Company lacked effective controls for the proper reconciliation of the components of its parent company and subsidiaries’ income tax assets and liabilities to related consolidated balance sheet accounts, including a detailed comparison of items filed in the subsidiaries’ tax returns to the corresponding calculation of U.S. GAAP balance sheet tax accounts. The Company lacked an effective control to ensure that foreign subsidiaries whose functional currency is the U.S. dollar had properly classified income tax accounts as monetary, rather than non-monetary, assets and liabilities at the time of acquisition. These subsidiaries were not re-measuring their deferred tax balances each period in accordance with Financial Accounting Standards Board Statement (“SFAS”) No. 52, Foreign Currency Translation and SFAS No. 109, Accounting for Income Taxes. Finally, the Company determined that it lacked effective controls and procedures for evaluating and recording tax related purchase accounting adjustments to the financial statements. These control deficiencies resulted in adjustments that were required to be made to the consolidated financial statements and are included in this Form 10-K. In addition, these deficiencies could result in a future misstatement of certain account balances that would result in a material misstatement to the annual or interim financial statements.

Aggregation of Control Deficiencies at our Cameroonian Subsidiary:

AES SONEL, a 56% owned subsidiary of the Company located in Cameroon, lacked adequate and effective controls related to transactional accounting and financial reporting. These deficiencies included a lack of timely and sufficient financial statement account reconciliation and analysis, lack of sufficient support resources within the accounting and finance group, inadequate preparation and review of purchase accounting adjustments incorrectly recorded in 2002, and errors in the translation of local currency financial statements to the U.S. Dollar. These deficiencies could result in a future misstatement of certain account balances that would result in a material misstatement to the annual or interim financial statements.

Lack of U.S. GAAP Expertise in Brazilian Businesses:

The Company lacked effective controls to ensure the proper application of certain U.S. GAAP principles, not limited to, SFAS No. 95, Statement of Cash Flows, SFAS No. 71, Accounting for the Effects of

162




Certain Types of Regulation, SFAS No. 87, Employers’ Accounting for Pensions, and SFAS No. 109, Accounting for Income Taxes. In addition, the Company lacked effective controls to ensure appropriate conversion and analysis of Brazilian GAAP to U.S. GAAP financial statements for certain of our Brazilian subsidiaries. These control deficiencies resulted in adjustments that were required to be made to the consolidated financial statements and are included in this Form 10-K. In addition, these deficiencies could result in a future misstatement of certain account balances that would result in a material misstatement to the annual or interim financial statements.

Treatment of Intercompany Loans Denominated in Other Than the Functional Currency:

The Company lacked effective controls to ensure the proper application of SFAS No. 52, Foreign Currency Translation, related to the treatment of foreign currency gains or losses on certain long term intercompany loan balances denominated in other than the entity’s functional currency and lacked appropriate documentation for the determination of certain of its holding companies’ functional currencies. The Company determined it was incorrectly translating certain loan balances due to the fact that it lacked an effective assessment process to identify and document whether or not a loan was to be repaid in the foreseeable future at inception and to update this determination on a periodic basis. Also, the Company had incorrectly determined the functional currency for one of its holding companies which impacted the proper translation of its intercompany loan balances. These deficiencies could result in a future misstatement of certain account balances that would result in a material misstatement to the annual or interim financial statements.

Derivative Accounting:

The Company lacked effective controls related to accounting for certain derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Specifically, a deficiency was identified related to a lack of sufficient controls designed to ensure the adequate analysis and documentation of whether or not certain fuel contracts or power purchase contracts met the criteria of being accounted for as a derivative instrument at inception and on an ongoing basis. In addition, the Company lacked an effective control to ensure adequate derivative valuation was performed. Subsequent to filing the 2004 Form 10-K/A, the Company identified an additional deficiency related to a lack of sufficient controls to ensure adequate documentation of the on-going assessment of hedge effectiveness, in accordance with SFAS 133, for certain interest rate and foreign currency hedge contracts entered into prior to 2005. These control deficiencies resulted in adjustments that were required to be made to the consolidated financial statements and are included in this Form 10-K. In addition, these deficiencies could result in a future misstatement of certain account balances that would result in a material misstatement to the annual or interim financial statements.

Conclusion:

Because of the material weaknesses described above, management has concluded that, as of December 31, 2005, the Company did not maintain effective internal control over financial reporting.

The Company’s independent auditor has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting, which appears on page 167.

Material Weaknesses Remediation Plans:

Management and our Board of Directors are committed to the remediation of these material weaknesses as well as the continued improvement of the Company’s overall system of internal control over financial reporting. Management has developed remediation plans for each of the weaknesses described below and is undergoing efforts to strengthen the existing finance organization and systems across the

163




Company. These efforts include the planned expansion of accounting and tax personnel at the corporate office to provide technical support and oversight of our global financial processes, as well as adding additional finance resources to our subsidiaries, where applicable. In addition, various levels of training programs on specific aspects of U.S. GAAP are being developed for distribution to the subsidiaries during 2006. The Company is also utilizing additional resources to assist in the program management aspect of each material weakness remediation plan and has committed to provide status reports to our external auditors and our Audit Committee of the Board of Directors on a monthly basis throughout 2006.

Income Taxes:

The Company had corrected errors identified and recorded tax accounting adjustments on the appropriate subsidiaries’ books for ongoing tracking, reconciliation and translation, where appropriate. The Company currently is executing its remediation plan that includes the following:

·      Adopting a more rigorous approach to communicate, document and reconcile the detailed components of subsidiary income tax assets and liabilities including developing policy and procedure manuals and detailed checklists for use by our subsidiaries;

·      Expanding staffing and resources worldwide, including the continued use of external third party assistance, along with providing specific SFAS 109 training to the income tax accounting function throughout the Company;

·      Continuing to identify and implement additional best practice solutions, including the use of automated resources to ensure efficient data collection, integration and adherence to controls as well as developing best practice processes to ensure tax related purchase accounting adjustments are properly evaluated and recorded; and

·      Implementing additional procedures for tax and accounting personnel in the identification and evaluation of non-recurring tax adjustments and in tracking movements in deferred tax accounts recorded by the parent company and its subsidiaries.

Aggregation of Control Deficiencies at our Cameroonian Subsidiary:

The Company utilized our Internal Audit department, in conjunction with our Corporate finance department, to assist the SONEL finance team with performing additional detailed analytical reviews of the financial statements to obtain assurance that results were not misstated. The Company currently is executing its remediation plan that includes the following:

·      Developing a dedicated remediation team led by the AES CFO’s organization, that includes members of our global information technology department, Internal Audit, the SONEL finance team, and external resources;

·      Expanding the information technology infrastructure, resources, and capabilities across SONEL’s business units in order to centralize and improve the financial data collection process;

·      Creating detailed training programs on financial controls, policies and procedures for use by SONEL business units to ensure on-going application and execution of controls; and

·      Developing tools to perform consistent, routine analytical reviews of the financial results, including key balance sheet account analyses and conversion of local currency financial statements to U.S. Dollar.

164




Lack of U.S. GAAP Expertise in Brazilian Businesses:

The Company performed detailed analysis of the U.S. GAAP financial results, including conversion of local GAAP to U.S. GAAP. Specific reviews of U.S. GAAP issues were performed by the Brazil country level CFO and additional reviews of significant accounting positions were added to the on-going monthly and quarterly analysis discussions held between the Brazilian finance organization and the Corporate finance department, to obtain assurance that reported results are not misstated. The Company currently is executing its remediation plan that includes the following:

·      Engaging consultants to work in conjunction with the Corporate finance department to develop detailed U.S. GAAP and operational accounting policy and procedure guidance, including SFAS 71, SFAS 133, SFAS 109, SFAS 95 and SFAS 87;

·      Utilizing local recruiters to assist with hiring personnel for positions identified as a result of the evaluation of the local finance organization completed by the Brazilian businesses; and

·      Developing procedures to ensure timely and complete communication and evaluation of operational issues that have a potential impact on the financial results within the Brazilian businesses and formalizing processes to evaluate complex issues with technical accounting personnel at Corporate.

Treatment of Intercompany Loans Denominated in Other Than the Functional Currency:

The Company confirmed the correct evaluation and documentation of certain material intercompany loans with the parent denominated in currencies other than the entity’s functional currency to ensure proper application of SFAS 52 and re-evaluated and documented the functional currencies of certain U.S. and non U.S. holding companies to ensure that proper SFAS 52 translations were being performed. The Company currently is executing its remediation plan that includes the following:

·      Developing additional accounting policy guidance for communication to its subsidiaries regarding the requirements of SFAS 52 related to intercompany loan transactions to ensure proper evaluation of material transactions;

·      Providing detailed training programs on critical aspects of SFAS 52, including workshops on how to apply SFAS 52 to intercompany transactions; and

·      Developing and implementing procedures to ensure documentation and testing of the proper determination of an entity’s functional currency on a periodic basis, particularly as it relates to the Company’s material holding company structures.

Derivative Accounting:

The Company performed a reassessment of certain material fuel contracts and power purchase contracts to confirm that appropriate documentation existed or that the contracts did not qualify as derivatives. The Company also performed a detailed review of material components of the other comprehensive income balance within stockholders’ equity to ensure appropriate application of on-going hedge effectiveness testing and documentation. The Company currently is executing its remediation plan that includes the following:

·      Engaging outside resources to help improve comprehensive derivative policies and procedures for use by our subsidiaries when evaluating, reviewing and approving contracts that may qualify as derivatives;

165




·      Evaluating automated solutions to collect and consolidate all material contracts at our subsidiaries to ensure appropriate evaluation and documentation has been followed in accordance with SFAS 133;

·      Developing additional detailed training to be provided on a routine basis to both finance and non-finance employees who are responsible for hedging activities, development of power purchase agreements and negotiation of significant purchase contracts; and

·      Expanding the technical accounting personnel who will support our subsidiaries in the evaluation of derivative implications within hedge instruments and purchase/sale contracts.

Changes in Internal Controls

As described above, in the course of our evaluation of disclosure controls and procedures, management considered certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Based upon that evaluation, the CEO and CFO concluded that there were no changes in our internal controls over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a 15 or 15d 15, that occurred during the quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

166




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
The AES Corporation
Arlington, Virginia

We have audited management's assessment, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting, that The AES Corporation and subsidiaries (the “Company”) did not maintain effective internal control over financial reporting as of December 31, 2005, because of the effect of the material weaknesses identified in management's assessment based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management's assessment:

Income Taxes:

The design of the Company’s internal control over financial reporting lacked effective controls for the proper reconciliation of the components of its parent company and subsidiaries’ income tax assets and

167




liabilities to related consolidated balance sheet accounts, including a detailed comparison of items filed in the subsidiaries’ tax returns to the corresponding calculation of U.S. GAAP balance sheet tax accounts.  In addition, the Company determined that it lacked an effective control to ensure that foreign subsidiaries whose functional currency is the U.S. dollar had properly classified income tax accounts as monetary, rather than non-monetary, assets and liabilities at the time of acquisition. These subsidiaries were not re-measuring their deferred tax balances each period in accordance with Financial Accounting Standards Board Statement (SFAS) No. 52, Foreign Currency Translation and SFAS No. 109, Accounting for Income Taxes. Finally, the company determined that it lacked effectively operating controls and procedures for evaluating and recording tax related purchase accounting adjustments to the financial statements. These control deficiencies resulted in adjustments to the deferred tax assets, deferred tax expense, and cumulative translation adjustment accounts, and could result in a misstatement of the current and deferred income taxes, property, plant and equipment, goodwill, minority interest accounts and related disclosures that would result in a material misstatement of annual or interim financial statements.

Aggregation of Control Deficiencies at a Cameroonian Subsidiary:

AES SONEL, a 56% owned subsidiary of the Company located in Cameroon, lacked adequately designed and effectively operating controls related to transactional accounting and financial reporting.   These deficiencies included a lack of timely and sufficient financial statement account reconciliation and analysis, lack of sufficient support resources within the accounting and finance group, inadequate preparation and review of purchase accounting adjustments incorrectly recorded in 2002, and errors in the translation of local currency financial statements to the U.S. dollar. These deficiencies, in the aggregate, could result in a misstatement of the other assets and accumulated other comprehensive income accounts that would result in a material misstatement of annual or interim financial statements.

Lack of U.S. GAAP Expertise in Brazilian Businesses:

The Company lacked effectively operating controls to ensure the proper application of certain U.S. GAAP principles, not limited to, SFAS No. 95, Statement of Cash Flows, SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, SFAS No. 87, Employers’ Accounting for Pensions, and SFAS No. 109, Accounting for Income Taxes. In addition, the Company lacked effectively operating controls to ensure appropriate conversion and analysis of Brazilian GAAP to U.S. GAAP financial statements for certain of its Brazilian subsidiaries. These control deficiencies resulted in adjustments to the minority interest, cumulative translation adjustment, accrued liabilities, pension liabilities, other comprehensive income, regulatory assets, receivables, payables, and income tax accounts, and could result in misstatement of the cash, investments, and goodwill accounts that would result in a material misstatement of annual or interim financial statements.

Treatment of Intercompany Loans Denominated in Other Than the Functional Currency: 

The Company lacked effectively operating controls to ensure the proper application of SFAS No. 52, Foreign Currency Translation, related to the treatment of foreign currency gains or losses on certain long term intercompany loan balances denominated in other than the entity’s functional currency and lacked appropriate documentation for the determination of certain of its holding companies’ functional currencies. The Company determined it was incorrectly translating certain loan balances due to the fact that it lacked an effectively operating assessment process to identify and document whether or not a loan was to be repaid in the foreseeable future at inception and to update this determination on a periodic basis. Also, the Company had incorrectly determined the functional currency for one of its holding companies which impacted the proper translation of its intercompany loan balances. These deficiencies could result in a misstatement of the retained earnings, other expense, functional currency translation gain/loss, and cumulative translation allowance accounts that would result in a material misstatement of annual or interim financial statements.

168




Derivative Accounting:

The Company lacked effectively designed and operating controls related to accounting for certain derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Specifically, the company lacked effectively designed and operating controls to ensure that adequate analysis and documentation of whether or not certain fuel contracts or power purchase contracts met the criteria of being accounted for as a derivative instrument at inception and on an ongoing basis. In addition the Company lacked an effective control to ensure adequate derivative valuation was performed. Subsequent to the filing of the 2004 Form 10-K/A, the Company identified an additional deficiency related to a lack of sufficiently designed and operating controls to ensure adequate documentation of the ongoing assessment of hedge effectiveness, in accordance with SFAS 133, for certain interest rate and foreign currency hedge contracts entered into prior to 2005. These control deficiencies resulted in adjustments to the accumulated other comprehensive income, interest expense, foreign currency, transaction gains and losses on net monetary position, income tax expense, and minority interest expense accounts, and could result in a misstatement of the long term liabilities or assets, cost of sales, or revenue accounts that would result in a material misstatement of annual or interim financial statements.

These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of operations, changes in stockholders’ equity, cash flows and financial statement schedules as of and for the year ended December 31, 2005, of the Company and this report does not affect our report on such financial statements and financial statement schedules.

In our opinion, management's assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of operations, changes in stockholders’ equity, cash flows and financial statement schedules as of and for the year ended December 31, 2005, of the Company and our report dated April 4, 2006 expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/ DELOITTE & TOUCHE LLP

McLean, VA
April 4, 2006

169




ITEM 9B.         OTHER INFORMATION.

None.

PART III

ITEM 10.          DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Securities and Exchange Commission’s Rule 10b5-1 permits directors, officers and other key personnel to establish purchase and sale programs. The rule permits such persons to adopt written plans at a time before becoming aware of material nonpublic information and to sell shares according to a plan on a regular basis (for example, weekly or monthly), regardless of any subsequent nonpublic information they receive. Rule 10b5-1 plans allow systematic, pre-planned sales that take place over an extended period and should have a less disruptive influence on the price of our stock. Plans of this type inform the marketplace about the nature of the trading activities of our directors and officers. We recognize that our directors and officers may have reasons totally unrelated to their assessment of the Company or its prospects in determining to effect transaction in our common stock. Such reasons might include, for example tax and estate planning, the purchase of a home, the payment of college tuition, the establishment of a trust, the balancing of assets, or other personal reasons.

Mr. Robert Hemphill, Mr. William Luraschi and Mr. Brian Miller adopted trading plans pursuant to Rule 10b5-1.

Certain information regarding executive officers required by this Item is set forth as a supplementary item in Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this Item, to the extent not included above, will be contained in our Proxy Statement for the Annual Meeting of Shareholders to be held on May 11, 2006 and is hereby incorporated by reference.

ITEM 11.          EXECUTIVE COMPENSATION

See the information contained under the captions “Compensation of Executive Officers” and “Compensation of Directors” of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on May 11, 2006 which is incorporated herein by reference.

ITEM 12.          SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

(a)          Security Ownership of Certain Beneficial Owners.

See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the Proxy Statement for the Annual Meeting of Shareholders of the Registrant to be held on May 11, 2006, which information is incorporated herein by reference.

(b)          Security Ownership of Directors and Executive Officers.

See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the Proxy Statement for the Annual Meeting of Shareholders of the Registrant to be held on May 11, 2006, which information is incorporated herein by reference.

(c)           Changes in Control.

None.

(d)          Securities Authorized for Issuance under Equity Compensation Plans.

Except for the information concerning equity compensation plans below, the information required by Item 12 is incorporated by reference to the Company’s 2006 Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.”

170




The following table provides information about shares of AES common stock that may be issued under AES’s equity compensation plans, as of December 31, 2005:

Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2005)

 

 

(a)

 

(b)

 

(c)

 

Plan category

 

 

 

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

 

Weighted-average
exercise price
of outstanding options,
warrants and rights

 

Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected
in column(a))

 

Equity compensation plans approved by security holders

 

 

24,271,734

 

 

 

$

16.56

 

 

 

14,845,291

 

 

Equity compensation plans not approved by security holders(1)

 

 

10,778,193

 

 

 

$

13.15

 

 

 

560,885

 

 

Total

 

 

35,049,927

 

 

 

$

15.51

 

 

 

15,406,176

 

 


(1)          The AES Corporation 2001 Non-officer Stock Option Plan (the “Plan”) was adopted by our Board of Directors on October 18, 2001. This Plan did not require approval under either the SEC or NYSE rules and /or regulations. Eligible participants under the Plan include all of our non-officer employees. As of the end of December 31, 2005, approximately 13,500 employees held options under the Plan. The exercise price of each option awarded under the Plan is equal to the fair market value of our common stock on the grant date of the option. Options under the Plan generally vest as to 50% of their underlying shares on each anniversary of the option grant date, however, grants dated October 25, 2001 vest in one year. The Plan shall expire on October 25, 2011. The Board may amend, modify or terminate the plan at any time.

ITEM 13.          CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14.          PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item will be contained in our Proxy Statement for the Annual Meeting of Shareholders to be held on May 11, 2006 and is hereby incorporated by reference.

PART IV

ITEM 15.          EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)   1.           Financial Statements. The following Consolidated Financial Statements of The AES Corporation are filed under “Item 8. Financial Statements and Supplementary Data.”

Consolidated Balance Sheets as of December 31, 2004 and 2003

 

101

 

Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002

 

102

 

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

 

103

 

Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the
years ended December 31, 2004, 2003, and 2002

 

104

 

Notes to Consolidated Financial Statements

 

105

 

 

2.                Financial Statement Schedules.  See Index to Financial Statement Schedules of the Registrant and subsidiaries at page S-1 hereof, which index is incorporated herein by reference.

(b)          Exhibits.

171




 

3.1

 

 

Sixth Restated Certificate of Incorporation of The AES Corporation and incorporated herein by reference to the Registrant’s 2002 Form 10-K.

 

3.2

 

 

By-Laws of The AES Corporation, as amended and incorporated herein by reference to the Registrant’s 2002 Form 10-K.

 

4.1

 

 

Senior Indenture, dated December 31, 2002, between The AES Corporation and Wells Fargo Bank Minnesota, National Association, as Trustee is herein incorporated by reference to Exhibit 4.1 of the Form 8-K filed on December 17, 2002.

 

4.1.1

 

 

First Supplemental Indenture dated as of July 29, 2003 to Senior Indenture dated as of December 13, 2002, among The AES Corporation as the Company and AES Hawaii Management Company, Inc., AES New York Funding, L.L.C., AES Oklahoma Holdings, L.L.C., AES Warrior Run Funding, L.L.C., as Subsidiary Guarantors party hereto and Wells Fargo Bank Minnesota, National Association as Trustee. Incorporated by reference to the Registrant’s Quarterly Report on Form 10-Q for the Quarter ended June 30, 2003.

 

4.2

 

 

Collateral Trust Agreement dated as of December 12, 2002 among The AES Corporation, AES International Holdings II, Ltd., Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, an individual trustee is herein incorporated by reference to Exhibit 4.2 of the Form 8-K filed on December 17, 2002.

 

4.3

 

 

Security Agreement dated as of December 12, 2002 made by The AES Corporation to Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is herein incorporated by reference to Exhibit 4.3 of the Form 8-K filed on December 17, 2002.

 

4.4

 

 

Charge Over Shares dated as of December 12, 2002 between AES International Holdings II, Ltd. and Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is herein incorporated by reference to Exhibit 4.4 of the Form 8-K filed on December 17, 2002.

 

4.5

 

 

There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request.

 

10.1

 

 

Amended Power Sales Agreement, dated as of December 10, 1985, between Oklahoma Gas and Electric Company and AES Shady Point, Inc. is incorporated herein by reference to Exhibit 10.5 to the Registration Statement on Form S-1 (Registration No. 33-40483).

 

10.2

 

 

First Amendment to the Amended Power Sales Agreement, dated as of December 19, 1985, between Oklahoma Gas and Electric Company and AES Shady Point, Inc. is incorporated herein by reference to Exhibit 10.45 to the Registration Statement on Form S-1 (Registration No. 33-46011).

 

10.3

 

 

The AES Corporation Profit Sharing and Stock Ownership Plan is incorporated herein by reference to Exhibit 4(c)(1) to the Registration Statement on Form S-8 (Registration No. 33-49262).

 

10.4

 

 

The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 to the Annual Report on Form 10-K of the Registrant for the fiscal year ended December 31, 1995.

 

10.5

 

 

Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 to the Registration Statement on Form S-1 (Registration No. 33-40483).

 

10.6

 

 

Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 to Amendment No. 1 to the Registration Statement on Form S-1(Registration No. 33-40483).

172




 

10.7

 

 

Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q of the Registrant for the quarter ended March 31, 1998, filed May 15, 1998.

 

10.8

 

 

The AES Corporation Stock Option Plan for Outside Directors as amended is incorporated herein by reference to the Registrant’s 2003 Proxy Statement.

 

10.9

 

 

The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.64 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 1994.

 

10.10

 

 

The AES Corporation 2001 Stock Option Plan is incorporated herein by reference to Exhibit 10.12 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2000.

 

10.11

 

 

Second Amended and Restated Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.13 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2000.

 

10.12

 

 

The AES Corporation 2001 Non-Officer Stock Option Plan is incorporated herein by reference to the Registrant’s 2002 Form 10-K.

 

10.13

 

 

The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to the Registrant’s 2003 Proxy Statement.

 

10.13.A

 

 

Form of Nonqualified Stock Option Award Agreement Pursuant to the AES Corporation 2003 Long Term Compensation Plan is incorporated by reference to Exhibit 10.13A to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2004.*

 

10.13.B

 

 

Form of Performance Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan is incorporated by reference to Exhibit 10.13B to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2004.*

 

10.13.C

 

 

Form of Restricted Stock Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan is incorporated by reference to Exhibit 10.13C to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2004.*

 

10.13.D

 

 

Restricted Stock Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation plan, dated as of May 4, 2005, entered into by and between the Registrant and William R. Luraschi.*

 

10.14

 

 

The AES Corporation Employment Agreement with Paul Hanrahan is incorporated herein by reference to the Registrant’s 2002 Form 10-K.

 

10.15

 

 

The AES Corporation Employment Agreement with Barry J. Sharp is incorporated herein by reference to the Registrant’s 2002 Form 10-K.

 

10.16

 

 

The AES Corporation Employment Agreement with John R. Ruggirello is incorporated herein by reference to the Registrant’s 2002 Form 10-K.

 

10.17

 

 

The AES Corporation Employment Agreement with William R. Luraschi is incorporated herein by reference to the Registrant’s 2002 Form 10-K.

 

10.18

 

 

The AES Corporation Employment Agreement with Robert F. Hemphill is incorporated herein by reference to the Registrant’s 2003 Form 10-K.

 

10.19

 

 

The AES Corporation Employment Agreement with Victoria D. Harker is incorporated herein by reference to Exhibit 99.2 of the Form 8-K filed on January 24, 2006.

173




 

10.20

 

 

Second Amended and Restated Credit and Reimbursement Agreement dated as of July 29, 2003 among The AES Corporation, as Borrower, AES Oklahoma Holdings, L.L.C., AES Hawaii Management Company, Inc., AES Warrior Run Funding, L.L.C., and AES New York Funding, L.L.C., as Subsidiary Guarantors, Citicorp USA, INC., as Administrative Agent, Citibank, N.A., as Collateral Agent, Citigroup Global Markets Inc., as Lead Arranger and Book Runner, Banc Of America Securities L.L.C., as Lead Arranger and Book Runner and as Co-Syndication Agent (Term Loan Facility), Deutsche Bank Securities Inc., as Lead Arranger and Book Runner (Term Loan Facility), Union Bank of California, N.A., as Co-Syndication Agent (Term Loan Facility) and as Lead Arranger and Book Runner and as Syndication Agent (Revolving Credit Facility), Lehman Commercial Paper Inc., as Co-Documentation Agent (Term Loan Facility), UBS Securities LLC. as Co-Documentation Agent (Term Loan Facility), Societe General, as Co-Documentation Agent (Revolving Credit Facility), and The Banks Listed Herein. Incorporated by reference to the Registrant’s Quarterly Report on Form 10-Q for the Quarter ended June 30, 2003.

 

10.21

 

 

Second Amended and Restated Pledge Agreement dated as of December 12, 2002 between AES EDC Funding II, L.L.C. and Citicorp USA, Inc., as Collateral Agent is herein incorporated by reference to Exhibit 99.3 of the Form 8-K filed on December 17, 2002.

 

10.22

 

 

The AES Corporation 2004 Restoration Supplemental Retirement Plan is incorporated by reference to Exhibit 10.22 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2004.

 

10.23

 

 

Third Amended And Restated Credit And Reimbursement Agreement dated as of March 17, 2004 among THE AES CORPORATION, a Delaware corporation , the SUBSIDIARY GUARANTORS listed herein, the BANKS listed on the signature pages hereof, CITIGROUP GLOBAL MARKETS INC., as Lead Arranger and Book Runner, BANC OF AMERICA SECURITIES LLC, as Lead Arranger and Book Runner and as Co-Syndication Agent, DEUTSCHE BANK SECURITIES INC, as Lead Arranger and Book Runner, UNION BANK OF CALIFORNIA, N.A., as Co-Syndication Agent and as Lead Arranger and Book Runner and as Syndication Agent, LEHMAN COMMERCIAL PAPER INC., as Co-Documentation Agent, UBS SECURITIES LLC, as Co-Documentation Agent, SOCIÉTÉ GÉNÉRALE, as Co-Documentation Agent, CREDIT LYONNAIS NEW YORK BRANCH, as Co-Documentation Agent, CITICORP USA, INC., as Administrative Agent for the Bank Parties and CITIBANK, N.A., as Collateral Agent for the Bank Parties is incorporated herein by reference to the Registrant’s Quarterly Report on Form 10-Q for the Quarter ended March 31, 2004.

 

10.24

 

 

Amendment No. 1 To Third Amended And Restated Credit And Reimbursement Agreement dated as of August 10, 2004 among THE AES CORPORATION, a Delaware corporation, the SUBSIDIARY GUARANTORS, the BANK PARTIES, CITICORP USA, INC., as administrative agent and CITIBANK, N.A., as Collateral Agent, for the Bank Parties is incorporated herein by reference to the Registrant’s Quarterly Report on Form 10-Q for the Quarter ended September 30, 2004.

 

10.25

 

 

Amendment No. 2 To Third Amended And Restated Credit And Reimbursement Agreement dated as of August 10, 2004 among THE AES CORPORATION, a Delaware corporation, the SUBSIDIARY GUARANTORS, the BANK PARTIES, CITICORP USA, INC., as administrative agent and CITIBANK, N.A., as Collateral Agent, for the Bank Parties is incorporated herein by reference to Exhibit 99.2 of the Form 8-K filed on June 28, 2005.

 

10.26

 

 

Amendment No. 4 To Third Amended And Restated Credit And Reimbursement Agreement dated as of August 10, 2004 among THE AES CORPORATION, a Delaware corporation, the SUBSIDIARY GUARANTORS, the BANK PARTIES, CITICORP USA, INC., as administrative agent and CITIBANK, N.A., as Collateral Agent, for the Bank Parties is incorporated herein by reference to Exhibit 99.1 of the Form 8-K filed on October 4, 2005.

 

10.27

 

 

Amendment No. 5 To Third Amended And Restated Credit And Reimbursement Agreement dated as of August 10, 2004 among THE AES CORPORATION, a Delaware corporation, the SUBSIDIARY GUARANTORS, the BANK PARTIES, CITICORP USA, INC., as administrative agent and CITIBANK, N.A., as Collateral Agent, for the Bank Parties is incorporated herein by reference to Exhibit 99.2 of the Form 8-K filed on October 4, 2005.

174




 

10.28

 

 

Amendment No. 6 To Third Amended And Restated Credit And Reimbursement Agreement dated as of August 10, 2004 among THE AES CORPORATION, a Delaware corporation, the SUBSIDIARY GUARANTORS, the BANK PARTIES, CITICORP USA, INC., as administrative agent and CITIBANK, N.A., as Collateral Agent, for the Bank Parties is incorporated herein by reference to Exhibit 99.1 of the Form 8-K filed on October 19, 2005.

 

10.29  

 

 

Credit Agreement dated as of March 31, 2006 among The AES Corporation as Borrower, Merrill Lynch Capital Corporation as Administrative Agent, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Lead Arranger is incorporated herein by reference to Exhibit 99.1 of the Form 8-K filed on April 3, 2006.

 

12.1

 

 

Statement of computation of ratio of earnings to fixed charges (filed herewith).

 

21.1

 

 

Subsidiaries of The AES Corporation (filed herewith).

 

23.1

 

 

Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP (filed herewith).

 

24

 

 

Power of Attorney (filed herewith).

 

31.1

 

 

Rule13a-14(a)/15d-14(a) Certification of Paul Hanrahan (filed herewith).

 

31.2

 

 

Rule 13a-14(a)/15d-14(a) Certification of Victoria D. Harker (filed herewith).

 

32.1

 

 

Section 1350 Certification of Paul Hanrahan (filed herewith).

 

32.2

 

 

Section 1350 Certification of Victoria D. Harker (filed herewith).


*                    indicates management contract or compensatory plan or arrangement required to be filed as exhibits pursuant to Item 15(b) of this report.

(c)           Schedules.

Schedule I—Condensed Financial Information of Registrant

Schedule II—Valuation and Qualifying Accounts

175




SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

THE AES CORPORATION

 

 

(Company)

Date: April 4, 2006

 

By:

 

/s/ PAUL HANRAHAN

 

 

 

 

Name: Paul Hanrahan

 

 

 

 

President, Chief Executive Officer

 

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.

Name

 

Title

 

Date

 

*

 

Chairman of the Board and Director

 

April 4, 2006

 

Richard Darman

 

 

 

 

 

*

 

President, Chief Executive Officer

 

April 4, 2006

 

Paul Hanrahan

 

(Principal Executive Officer) and Director

 

 

 

*

 

Director

 

April 4, 2006

 

Kristina M. Johnson

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

John A. Koskinen

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

Philip Lader

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

John H. McArthur

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

Sandra O. Moose

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

Philip A. Odeen

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

Charles O. Rossotti

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

Sven Sandstrom

 

 

 

 

 

*

 

Director

 

April 4, 2006

 

Roger W. Sant

 

 

 

 

 

/s/ VICTORIA D. HARKER

 

Executive Vice President and Chief Financial Officer

 

April 4, 2006

 

Victoria D. Harker

 

(Principal Financial Officer)

 

 

 

/s/ CATHERINE FREEMAN

 

Vice President and Controller

 

 

 

Catherine Freeman

 

(Principal Accounting Officer)

 

 

 

 

*By:

 

/s/ BRIAN A. MILLER

 

April 4, 2006

 

 

Attorney-in-fact

 

 

 

176




THE AES CORPORATION AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule I—Condensed Financial Information of Registrant

 

S-2

 

Schedule II—Valuation and Qualifying Accounts

 

S-9

 

 

Schedules other than those listed above are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.

S-1




THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
UNCONSOLIDATED BALANCE SHEETS
(IN MILLIONS)

 

 

December 31,

 

 

 

2005

 

2004

 

 

 

 

 

(restated)(1)

 

ASSETS

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

262

 

 

$

287

 

 

Restricted cash

 

6

 

 

4

 

 

Accounts and notes receivable from subsidiaries

 

1,012

 

 

1,097

 

 

Deferred income taxes

 

28

 

 

20

 

 

Prepaid expenses and other current assets

 

7

 

 

6

 

 

Total current assets

 

1,315

 

 

1,414

 

 

Investment in and advances to subsidiaries and affiliates

 

4,528

 

 

3,971

 

 

Office Equipment:

 

 

 

 

 

 

 

Cost

 

43

 

 

29

 

 

Accumulated depreciation

 

(12

)

 

(6

)

 

Office equipment, net

 

31

 

 

23

 

 

Other Assets:

 

 

 

 

 

 

 

Deferred financing costs (less accumulated amortization: 2005, $47; 2004, $41)

 

84

 

 

96

 

 

Deferred income taxes

 

769

 

 

754

 

 

Total other assets

 

853

 

 

850

 

 

Total

 

$

6,727

 

 

$

6,258

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

 

Accounts payable

 

$

4

 

 

$

3

 

 

Accrued and other liabilities

 

174

 

 

131

 

 

Term loan—current portion

 

200

 

 

-

 

 

Junior notes and debentures payable—current portion

 

 

 

142

 

 

Total current liabilities

 

378

 

 

276

 

 

Long-term Liabilities:

 

 

 

 

 

 

 

Term loan

 

 

 

200

 

 

Senior notes payable

 

3,838

 

 

3,854

 

 

Senior subordinated notes and debentures payable

 

113

 

 

225

 

 

Junior subordinated notes and debentures payable

 

731

 

 

731

 

 

Other long-term liabilities

 

18

 

 

16

 

 

Total long-term liabilities

 

4,700

 

 

5,026

 

 

Stockholders’ equity:

 

 

 

 

 

 

 

Common stock

 

7

 

 

7

 

 

Additional paid-in capital

 

6,517

 

 

6,434

 

 

Accumulated loss

 

(1,214

)

 

(1,844

)

 

Accumulated other comprehensive loss

 

(3,661

)

 

(3,641

)

 

Total stockholders’ equity

 

1,649

 

 

956

 

 

Total

 

$

6,727

 

 

$

6,258

 

 


(1)          See note 1 to Schedule I related to restated unconsolidated financial statements.

See notes to Schedule I.

S-2




THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED OPERATIONS
(IN MILLIONS)

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

(restated)(1)

 

(restated)(1)

 

Revenues from subsidiaries and affiliates

 

$

39

 

 

$

42

 

 

 

$

42

 

 

Equity in earnings (losses) of subsidiaries and affiliates

 

1,125

 

 

609

 

 

 

(523

)

 

Interest income

 

54

 

 

54

 

 

 

258

 

 

General and Administrative expenses

 

(173

)

 

(188

)

 

 

(14

)

 

Interest expense

 

(439

)

 

(491

)

 

 

(525

)

 

Income (loss) before cumulative effect of change in accounting principle

 

606

 

 

26

 

 

 

(762

)

 

Cumulative effect of accounting change

 

1

 

 

 

 

 

 

 

Income (loss) before income taxes

 

607

 

 

26

 

 

 

(762

)

 

Income tax benefit

 

23

 

 

272

 

 

 

310

 

 

Net income (loss)

 

$

630

 

 

$

298

 

 

 

$

(452

)

 


(1)          See note 1 to Schedule I related to restated unconsolidated financial statements.

See notes to Schedule I.

S-3




THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED CASH FLOWS
(IN MILLIONS)

 

 

For the Years Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

(restated)(1)

 

(restated)(1)

 

Net cash provided by operating activities

 

$

412

 

 

$

437

 

 

 

$

283

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

 

 

Proceeds from asset sales, net of expenses

 

2

 

 

13

 

 

 

1,112

 

 

Investment in and advances to subsidiaries

 

(148

)

 

(477

)

 

 

(609

)

 

Acquisitions-net of cash acquired

 

(85

)

 

 

 

 

 

 

Return of capital

 

57

 

 

127

 

 

 

242

 

 

Increase in restricted cash

 

(3

)

 

(4

)

 

 

 

 

Additions to property, plant and equipment

 

(30

)

 

(27

)

 

 

(11

)

 

Net cash (used in) provided by investing activities

 

(207

)

 

(368

)

 

 

734

 

 

Financing Activities:

 

 

 

 

 

 

 

 

 

 

 

Repayments under the old revolver, net

 

 

 

 

 

 

 

 

(Repayments) borrowings under the new revolver, net

 

 

 

 

 

 

(228

)

 

Borrowings of notes payable and other coupon bearing securities

 

5

 

 

491

 

 

 

2,504

 

 

Repayments of notes payable and other coupon bearing securities

 

(259

)

 

(1,140

)

 

 

(2,877

)

 

Proceeds from issuance of common stock, net

 

26

 

 

16

 

 

 

337

 

 

Payments for deferred financing costs

 

(2

)

 

(14

)

 

 

(76

)

 

Net cash (used in) provided by financing activities

 

(230

)

 

(647

)

 

 

(340

)

 

(Decrease)/Increase in cash and cash equivalents

 

(25

)

 

(578

)

 

 

677

 

 

Cash and cash equivalents, beginning

 

287

 

 

865

 

 

 

188

 

 

Cash and cash equivalents, ending

 

$

262

 

 

$

287

 

 

 

$

865

 

 

Schedule of non-cash investing and financing activities:

 

 

 

 

 

 

 

 

 

 

 

Common stock issued for debt retirement

 

$

 

 

$

168

 

 

 

$

63

 

 


(1)          See note 1 to Schedule I related to restated unconsolidated financial statements.

See Notes to Schedule I.

S-4




THE AES CORPORATION
SCHEDULE I
NOTES TO SCHEDULE I

1.   Application of Significant Accounting Principles

Accounting for Subsidiaries and Affiliates—The AES Corporation (the “Company”) has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.

Revenues—Construction management fees earned by the parent from its consolidated subsidiaries are eliminated.

Income Taxes—The unconsolidated income tax expense or benefit computed for the Company in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, reflects the tax assets and liabilities of the Company on a stand alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies.

Accounts and Notes Receivable from Subsidiaries—Such amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements.

RESTATEMENT— Subsequent to filing its restated annual report on Form 10-K/A with the Securities Exchange Commission on January 19, 2006, the Company discovered its previously issued restated annual report included certain errors in accounting for derivative instruments and hedging activities, minority interest expense and income taxes. The errors in accounting for derivative instruments and hedging activities resulted in differences in previously issued consolidated interim financial statements for certain quarterly periods in 2004 sufficient to require restatement of prior period interim results. The errors in accounting for income taxes and minority interest expense required restatement of previously issued consolidated annual financial statements.

Based upon management’s review it has been determined that these errors were inadvertent and unintentional. The errors relate to the following areas:

A.              Accounting for Derivative Instruments and Hedging Activities

The Company determined that it failed to perform adequate on-going effectiveness testing for three interest rate cash flow hedges and one foreign currency cash flow hedge during 2004 as required by SFAS No. 133. As a result, the Company should have discontinued hedge accounting and recognized changes in the fair value of the derivative instruments in earnings prospectively from the last valid effectiveness assessment until the earlier of either (1) the expiration of the derivative instrument or (2) the re-designation of the derivative instrument as a hedging activity.

B.               Income Tax and Minority Interest Adjustments

As a result of the Company’s year end closing review process, the Company discovered certain other errors related to the recording of income tax liabilities and, in one case, the associated impact on minority interest expense. The adjustments include:

·      An increase in income tax expense related to the recording of certain historical withholding tax liabilities at one of our El Salvador subsidiaries;

·      An increase in minority interest expense related to a correction of the allocation of income tax expense to minority shareholders. This allocation pertained to certain deferred tax adjustments recorded in the original restatement at one of our Brazilian generating companies; and

S-5




·      A reduction of 2004 income tax expense related to adjustments derived from income tax returns filed in 2005.

The following tables set forth the previously reported and restated amounts of selected items within Schedule I condensed financial statement information for the year ended December 31, 2004.

Selected Unconsolidated Balance Sheet Data:

 

 

December 31, 2004

 

 

 

As Previously
Reported

 

As Restated

 

 

 

(in millions)

 

Assets

 

 

 

 

 

 

 

 

 

Investment in and advances to subsidiaries and affiliates

 

 

$

4,004

 

 

 

$

3,971

 

 

Deferred income taxes

 

 

$

747

 

 

 

$

754

 

 

Total other assets

 

 

$

843

 

 

 

$

850

 

 

Total assets

 

 

$

6,284

 

 

 

$

6,258

 

 

Liabilities and Stockholders' Equity

 

 

 

 

 

 

 

 

 

Accrued and other liabilities

 

 

$

141

 

 

 

$

131

 

 

Total current liabilities

 

 

$

286

 

 

 

$

276

 

 

Additional paid-in capital

 

 

$

6,423

 

 

 

$

6,434

 

 

Accumulated loss

 

 

$

(1,815

)

 

 

$

(1,844

)

 

Accumulated other comprehensive loss

 

 

$

(3,643

)

 

 

$

(3,641

)

 

Total stockholders' equity

 

 

$

972

 

 

 

$

956

 

 

Total liabilities and stockholders' equity

 

 

$

6,284

 

 

 

$

6,258

 

 

 

Selected Statement of Unconsolidated Operations Data:

 

 

For the Year Ended

 

 

 

December 31, 2004

 

December 31, 2003

 

 

 

As Previously
Reported

 

As Restated

 

As Previously
Reported

 

As Restated

 

Equity in earnings (losses) of subsidiaries and affiliates

 

 

$

608

 

 

 

$

609

 

 

 

$

(503

)

 

 

$

(523

)

 

Income (loss) before income taxes

 

 

$

25

 

 

 

$

26

 

 

 

$

(742

)

 

 

$

(762

)

 

Income tax (expense) benefit

 

 

$

267

 

 

 

$

272

 

 

 

$

307

 

 

 

$

310

 

 

Net income (loss)

 

 

$

292

 

 

 

$

298

 

 

 

$

(435

)

 

 

$

(452

)

 

 

Selected Unconsolidated Cash Flows Data:

 

 

For the Year Ended

 

 

 

December 31, 2004

 

December 31, 2003

 

 

 

As Previously
Reported

 

As Restated

 

As Previously
Reported

 

As Restated

 

Schedule of non-cash investing and financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock issued for debt retirement

 

 

$

168

 

 

 

$

168

 

 

 

$

48

 

 

 

$

63

 

 

 

S-6




2.   Notes Payable

 

 

 

 

Final

 

First Call

 

 

 

 

 

 

 

Interest Rate(1)

 

Maturity

 

Date(2)

 

2005

 

2004

 

Senior Secured Term Loan

 

LIBOR + 2.25%

 

 

2011

 

 

 

 

 

 

200

 

Senior Secured Term Loan(3)

 

LIBOR + 1.75%

 

 

2011

 

 

 

 

 

200

 

 

Senior Secured Notes

 

8.75%

 

 

2013

 

 

 

 

 

1,200

 

1,200

 

Senior Secured Notes

 

9.00%

 

 

2015

 

 

 

 

 

600

 

600

 

Senior Notes

 

8.75%

 

 

2008

 

 

 

 

 

202

 

202

 

Senior Notes

 

9.50%

 

 

2009

 

 

 

 

 

467

 

467

 

Senior Notes

 

9.375%

 

 

2010

 

 

 

 

 

423

 

423

 

Senior Notes

 

8.875%

 

 

2011

 

 

 

 

 

307

 

307

 

Senior Notes

 

8.375%

 

 

2011

 

 

 

 

 

148

 

165

 

Senior Notes

 

7.750%

 

 

2014

 

 

 

 

 

500

 

500

 

Senior Subordinated Notes

 

8.50%

 

 

2007

 

 

 

2002

 

 

 

112

 

Senior Subordinated Debentures

 

8.875%

 

 

2027

 

 

 

2004

 

 

115

 

115

 

Convertible Junior Subordinated Debentures

 

4.50%

 

 

2005

 

 

 

2001

 

 

 

142

 

Convertible Junior Subordinated Debentures

 

6.00%

 

 

2008

 

 

 

 

 

213

 

213

 

Convertible Junior Subordinated Debentures

 

6.75%

 

 

2029

 

 

 

 

 

517

 

517

 

Unamortized discounts

 

 

 

 

 

 

 

 

 

 

 

(10

)

(11

)

SUBTOTAL

 

 

 

 

 

 

 

 

 

 

 

4,882

 

5,152

 

Less: Current maturities

 

 

 

 

 

 

 

 

 

 

 

(200

)

(142

)

Total

 

 

 

 

 

 

 

 

 

 

 

$

4,682

 

$

5,010

 


(1)          Interest rate at December 31, 2005. Weighted average LIBOR rates at December 31, 2005 and 2004 were 3.63% and 2.10%, respectively.

(2)          The first call date represents the date that the Company, at its option, can call the related debt.

(3)          This loan is currently classified as current portion of debt as the amount is in default at December 31, 2005.

FUTURE MATURITIES OF DEBT—Scheduled maturities of total debt for continuing operations at December 31, 2005 are (in millions):

2006

 

$

200

 

2007

 

 

2008

 

415

 

2009

 

467

 

2010

 

423

 

Thereafter

 

3,377

 

Total

 

$

4,882

 

 

3.   Dividends from Subsidiaries and Affiliates

Cash dividends received from consolidated subsidiaries and from affiliates accounted for by the equity method were as follows (in millions):

 

 

2005

 

2004

 

2003

 

Subsidiaries

 

$

741

 

$

824

 

$

807

 

Affiliates

 

32

 

29

 

43

 

 

S-7




4.   Guarantees and Letters of Credit

GUARANTEES—In connection with certain of its project financing, acquisition, and power purchase agreements, the Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter of credit and other obligations discussed below, were limited as of December 31, 2005, by the terms of the agreements, to an aggregate of approximately $507 million representing 34 agreements with individual exposures ranging from less than $1 million up to $100 million.

LETTERS OF CREDIT—At December 31, 2005, the Company had $294 million in letters of credit outstanding representing 18 agreements with individual exposures ranging from less than $1 million up to $74 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. The Company pays letter of credit fees ranging from 0.15% to 2.75% per annum on the outstanding amounts. In addition, the Company had $1 million in surety bonds outstanding at December 31, 2005

S-8




THE AES CORPORATION
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(IN MILLIONS)

 

 

Additions

 

Deductions

 

 

 

Balance at

 

Charged to

 

 

 

 

 

 

 

Balance at

 

 

 

Beginning

 

Costs and

 

Acquisitions

 

Translation

 

Amounts

 

End of

 

 

 

of Period

 

Expenses

 

of Business

 

Adjustment

 

Written Off

 

Period

 

Allowance for accounts receivables (current and noncurrent):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2003

 

 

352

 

 

 

57

 

 

 

3

 

 

 

51

 

 

 

(121

)

 

 

342

 

 

Year ended December 31, 2004

 

 

342

 

 

 

69

 

 

 

 

 

 

24

 

 

 

(53

)

 

 

382

 

 

Year ended December 31, 2005

 

 

382

 

 

 

317

 

 

 

 

 

 

39

 

 

 

(234

)

 

 

504

 

 

 

S-9