10-K 1 d290041d10k.htm FORM 10-K FORM 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

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

For the Fiscal Year Ended December 31, 2011

-OR-

 

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

COMMISSION FILE NUMBER 1-12291

 

 

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 Preferred Securities   New York Stock Exchange

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  ¨

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  ¨    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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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 filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  x

   Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨
      (Do not check if a smaller
reporting company)
  

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2011, the last business day of the Registrant’s most recently completed second fiscal quarter (based on the closing sale price of $12.74 of the Registrant’s Common Stock, as reported by the New York Stock Exchange on such date) was approximately $8.37 billion.

The number of shares outstanding of the Registrant’s Common Stock, par value $0.01 per share, on February 17, 2012, was 765,906,019.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s Proxy Statement for its 2012 annual meeting of stockholders are incorporated by reference in Parts II and III

 

 

 


Table of Contents

THE AES CORPORATION

FISCAL YEAR 2011 FORM 10-K

TABLE OF CONTENTS

 

PART I

     1   

ITEM 1. BUSINESS

     3   

Overview

     3   

Our Organization and Segments

     6   

Customers

     19   

Employees

     19   

Executive Officers

     19   

How to Contact AES and Sources of Other Information

     21   

Regulatory Matters

     22   

ITEM 1A. RISK FACTORS

     78   

ITEM 2. PROPERTIES

     103   

ITEM 3. LEGAL PROCEEDINGS

     103   

ITEM 4. MINE SAFETY DISCLOSURES

     111   

PART II

     112   

ITEM  5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     112   

Recent Sale of Unregistered Securities

     112   

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

     112   

Market Information

     112   

Holders

     113   

Dividends

     113   

ITEM 6. SELECTED FINANCIAL DATA

     114   

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

     116   

Overview of Our Business

     116   

Performance Highlights

     126   

Non-GAAP Measures

     129   

Consolidated Results of Operations

     131   

Critical Accounting Estimates

     147   

New Accounting Pronouncements

     151   

Capital Resources and Liquidity

     151   

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     163   

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     166   

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

     267   

ITEM 9A. CONTROLS AND PROCEDURES

     267   

ITEM 9B. OTHER INFORMATION

     270   

PART III

     270   

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

     270   

ITEM 11. EXECUTIVE COMPENSATION

     270   

ITEM  12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

     270   

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE

     272   

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

     272   

PART IV

     273   

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

     273   

SIGNATURES

     278   

 


Table of Contents

PART I

In this Annual Report the terms “AES,” “the Company,” “us,” or “we” refer to The AES Corporation and all of its subsidiaries and affiliates, collectively. The term “The AES Corporation” and “Parent Company” refers only to the parent, publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates.

FORWARD-LOOKING INFORMATION

In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.

Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:

 

   

the economic climate, particularly the state of the economy in the areas in which we operate, including the fact that the global economy faces considerable uncertainty for the foreseeable future, which further increases many of the risks discussed in this Form 10-K;

 

   

changes in inflation, demand for power, interest rates and foreign currency exchange rates, including our ability to hedge our interest rate and foreign currency risk;

 

   

changes in the price of electricity at which our Generation businesses sell into the wholesale market and our Utility businesses purchase to distribute to their customers, and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk;

 

   

changes in the prices and availability of coal, gas and other fuels (including our ability to have fuel transported to our facilities) and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts;

 

   

changes in and access to the financial markets, particularly changes affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments and other corporate purposes;

 

   

our ability to manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our senior secured credit facility and other existing financing obligations;

 

   

changes in our or any of our subsidiaries’ corporate credit ratings or the ratings of our or any of our subsidiaries’ debt securities or preferred stock, and changes in the rating agencies’ ratings criteria;

 

   

our ability to purchase and sell assets at attractive prices and on other attractive terms;

 

   

our ability to compete in markets where we do business;

 

   

our ability to manage our operational and maintenance costs;

 

   

the performance and reliability of our generating plants, including our ability to reduce unscheduled down-times;

 

   

our ability to locate and acquire attractive “greenfield” projects and our ability to finance, construct and begin operating our “greenfield” projects on schedule and within budget;

 

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our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as Power Purchase Agreements (“PPA”), fuel supply, and other agreements and to manage counterparty credit risks in these agreements;

 

   

variations in weather, especially mild winters and cooler summers in the areas in which we operate, low levels of wind or sunlight for our wind and solar businesses, and the occurrence of difficult hydrological conditions for our hydro-power plants, as well as hurricanes and other storms and disasters;

 

   

our ability to meet our expectations in the development, construction, operation and performance of our wind businesses, which rely, in part, on actual wind conditions and wind turbine performance being in line with our expectations;

 

   

the success of our initiatives in other renewable energy projects, as well as greenhouse gas emissions reduction projects and energy storage projects;

 

   

our ability to keep up with advances in technology;

 

   

the potential effects of threatened or actual acts of terrorism and war;

 

   

the expropriation or nationalization of our businesses or assets by foreign governments, whether with or without adequate compensation;

 

   

our ability to achieve expected rate increases in our Utility businesses;

 

   

changes in laws, rules and regulations affecting our international businesses;

 

   

changes in laws, rules and regulations affecting our North America business, including, but not limited to, deregulation of wholesale power markets and its effects on competition, the ability to recover net utility assets and other potential stranded costs by our utilities, the establishment of a regional transmission organization that includes our utility service territory, the application of market power criteria by the Federal Energy Regulatory Commission, changes in law resulting from new federal energy legislation, including the effects of the repeal of Public Utility Holding Company Act of 1935, and changes in political or regulatory oversight or incentives affecting our wind business, our solar joint venture, our other renewables projects and our initiatives in greenhouse gas reductions and energy storage including tax incentives;

 

   

changes in environmental laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, hazardous air pollutants and other substances, greenhouse gas legislation, regulation and/or treaties and coal ash regulation;

 

   

changes in tax laws and the effects of our strategies to reduce tax payments;

 

   

the effects of litigation and government and regulatory investigations;

 

   

our ability to maintain adequate insurance;

 

   

decreases in the value of pension plan assets, increases in pension plan expenses and our ability to fund defined benefit pension and other post-retirement plans at our subsidiaries;

 

   

losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets;

 

   

changes in accounting standards, corporate governance and securities law requirements;

 

   

our ability to maintain effective internal controls over financial reporting;

 

   

our ability to attract and retain talented directors, management and other personnel, including, but not limited to, financial personnel in our foreign businesses that have extensive knowledge of accounting principles generally accepted in the United States;

 

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the performance of business and asset acquisitions, including our recent acquisition of DPL Inc., and our ability to successfully integrate and operate acquired businesses and assets, such as DPL, and effectively realize anticipated benefits; and

 

   

information security breaches could harm our businesses.

These factors in addition to others described elsewhere in this Form 10-K, including those described under Item 1A.—Risk Factors, and in subsequent securities filings, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward looking information.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

 

ITEM 1. BUSINESS

Overview

We are a global power company, dedicated to improving lives by providing safe, reliable and sustainable energy solutions in every market we serve. We own a portfolio of electricity generation and distribution businesses on five continents in 27 countries, with total capacity of approximately 44,200 Megawatts (“MW”) and distribution networks serving approximately 12 million customers as of December 31, 2011. In addition, we have approximately 2,400 MW under construction in eight countries. We were incorporated in Delaware in 1981.

We own and operate two primary types of businesses. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. The second is our Utilities business, where we own and/or operate utilities to generate, distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area.

Our assets are diverse with respect to fuel source and type of market, which helps reduce certain types of operating risk. Our portfolio employs a broad range of fuels, including coal, diesel, fuel oil, natural gas, biomass and renewable sources such as hydroelectric power, wind and solar, which reduces the risks associated with dependence on any one fuel source. Our portfolio combines a presence in stable markets in developed countries with faster growing emerging markets. In addition, our Generation portfolio is largely contracted, which reduces the risk related to market prices of electricity and fuel. We also attempt to limit risk by matching the currency of most of our subsidiary debt to the revenue of the underlying business and by hedging some of our interest rate and commodity risk. However, our business is still subject to these and other risks, which are further described in Item 1A.—Risk Factors of this Form 10-K.

Our goal is to maximize value for our shareholders by growing cash flow and earnings per share and achieving better returns on our investments. We will expand our platforms in our core markets, specifically Brazil, Chile, Colombia and the United States, and will work to develop growth platforms in key markets including Turkey, Poland and the United Kingdom. Over time, by focusing our growth and exiting select non-strategic markets, we expect to narrow our geographic focus to achieve better results with fewer countries. Across our portfolio, we will work to optimize profitability, as well as reduce our overhead and business development costs. Finally, we have announced our intent to initiate a dividend beginning in the third quarter of 2012, with the first payment expected to be made in the fourth quarter of 2012.

Key Lines of Business

AES’ primary sources of revenue and gross margin today are from Generation and Utilities. These businesses are distinguished by the nature of the customers, operational differences, cost structure, regulatory environment and risk exposure. The breakout of revenue and gross margin between Generation and Utilities for the years ended December 31, 2011, 2010 and 2009, respectively, is shown below. Operating results for integrated utilities, which have both Generation and Utilities, are reflected in the Utilities amounts below.

 

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Revenue

($ in billions)

 

LOGO

Gross Margin

($ in billions)

 

LOGO

 

(1) 

Utilities gross margin includes the margin from generation businesses owned by the Company and from whom the utility purchases energy.

Generation

We currently own or operate a generation portfolio of approximately 33,800 MW, excluding the generation capabilities of our integrated utilities, consisting of 98 Generation facilities in 22 countries on five continents at our generation businesses. We also have approximately 2,100 MW of capacity currently under construction in four countries. We are a major power source in many countries, such as Chile, where AES Gener (“Gener”) is the second largest electricity generation company in terms of capacity. Our Generation business uses a wide range of technologies and fuel types including coal, combined-cycle gas turbines, hydroelectric power and biomass. Generation revenue was $7.8 billion, $6.9 billion and $5.5 billion for the years ended December 31, 2011, 2010 and 2009, respectively.

Performance drivers for our Generation businesses include, among other factors, plant reliability, fuel costs, power prices, volume and fixed-cost management. Growth in the Generation business is largely tied to securing new power purchase agreements (“PPAs”), expanding capacity in our existing facilities, reducing our fixed costs and building or acquiring new power plants.

The majority of the electricity produced by our Generation businesses is sold under long-term PPAs, to wholesale customers. In 2011, approximately 71% of the contracted revenue from our Generation business was

 

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from plants that operate under PPAs of three years or longer for 75% or more of their output capacity. These businesses often reduce their exposure to fuel supply risks by entering into long-term fuel supply contracts or fuel tolling arrangements where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. These long-term contractual agreements help reduce the volatility of our cash flows and earnings and also reduce exposure to volatility in the market price for electricity and fuel; however, the amount of earnings and cash flow predictability varies from business to business based on the degree to which its exposure is limited by the contracts it has negotiated.

Our Generation businesses with long-term contracts face most of their competition from other utilities and independent power producers (“IPPs”) prior to the execution of a power sales agreement during the development phase of a project or upon expiration of an existing agreement. Once a project is operational, we traditionally have faced limited competition due to the long-term nature of the generation contracts. However, as our existing contracts expire, we may face increased competition to attract new customers and maintain our current customer base.

The balance of our Generation business sells power through competitive markets under short-term contracts, directly in the spot market or, in some cases, at regulated prices. As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity, natural gas, coal and other fuels. Competitive factors for these facilities include price, reliability, operational cost and third-party credit requirements.

Utilities

AES utility businesses distribute power to over 12 million people in six countries on five continents and consist primarily of 13 companies owned or operated under management agreements, each of which operates in defined service areas. These businesses also include 29 generation plants in two countries with generation capacity totaling approximately 8,500 MW. These businesses have a variety of structures ranging from pure distribution businesses to fully integrated utilities, which generate, transmit and distribute power. For instance, our wholly-owned subsidiary in the U.S., Indianapolis Power & Light (“IPL”), has the exclusive right to provide retail services to approximately 470,000 customers in Indianapolis, Indiana. The Dayton Power and Light Company (“DP&L”) serves approximately 500,000 customers in West Central Ohio. Eletropaulo Metropolitana Electricidade de São Paulo S.A. (“AES Eletropaulo” or “Eletropaulo”), serving the São Paulo metropolitan region for over 100 years, has approximately six million customers and is the largest electricity distribution company in Latin America in terms of revenue and electricity distributed. Utilities revenue was $9.5 billion, $8.9 billion and $7.6 billion for the years ended December 31, 2011, 2010 and 2009, respectively.

Performance drivers for Utilities include, but are not limited to, reliability of service, management of working capital, negotiation of tariff adjustments, compliance with extensive regulatory requirements, and in developing countries, reduction of commercial and technical losses. The results of operations of our Utilities businesses are sensitive to changes in economic growth, regulations and variations in weather conditions in the areas in which they operate. In certain locations, our distribution businesses 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.

The majority of our utilities face relatively little direct competition due to significant barriers to entry, which are present in these markets. Competition is a factor in efforts to acquire existing businesses. In this arena, we compete against a number of other market participants, some of which have greater financial resources, have been engaged in distribution related businesses for longer periods of time and/or have accumulated more significant portfolios. Relevant competitive factors for our power distribution businesses include financial resources, governmental assistance, regulatory restrictions and access to non-recourse financing.

Renewables and Other Initiatives

In recent years, as demand for renewable sources of energy has grown, we have developed projects in wind, solar and other renewable initiatives including energy storage. In 2005, we started a wind generation business

 

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(“Wind Generation”), which currently has 21 plants in operation in five countries totaling approximately 1,800 MW in generation capacity and is one of the largest producers of wind power in the U.S. In addition, 205 MW are under construction in four countries. In March 2008, we formed AES Solar Energy LLC (“AES Solar”), a joint venture with Riverstone Holdings, LLC (“Riverstone”), a private equity firm, which has since commenced commercial operations of 26 plants totaling 151 MW of solar projects in Bulgaria, France, Greece, Italy and Spain. We also have a line of business to develop and implement utility scale energy storage systems (such as batteries), which store and release power when needed. None of these initiatives are currently material to our operations, however, there are risks associated with these initiatives, which are further described in Item 1A.—Risk Factors of this Form 10-K.

Risks

We routinely encounter and address risks, some of which may cause our future results to be different, sometimes materially different, than we presently anticipate. The categories of risk we have identified in Item 1A.—Risk Factors of this Form 10-K include the following:

 

   

risks related to our high level of indebtedness;

 

   

risks associated with our ability to raise needed capital;

 

   

external risks associated with revenue and earnings volatility;

 

   

risks associated with our operations;

 

   

risks associated with governmental regulation and laws; and

 

   

risks associated with our disclosure controls and internal controls over financial reporting.

The categories of risk identified above are discussed in greater detail in Item 1A.—Risk Factors of this Form 10-K. These risk factors should be read in conjunction with Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related notes included elsewhere in this report.

Our Organization and Segments

We believe our broad geographic footprint allows us to focus development in targeted markets with opportunities for new investment, and provides stability through our presence in more developed regions. In addition, our presence in each region affords us important relationships and helps us identify local markets with attractive opportunities for new investment. In October 2011, the Company announced a plan to redefine its operational management and organizational structure. The planned reporting structure will remain organized along two lines of business—Generation and Utilities, each led by a Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). Our CEO and COOs are based in Arlington, Virginia.

We are continuing to evaluate both the timing and impact, if any, that the new operational and management and organizational structure will have on our reportable segments. For the year ended 2011, the Company’s segment reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively, “EMEA”), which reflects how we manage the business internally. Additionally, Wind Generation is managed within our North America region. For financial reporting purposes, the Company has six reportable segments which include:

 

   

Latin America—Generation;

 

   

Latin America—Utilities;

 

   

North America—Generation;

 

   

North America—Utilities;

 

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Europe—Generation;

 

   

Asia—Generation.

Corporate and Other—The Company’s Europe Utilities, Africa Utilities, Africa Generation and Wind Generation businesses as well as the Company’s renewables initiatives are reported within “Corporate and Other” because they do not require separate disclosure under segment reporting accounting guidance. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion of the Company’s segment structure used for financial reporting purposes.

The following describes our businesses as they are aligned in our segment reporting structure for financial reporting purposes.

Latin America

Our Latin America operations accounted for 65%, 65% and 66% of consolidated AES revenue in 2011, 2010 and 2009, respectively. The following table provides highlights of our Latin America operations:

 

Countries

  

Argentina, Brazil, Chile, Colombia, Dominican Republic, El Salvador and Panama

Generation Capacity

  

12,616 Gross MW

Utilities Penetration

  

8.7 million customers (48,470 Gigawatt Hours (“GWh”))

Generation Facilities

  

56 (including 1 under construction)

Utilities Businesses

  

6

Key Generation Businesses

  

Gener, Tietê and Alicura

Key Utilities Businesses

  

Eletropaulo and Sul

The bar charts below shows the breakdown between our Latin America Generation and Utilities segments as a percentage of total Latin America revenue and gross margin for the years ended December 31, 2011, 2010, and 2009. See Note 16—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment.

 

Revenue

($ in billions)

 

LOGO

 

Gross Margin

($ in billions)

 

LOGO

Latin America Generation. Our largest generation business in Latin America, AES Tietê (“Tietê”), located in Brazil, represents approximately 18% of the total generation capacity in the state of São Paulo and is the tenth largest generator in Brazil. AES holds a 24% economic interest in Tietê. In Chile, we are the second largest generator of power. We currently have one new generation plant under construction in Chile with a generation capacity of 270 MW.

 

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Set forth below is a list of our Latin America Generation facilities:

Generation

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
or Began
Operation
 

Alicura

   Argentina    Hydro      1,050        99     2000  

Gener—TermoAndes

   Argentina    Gas/Diesel      643        71     2000  

Los Caracoles(1)

   Argentina    Hydro      125        0     2009  

Paraná-GT

   Argentina    Gas/Diesel      845        99     2001  

Quebrada de Ullum(1)

   Argentina    Hydro      45        0     2004  

Rio Juramento—Cabra Corral

   Argentina    Hydro      102        99     1995  

Rio Juramento—El Tunal

   Argentina    Hydro      10        99     1995  

San Juan—Sarmiento

   Argentina    Gas/Diesel      33        99     1996  

San Juan—Ullum

   Argentina    Hydro      45        99     1996  

San Nicolás

   Argentina    Coal/Gas/Oil      675        99     1993  

Tietê(2)

   Brazil    Hydro      2,659        24     1999  

Uruguaiana

   Brazil    Gas      639        46     2000  

Gener—Electrica Angamos

   Chile    Coal      545        71     2011  

Gener—Electrica Santiago(3)

   Chile    Gas/Diesel      479        64     2000  

Gener—Electrica Ventanas(4)

   Chile    Coal      272        71     2010  

Gener—Gener(5)

   Chile    Hydro/Coal/Diesel
/Biomass
     1,003        71     2000  

Gener—Guacolda(6),(7)

   Chile    Coal/Pet Coke      608        35     2000  

Gener—Norgener

   Chile    Coal/Pet Coke      277        71     2000  

Chivor

   Colombia    Hydro      1,000        71     2000  

Andres

   Dominican Republic    Gas      319        100     2003  

Itabo(8)

   Dominican Republic    Coal      295        50     2000  

Los Mina

   Dominican Republic    Gas      236        100     1996  

AES Nejapa

   El Salvador    Landfill Gas      6        100     2011  

Bayano

   Panama    Hydro      260        49     1999  

Changuinola

   Panama    Hydro      223        100     2011  

Chiriqui—Esti

   Panama    Hydro      120        49     2003  

Chiriqui—La Estrella

   Panama    Hydro      48        49     1999  

Chiriqui—Los Valles

   Panama    Hydro      54        49     1999  
        

 

 

      
           12,616       
        

 

 

      

 

(1) 

AES operates these facilities through management or operations and maintenance (“O&M”) agreements and owns no equity interest in these businesses.

(2) 

Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim and seven other small hydroelectric plants below Tietê’s wholly-owned subsidiary “PCH Minas Ltda”.

(3) 

Gener—Electrica Santiago plants: Nueva Renca and Renca.

(4) 

Gener—Electrica Ventanas plant: Nueva Ventanas.

(5) 

Gener—Gener plants: Alfalfal, Constitución, Laguna Verde, Laguna Verde Turbogas, Laja, Los Vientos, Maitenas, Queltehues, San Francisco de Mostazal, Santa Lidia, Ventanas and Volcán.

(6) 

Gener—Guacolda plants: Guacolda 1, Guacolda 2, Guacolda 3 and Guacolda 4.

(7) 

Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates.

(8) 

Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine).

 

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Generation under construction

 

Business

  

Location

  

Fuel

   Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Expected
Year of
Commercial
Operations
 

Campiche

   Chile    Coal      270        71     2013  

Latin America Utilities. Each of our Utilities businesses in Latin America sells electricity under regulated tariff agreements and has transmission and distribution capabilities but none of them has generation capability. AES Eletropaulo, a consolidated subsidiary of which AES owns a 16% economic interest and which has served the São Paulo, Brazil area for over 100 years, has approximately six million customers and is the largest electricity distribution company in Latin America in terms of revenue and electricity distributed. Pursuant to its concession agreement, AES Eletropaulo is entitled to distribute electricity in its service area until 2028. AES Eletropaulo’s service territory consists of 24 municipalities in the greater São Paulo metropolitan area and adjacent regions that account for approximately 17% of Brazil’s GDP and 40% of the population in the State of São Paulo. AES Sul (“Sul”), a wholly-owned subsidiary, serves over one million customers.

Set forth below is a list of our Latin America Utilities facilities:

Distribution

 

Business

   Location    Approximate
Number of
Customers
Served as of
12/31/2011
     GWh
Sold in
2011
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
 

Eletropaulo

   Brazil      6,348,000        36,817        16     1998  

Sul

   Brazil      1,260,000        8,223        100     1997  

CAESS

   El Salvador      516,000        2,060        75     2000  

CLESA

   El Salvador      304,000        786        64     1998  

DEUSEM

   El Salvador      62,000        108        74     2000  

EEO

   El Salvador      229,000        476        89     2000  
     

 

 

    

 

 

      
        8,719,000        48,470       
     

 

 

    

 

 

      

North America

Our North America operations accounted for 16%, 16% and 19% of consolidated revenue in 2011, 2010 and 2009, respectively. The following table provides highlights of our North America operations:

 

Countries

   U.S., Puerto Rico, Mexico and Trinidad

Generation Capacity

   15,756 Gross MW

Utilities Penetration

   970,000 customers (16,890 GWh)

Generation Facilities

   15

Utilities Businesses

  

2 integrated utilities (includes 18 generation plants)

Key Generation Businesses

   Southland and TEG/TEP

Key Utilities Businesses

   IPL, DPL

The bar charts below shows the breakdown between our North America Generation and Utilities segments as a percentage of total North America revenue and gross margin for the years ended December 31, 2011, 2010 and 2009. See Note 16—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment.

 

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Table of Contents

 

Revenue

($ in billions)

 

LOGO

 

Gross Margin

($ in millions)

 

LOGO

North America Generation. Approximately 92% of the generation capacity is supported by long-term power purchase or tolling agreements. Our North America Generation business consists of seven gas-fired, five coal-fired and three petroleum coke-fired plants in the United States, Puerto Rico, Mexico and Trinidad.

Our largest generation business is AES Southland. This business operates three gas-fired plants, representing generation capacity of 3,853 MW, in the Los Angeles basin under a long-term tolling agreement. Other significant generation facilities include TEG and TEP, which represent a total of 460 MW of long-term contracted generation capacity in Mexico.

Set forth below is a list of our North America Generation facilities:

Generation

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Ownership
(Percent,
Rounded)
    Year
Acquired or
Began
Operation
 

Mérida III

   Mexico    Gas      484        55     2000  

Termoelectrica del Golfo (TEG)

   Mexico    Pet Coke      230        99     2007  

Termoelectrica del Peñoles (TEP)

   Mexico    Pet Coke      230        99     2007  

Trinidad

   Trinidad    Gas      394        10     2011  

Southland—Alamitos

   USA—CA    Gas      2,047        100     1998  

Southland—Huntington Beach

   USA—CA    Gas      430        100     1998  

Southland—Redondo Beach

   USA—CA    Gas      1,376        100     1998  

Hawaii

   USA—HI    Coal      203        100     1992  

Warrior Run

   USA—MD    Coal      205        100     2000  

Red Oak

   USA—NJ    Gas      832        100     2002  

Shady Point

   USA—OK    Coal      360        100     1991  

Beaver Valley

   USA—PA    Coal      125        100     1985  

Ironwood

   USA—PA    Gas      710        100     2001  

Puerto Rico

   USA—PR    Coal      454        100     2002  

Deepwater

   USA—TX    Pet Coke      160        100     1986  
        

 

 

      
           8,240       
        

 

 

      

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Expected
Year of
Commercial
Operations
 

Trinidad

   Trinidad    Gas      394        10     2012  

North America Utilities. AES has two integrated utilities in North America, IPL, which it owns through IPALCO Enterprises, Inc. (“IPALCO”), the parent holding company of IPL and The Dayton Power and Light

 

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Table of Contents

Company (“DP&L”), which it owns through DPL Inc. (“DPL”), the parent company of DP&L. IPL generates, transmits, distributes and sells electricity to approximately 470,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL owns and operates four generating stations. Two of the generating stations are primarily coal-fired stations. The third station has a combination of units that use coal (base load capacity) and natural gas and/or oil (peaking capacity) for fuel to produce electricity. The fourth station is a small peaking station that uses gas-fired combustion turbine technology for the production of electricity. IPL’s gross electric generation capacity is 3,699 MW. Approximately 45% of IPL’s coal is provided by one supplier with which IPL has long-term contracts. A key driver for the business is tariff recovery for environmental projects through the rate adjustment process. IPL’s customers include residential, industrial, commercial and all other which made up 33%, 13%, 36% and 6%, respectively, of North America Utilities revenue for 2011. The remaining 12% of North America Utilities revenue is from DPL.

DP&L generates, transmits, distributes and sells electricity to more than 500,000 customers in a 6,000 square mile area of West Central Ohio. DP&L, with certain other Ohio utilities and their affiliates, commonly owns seven coal-fired electric generating facilities and numerous transmission facilities. DP&L also has one wholly-owned coal-fired plant. DP&L is affiliated with DPL Energy, LLC (“DPLE”) which owns peaking generation units located in Ohio and Indiana. DP&L’s wholly-owned plants and share of the capacity of its jointly-owned plants and DPLE’s wholly-owned peaking units aggregates to approximately 3,817 MW. During the period November 28, 2011 through December 31, 2011, approximately 80% of DP&L’s coal was provided by four suppliers and DP&L has long-term contracts with three of them. DP&L’s customers include residential, commercial, industrial and governmental, which make up 67%, 21% and 12%, respectively, of DP&L’s revenue for the period after acquisition in November 2011.

Generation

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
or Began
Operation
 

IPL(1)

   USA—IN    Coal/Gas/Oil      3,699        100     2001  

DP&L(2)

   USA—OH    Coal/Diesel/Solar      3,817        100     2011  
        

 

 

      
           7,516       
        

 

 

      

 

(1) 

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

(2) 

DP&L wholly-owned plants: Hutchings, Tait Units 1-3 and diesels, Yankee Street, Yankee Solar, Monument and Sidney. DP&L jointly-owned plants: Beckjord Unit 6, Conesville Unit 4, East Bend Unit 2, Killen, Miami Fort Units 7 & 8, Stuart and Zimmer. In addition to the above, DP&L, also owns a 4.9% equity ownership in OVEC, an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,655 MW. DP&L’s share of this generation capacity is approximately 111 MW. DPLE plants: Tait Units 4-7 and Montpelier Units 1-4.

Distribution

 

Business

   Location    Approximate
Number of
Customers
Served as of
12/31/2011
     GWh
Sold in
2011
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
 

IPL

   USA—IN      470,000        15,647        100     2001  

DP&L(1)

   USA—OH      500,000        1,243        100     2011  
     

 

 

    

 

 

      
        970,000        16,890       
     

 

 

    

 

 

      

 

(1) 

GWh sold from the acquisition on November 28, 2011 through December 31, 2011.

 

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Table of Contents

Europe

The following table provides highlights of our Europe operations:

 

Countries

  

Bulgaria, Hungary, Jordan, Kazakhstan, Netherlands, Spain, Turkey, Ukraine and the United Kingdom

Generation Capacity

   8,779 Gross MW

Utilities Penetration

   1.8 million customers (10,862 GWh)

Generation Facilities

   19

Utilities Businesses

   4

Key Generation Businesses

   Maritza, Ballylumford, Kilroot

Key Utilities Businesses

   Kievoblenergo and Rivneenergo

Our Utilities operations in Europe are discussed further under Corporate and Other below.

Europe Generation. Our Generation operations in Europe accounted for 9%, 8% and 6% of our consolidated revenue in 2011, 2010 and 2009, respectively. In 2011, our Maritza facility in Bulgaria, a 670 MW coal-fired plant, commenced commercial operations. As a result of the announced sale of 80% of our interest in Cartagena, a 1,199 MW gas-fired plant in Spain, we have classified Cartagena as “held for sale” on the Consolidated Balance Sheets. AES operates four power plants in Kazakhstan which account for 8% of the country’s total installed generation capacity. In the United Kingdom, we own and operate more than 1,900 MW at the Ballylumford plant and the Kilroot facility. See Note 16—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for revenue, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment. Key business drivers of this segment are: foreign currency exchange rates, new legislation and regulations including those related to the environment.

 

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Table of Contents

Set forth below is a list of our Europe Generation facilities:

Generation

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
or Began
Operation
 

Maritza

   Bulgaria    Coal      670        100     2011  

Tisza II

   Hungary    Gas/Oil      900        100     1996  

Amman East

   Jordan    Gas      380        37     2009  

Shulbinsk HPP(1)

   Kazakhstan    Hydro      702        0     1997  

Sogrinsk CHP

   Kazakhstan    Coal      301        100     1997  

Ust—Kamenogorsk HPP(1)

   Kazakhstan    Hydro      331        0     1997  

Ust—Kamenogorsk CHP

   Kazakhstan    Coal      1,354        100     1997  

Elsta(2)

   Netherlands    Gas      630        50     1998  

Cartagena(3)

   Spain    Gas      1,199        71     2006  

Damlapinar(2),(4)

   Turkey    Hydro      16        51     2010  

Girlevik II-Mercan(2),(4)

   Turkey    Hydro      12        51     2007  

Kepezkaya(2),(4)

   Turkey    Hydro      28        51     2010  

Yukari-Mercan(2),(4)

   Turkey    Hydro      14        51     2007  

Kumkoy(2),(4)

   Turkey    Hydro      18        51     2011  

Bursa(2),(5)

   Turkey    Gas      156        50     2011  

Kocaeli(2),(5)

   Turkey    Gas      158        50     2011  

Istanbul (Koc University)(2),(5)

   Turkey    Gas      2        50     2011  

Ballylumford

   United Kingdom    Gas      1,246        100     2010  

Kilroot(6)

   United Kingdom    Coal/Gas/Oil      662        99     1992  
        

 

 

      
           8,779       
        

 

 

      

 

(1) 

AES operates these facilities under concession agreements until 2017.

(2) 

Unconsolidated entities, the results of operations of which are reflected in Equity in Earnings of Affiliates.

(3) 

In October 2011, the Company met held for sale criteria and expects to dispose of 80% of its interest in this business within the next twelve months. Until the business is sold, it will be reported as a held for sale business on the Consolidated Balance Sheets and reflected in continuing operations on the Consolidated Statements of Operations, as the Company continues to hold an ownership interest in the business.

(4) 

Joint Venture with I.C. Energy.

(5) 

Joint Venture with Koc Holding.

(6) 

Includes Kilroot Open Cycle Gas Turbine (“OCGT”).

Asia

Our Asia operations accounted for 4%, 4% and 3% of consolidated revenue in 2011, 2010 and 2009, respectively. Asia’s Generation business operates 7 power plants with a total capacity of 3,802 MW in four countries. In Asia, AES operates generation facilities only. See Note 16—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for revenue, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment. The following table provides highlights of our Asia operations:

 

Countries

   China, India, the Philippines and Sri Lanka

Generation Capacity

   3,802 Gross MW

Utilities Penetration

   None

Generation Facilities

   8 (including 1 under construction)

Utilities Businesses

   None

Key Businesses

   Masinloc, Kelanitissa and Yangcheng

 

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Table of Contents

Asia Generation. More than half of our generation capacity in Asia is located in China. In 1996, AES joined with Chinese partners to build Yangcheng, the first “coal-by-wire” power plant with the generation capacity of 2,100 MW. In April 2008, the Company completed the purchase of a 92% interest in a 660 MW coal-fired thermal power generation facility in Masinloc, Philippines (“Masinloc”).

Set forth below is a list of our generation facilities in Asia:

Generation

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
or Began
Operation
 

Chengdu(1)

   China    Gas      50        35     1997  

Cili

   China    Hydro      25        51     1994  

JHRH(1)

   China    Hydro      379        49     2010  

Yangcheng(1)

   China    Coal      2,100        25     2001  

OPGC(1)

   India    Coal      420        49     1998  

Masinloc

   Philippines    Coal      660        92     2008  

Kelanitissa

   Sri Lanka    Diesel      168        90     2003  
        

 

 

      
           3,802       
        

 

 

      

 

(1) 

Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates.

Generation under construction

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Expected
Year of
Commercial
Operation
 

Mong Duong II

   Vietnam    Coal      1,200        51     2015  

Corporate and Other

“Corporate and Other” includes the net operating results from our Utilities businesses in Africa and Europe, Africa Generation and Wind Generation and other renewables projects. These operations do not require separate segment disclosure. The following provides additional details about our Utilities businesses in Africa and Europe, Africa generation and Wind Generation, which are reported within “Corporate and Other” for financial reporting purposes.

Europe Utilities. Our distribution businesses in the Ukraine and Kazakhstan together serve approximately 1.8 million customers.

 

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Table of Contents

Distribution

 

Business

   Location      Approximate
Number of
Customers
Served as of
12/31/2011
     GWh
Sold in
2011
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
 

Eastern Kazakhstan REC(1),(2),(3)

     Kazakhstan         459,000        3,444        0  

Ust-Kamenogorsk Heat Nets(1),(4)

     Kazakhstan         96,000        —           0  

Kievoblenergo

     Ukraine         874,000        5,079        89     2001  

Rivneenergo

     Ukraine         409,000        2,339        84     2001  
     

 

 

    

 

 

      
        1,838,000        10,862       
     

 

 

    

 

 

      

 

(1) 

AES operates these businesses through management agreements and owns no equity interest in these businesses.

(2) 

In November 2011, AES sent notification to the Kazakhstan Government regarding the early termination of the management agreement for these companies. Transfer of management rights to the Kazakhstan Government should be completed within 180 days.

(3) 

Shygys Energo Trade, a retail electricity company, is 100% owned by Eastern Kazakhstan REC (“EK REC”) and purchases distribution service from EK REC and electricity in the wholesale electricity market and resells to the distribution customers of EK REC.

(4) 

Ust-Kamenogorsk Heat Nets provide transmission and distribution of heat with a total heat generating capacity of 224 Gcal.

Africa Utilities. AES owns a 56% interest in an integrated utility, Société Nationale d’Electricité (“Sonel”). Sonel generates, transmits and distributes electricity to over half a million people and is the sole distributor of electricity in Cameroon.

Set forth below is a list of the generation and distribution facilities of Sonel:

Sonel’s generation facilities

 

Business

   Location      Fuel      Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
or Began
Operation
 

Sonel(1)

     Cameroon         Hydro/Diesel/Heavy Fuel Oil         936        56     2001  

 

(1) 

Sonel plants: Bafoussam, Bassa, Djamboutou, Edéa, Lagdo, Limbé, Logbaba I, Logbaba II, Oyomabang I, Oyomabang II, Song Loulou, and other small remote network units.

Sonel’s distribution facility

 

Business

   Location      Approximate
Number of
Customers
Served as of
12/31/2011
     GWh
Sold in
2011
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired
 

Sonel

     Cameroon         660,000        3,345        56     2001  

Africa Generation. Set forth below is a list of our generation facilities in Africa:

 

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Table of Contents

Generation

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired

or Began
Operation
 

Dibamba

   Cameroon    Heavy Fuel Oil      86        56     2009  

Ebute

   Nigeria    Gas      294        95     2001  
        

 

 

      
           380       
        

 

 

      

Generation under construction

 

Business

   Location    Fuel    Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Expected
Year of
Commercial
Operations
 

Kribi

   Cameroon    Gas              216        56     2013  

Wind Generation. We own and operate 1,616 MW of wind generation capacity and operate an additional 134 MW of capacity through operating and management agreements. Our wind business is located primarily in North America where we operate wind generation facilities that have generation capacity of 1,266 MW.

Set forth below is a list of Wind Generation facilities:

Generation

 

Business

   Location    Power
Source
   Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Year
Acquired or
Began
Operation
 

St. Nikola

   Bulgaria    Wind      156        89     2010  

Dong Qi(1),(2)

   China    Wind      49        49     2010  

Huanghua I(1),(2)

   China    Wind      49        49     2009  

Huanghua II(1),(2)

   China    Wind      49        49     2010  

Hulunbeier(1),(2)

   China    Wind      49        49     2008  

InnoVent(2),(3)

   France    Wind      75        40     2003-2009   

St. Patrick

   France    Wind      35        100     2010  

North Rhins

   Scotland    Wind      22        100     2010  

Altamont

   USA—CA    Wind      40        100     2005  

Mountain View I & II(4)

   USA—CA    Wind      67        100     2008  

Palm Springs

   USA—CA    Wind      30        100     2005  

Tehachapi

   USA—CA    Wind      38        100     2006  

Storm Lake II(4)

   USA—IA    Wind      78        100     2007  

Lake Benton I(4)

   USA—MN    Wind      106        100     2007  

Condon(4)

   USA—OR    Wind      50        100     2005  

Armenia Mountain(4)

   USA—PA    Wind      101        100     2009  

Buffalo Gap I(4)

   USA—TX    Wind      121        100     2006  

Buffalo Gap II(4)

   USA—TX    Wind      233        100     2007  

Buffalo Gap III(4)

   USA—TX    Wind      170        100     2008  

Laurel Mountain

   USA—WV    Wind      98        100     2011  

Wind generation facilities(5)

   USA    Wind      134        0     2005  
        

 

 

      
           1,750       
        

 

 

      

 

(1) 

Joint Venture with Guohua Energy Investment Co. Ltd.

 

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Table of Contents
(2) 

Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates.

(3) 

InnoVent plants: Bignan, Chepy, Croixrault-Moyencourt, Eurotunel, Frenouville, Gapree, Grand Fougeray, Guehenno, Hargicourt, Hescamps, LePortal, Les Diagots, Nibas, Plechatel, Saint-Hilaire la Croix and Valhoun. InnoVent owns various percentages of underlying projects.

(4) 

AES owns these assets together with third party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as Noncontrolling Interest in the Company’s Consolidated Balance Sheets.

(5)

AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.

Wind Generation projects under construction

 

Business

   Location    Power
Source
   Gross
MW
     AES Equity
Interest
(Percent,
Rounded)
    Expected
Year of
Commercial
Operation
 

InnoVent(1)

   France    Wind      39        40     2012  

Chen Qi(2)

   China    Wind      49        49     2012  

Saurashtra

   India    Wind      39        100     2012  

Drone Hill

   United Kingdom    Wind      29        100     2012  

Mountain View IV

   US-CA    Wind      49        100     2012  
        

 

 

      
           205       
        

 

 

      

 

(1) 

InnoVent plants: Allery, Audrieu, Lamballe, Lefaux and Vron. InnoVent owns various percentages of underlying projects.

(2) 

Joint Venture with Guohua Energy Investment Co. Ltd.

Other. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting. Therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue and gross margin. AES Solar was formed in March 2008 to develop, own and operate solar installations. Since its launch, AES Solar has commenced commercial operations of 151 MW of solar projects in Bulgaria, France, Greece, Italy and Spain; and has 106 MW under construction in Bulgaria, France, Greece, India, Italy and the U.S.

“Corporate and Other” also includes costs related to corporate overhead which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation. See Note 16—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, Adjusted Gross Margin (a non-GAAP measure) and total assets by segment.

 

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Table of Contents

Financial Data by Country

The table below presents information, by country, about our consolidated operations for each of the three years ended December 31, 2011, 2010 and 2009, respectively, and property, plant and equipment as of December 31, 2011 and 2010, respectively. Revenue is recognized in the country in which it is earned and assets are reflected in the country in which they are located.

 

     Revenue      Property, Plant & Equipment, net  
     2011      2010      2009              2011                      2010          
                   (in millions)         

United States(1)

   $ 2,256      $ 2,095      $ 1,987      $ 8,448      $ 6,027  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Non-U.S.:

              

Brazil(2)

     6,640        6,355        5,292        5,896        6,263  

Chile

     1,608        1,355        1,239        2,781        2,560  

Argentina(3)

     979        771        571        279        270  

El Salvador

     752        648        619        268        261  

Dominican Republic

     674        535        429        662        625  

United Kingdom(4)

     587        364        228        523        507  

Philippines

     480        501        250        766        784  

Ukraine

     418        356        286        94        86  

Mexico

     404        409        329        774        786  

Cameroon

     386        422        370        901        823  

Colombia

     365        393        347        384        387  

Puerto Rico

     298        253        267        581        596  

Spain(5)

     258        411        —           —           —     

Bulgaria(6)

     251        44        —           1,619        1,825  

Hungary(7)

     204        252        259        6        73  

Panama

     189        194        168        1,040        921  

Kazakhstan

     145        138        123        86        63  

Sri Lanka

     140        100        109        22        69  

Jordan

     124        120        104        216        224  

Qatar(8)

     —           —           —           —           —     

Pakistan(9)

     —           —           —           —           —     

Oman(10)

     —           —           —           —           —     

Other Non-U.S.(11)

     116        112        133        385        279  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Non-U.S.

     15,018        13,733        11,123        17,283        17,402  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 17,274      $ 15,828      $ 13,110      $ 25,731      $ 23,429  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Excludes revenue of $228 million, $519 million and $559 million for the years ended December 31, 2011, 2010 and 2009, respectively, and property, plant and equipment of $140 million as of December 31, 2010, related to Eastern Energy and Thames, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

(2) 

Excludes revenue of $124 million, $118 million and $102 million for the years ended December 31, 2011, 2010 and 2009, respectively, and property, plant and equipment of $151 million as of December 31, 2010, related to Brazil Telecom, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

(3) 

Excludes revenue of $102 million, $116 million and $113 million for the years ended December 31, 2011, 2010 and 2009, respectively, and property, plant and equipment of $189 million as of December 31, 2010, related to our Argentina distribution businesses, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

 

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(4) 

Excludes revenue of $17 million, $21 million and $11 million for the years ended December 31, 2011, 2010 and 2009, respectively, and property, plant and equipment of $20 million as of December 31, 2010, related to carbon reduction projects, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

(5) 

Excludes property, plant and equipment of $620 million and $667 million as of December 31, 2011 and 2010, respectively, related to Cartagena, which was reflected as businesses held for sale in the accompanying Consolidated Balance Sheets.

(6) 

Maritza and our wind project in Bulgaria were under development and therefore not operational as of December 31, 2009. Our wind project in Bulgaria started operations in 2010 and Maritza started operations in June 2011.

(7) 

Excludes revenue of $14 million, $44 million and $58 million for the years ended December 31, 2011, 2010 and 2009, respectively, and property, plant and equipment of $7 million as of December 31, 2010, related to Borsod and Tiszapalkonya, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

(8) 

Excludes revenue of $129 million and $163 million for the years ended December 31, 2010 and 2009, respectively, related to Ras Laffan, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations.

(9) 

Excludes revenue of $299 million and $470 million for the years ended December 31, 2010 and 2009, respectively, related to Lal Pir and Pak Gen, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations.

(10) 

Excludes revenue of $62 million and $101 million for the years ended December 31, 2010 and 2009, respectively, related to Barka, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations.

(11) 

Excludes revenue of $1 million for the year ended December 31, 2011, and property, plant and equipment of $2 million and $18 million as of December 31, 2011, and 2010, respectively, related to alternative energy and carbon reduction projects, which were reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.

Customers

We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2011 total revenue. In our generation business, we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. Our utilities sell to end-user customers in the residential, commercial, industrial and governmental sectors in a defined service area.

Employees

As of December 31, 2011, we employed approximately 27,000 people.

Executive Officers

The following individuals are our executive officers:

Andrés R. Gluski, 54 years old, has been President, Chief Executive Officer (“CEO”) and a member of our Board of Directors since September 2011. Prior to assuming his current position, Mr. Gluski served as Executive Vice President and Chief Operating Officer (“COO”) of the Company since March 2007. Prior to becoming the COO of AES, Mr. Gluski was Executive Vice President and the Regional President of Latin America from 2006 to 2007. Mr. Gluski was Senior Vice President for the Caribbean and Central America from 2003 to 2006, CEO of La Electricidad de Caracas (“EDC”) from 2002 to 2003 and CEO of AES Gener (Chile) in 2001. Prior to joining AES in 2000, Mr. Gluski was Executive Vice President and CFO of EDC, Executive Vice President of Banco de Venezuela (Grupo Santander), Vice President for Santander Investment, and Executive Vice President and CFO of CANTV (subsidiary of GTE). Mr. Gluski has also worked with the International Monetary Fund in the Treasury and Latin American Departments and served as Director General of the Ministry of Finance of

 

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Venezuela. Mr. Gluski is also Chairman of AES Gener and AES Brasiliana and serves on the Boards of two AES joint ventures: AES Entek, a joint venture between AES and Koc Holdings that will develop and operate power projects in Turkey and AES Solar, a joint venture between AES and Riverstone Holdings LLC. Mr. Gluski is also on the Boards of Cliffs Natural Resources, The Council of Americas, US Spain Business Council and The Edison Electric Institute. Mr. Gluski is a graduate of Wake Forest University and holds an M.A and a Ph.D. in Economics from the University of Virginia.

Ned Hall, 52 years old, has been Chief Operating Officer, Global Generation, and Executive Vice President since October of 2011. Prior to assuming his current position, Mr. Hall was Executive Vice President, Regional President for North America and Chairman, Global Wind Generation and Energy Storage since June 2008. In August of 2009, Mr. Hall joined the Board of AES Solar, a joint venture between AES and Riverstone Holdings LLC. Mr. Hall is also a director on the AES Gener and AES Entek Boards. Prior to his current position, Mr. Hall was Vice President of the Company and President, Global Wind Generation from April 2005 to June 2008, Managing Director of AES Global Development from September 2003 to April 2005, and was an AES Group Manager from April 2001 to September 2003. Mr. Hall joined AES in 1988 as a Project Manager working in the Development Group and has held a variety of development and operating roles for AES, including assignments in the U.S., Europe, Asia and Latin America. He is a registered professional engineer in the Commonwealth of Massachusetts. Mr. Hall holds a BSME degree from Tufts University and an MBA degree in finance/operations management from the MIT Sloan School of Management.

Victoria D. Harker, 47 years old, has been an Executive Vice President and Chief Financial Officer (“CFO”) since January 2006. In 2011, she also became President, Global Business Services. Prior to joining the Company, Ms. Harker held the positions of Acting CFO, Senior Vice President and Treasurer of MCI from November 2002 to January 2006. Prior to that, Ms. Harker served as CFO 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. In November of 2009, she was elected to the board of directors of Darden Restaurants, Inc. and in 2011 she was elected as a Director of Xylem, Inc. She has also been a member of the University of Virginia Board of Managers since 2007 and the board of the Wolf Trap Foundation for the Performing Arts since 2009. Ms. Harker received a Bachelor of Arts degree in English and Economics from the University of Virginia and a Masters in Business Administration, Finance from American University.

Brian A. Miller, 46 years old, is an Executive Vice President of the Company, General Counsel, and Corporate Secretary. Mr. Miller joined the Company in 2001 and has served in various positions including Vice President, Deputy General Counsel, Corporate Secretary, General Counsel for North America and Assistant General Counsel. In March of 2008, Mr. Miller joined the Board of AES Solar Energy, Ltd. and AES Solar Power, LLC, joint ventures between AES and Riverstone Holdings LLC. In 2009, he joined the board of AgCert International Limited and AgCert Canada Holding Limited. In 2010, Mr. Miller joined the Board of AES Entek, a joint venture that will develop and operate power projects in Turkey, between AES and Koc Holdings. In November of 2011, Mr. Miller joined the Board of DPL Inc., owner of Dayton Power & Light Company. Prior to joining AES, he was an attorney with the law firm Chadbourne & Parke, LLP. Mr. Miller received a bachelor’s degree in History and Economics from Boston College and holds a Juris Doctorate from the University of Connecticut School Of Law.

Rita Trehan, 44 years old, is Vice President of Human Resources and Internal Communications, Safety and AES Performance Excellence (APEX), the Company’s worldwide performance improvement program since 2011. Prior to her current position, Ms. Trehan served as Vice President, Human Resources and Internal Communications from 2008 to 2011 and Vice President, People and Learning from 2005 to 2008. She has served on the Board of Directors for AES Sonel in Cameroon since 2004. Ms. Trehan joined AES in 2003 as Director of Learning and People Development. Before joining AES, Ms. Trehan held a number of senior human resources leadership positions at Honeywell International, including Global Human Resources Director for the Sensing & Controls Division. Ms. Trehan also served in various corporate and global human resources business roles during her 15 years at Honeywell. Ms. Trehan holds a Bachelor of Science in Sociology from Brunel University in Middlesex, UK and a postgraduate diploma from the Institute of Personnel Management.

 

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Andrew Vesey, 56 years old, has been Chief Operating Officer, Global Utilities, and Executive Vice President since October of 2011. Prior to assuming his current position, Mr. Vesey was Executive Vice President and Regional President of Latin America and Africa since April of 2009, Executive Vice President and Regional President for Latin America from March 2008 through March 2009, and Chief Operating Officer for Latin America from July 2007 through February 2008. Mr. Vesey also served as Vice President and Group Manager for AES Latin America, DR-CAFTA Region, Vice President of the Global Business Transformation Group, and Vice President of the Integrated Utilities Development Group. Mr. Vesey is also Chairman of the AES Sul, AES Tiete, IPL, IPALCO, DPL, DP&L Boards and serves on the Boards of AES Sonel, Brasiliana, and ELPA. In addition, Mr. Vesey is a member of the Board of the Corporate Council of Africa, Trust for the Americas, and the Institute of the Americas. Prior to joining AES in 2004, Mr. Vesey was a Managing Director of the Utility Finance and Regulatory Advisory Practice at FTI Consulting Inc., a partner in the Energy, Chemicals and Utilities Practice of Ernst & Young LLP, and CEO and Managing Director of Citipower Pty of Melbourne, Australia. He received his BA in Economics and a BS in Mechanical Engineering from Union College in Schenectady, New York and his MS from New York University.

Gardner W. Walkup Jr., 52 years old, has been AES’ Vice President of Strategy since 2010. Mr. Walkup has more than 25 years of energy industry experience. Between 2007 and 2010, he served as Vice President and Managing Director at IHS Cambridge Energy Research Associates where he led the Energy and Natural Resources consulting practice that provided strategy development services to clients globally. He held similar leadership roles at a number of business consulting firms including Strategic Decisions Group, PricewaterhouseCoopers and Applied Decision Analysis. In addition, he worked at Chevron for approximately 15 years in a variety of positions, including strategic planning, operations, and research and development. Mr. Walkup has a B.S. in Chemical Engineering from the University of California at Davis and a M.S. in Petroleum Engineering from Stanford University.

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 website 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 (the “Exchange Act”) are posted on our website. After the reports are filed with, or furnished to, the Securities and Exchange Commission (“SEC”), they are available from us free of charge. Material contained on our website is not part of and is not incorporated by reference in this Form 10-K. You may also read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website that contains the reports, proxy and information statements and other information that we file electronically with the SEC at www.sec.gov.

Our CEO and our CFO have provided certifications to the SEC as required by Section 302 of the Sarbanes-Oxley Act of 2002. These certifications are included as exhibits to this Annual Report on Form 10-K.

Our CEO provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on May 12, 2011.

Our Code of Business Conduct (“Code of Conduct”) and Corporate Governance Guidelines have been adopted by our 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 our subsidiaries and affiliates. Our Ethics and Compliance Department provides training, information, and certification programs for AES employees related to the Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering and

 

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associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website at http://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. If any amendments to, or waivers from, the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.

Regulatory Matters

Overview

In each country where we conduct business, we are subject to extensive and complex governmental regulations that affect most aspects of our business, such as regulations governing the generation and distribution of electricity and environmental regulations. These regulations affect the operation, development, growth and ownership of our businesses. Regulations differ on a country-by-country basis and are based upon the type of business we operate in a particular country.

Regulation of our Generation Businesses

Our Generation businesses operate in two different types of regulatory environments: Market Environments and Other Environments.

Market Environments. In market environments, sales of electricity may be made directly on the spot market, under negotiated bilateral contracts, or pursuant to PPAs. The spot markets are typically administered by a central dispatch or system operator that seeks to optimize the use of the generation resources throughout an interconnected system. The spot price is usually set at the marginal cost of energy (the cost of the least expensive next-generation plant required to meet system demand) or based on bid prices. In addition, many of these wholesale markets include markets for ancillary services to support the reliable operation of the transmission system, such as regulation (a service that corrects for short-term changes in electricity use that could impact the stability of the power system). Most of our businesses in Europe, Latin America and the United States operate in these types of liberalized markets.

Other Environments. We operate Generation assets in certain countries that do not have a spot market. In these environments, electricity is sold only through PPAs with state-owned entities and/or industrial clients as the offtaker. Examples of countries where we operate in this type of environment include Jordan, Nigeria, Puerto Rico and Sri Lanka.

Regulation of our Distribution Businesses

In general, our distribution companies sell electricity directly to end-users such as homes and businesses and bill customers directly. The amount that our distribution companies can charge customers for electricity is governed by a regulated tariff. The tariff, in turn, is generally based upon a certain usage level that includes a pass-through to the customer of costs that are not controlled by the distribution company, including the costs of fuel (in the case of integrated utilities) and/or the costs of purchased energy, plus a margin for the value added by the distributor, which is usually calculated as a fair return on the fair value of the company’s assets. This regulated tariff is periodically reviewed and reset by the applicable regulatory agency. Components of the tariff that are directly passed through to the customer are usually adjusted through an automated process. In many instances, the tariffs can be adjusted between scheduled regulatory resets pursuant to an inflation adjustment or another index. Customers with demand above a certain level are often unregulated and can choose to contract with generation companies directly and pay a wheeling fee, which is a fee to the distribution company for use of the distribution system. Most of our utilities operate as monopolies within exclusive geographic areas set by the regulatory agency and face limited competition from other distributors.

 

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Set forth below is a discussion of certain regulations under which we operate in the countries where we do business. In each country, the regulatory environment can pose material risks to our business, operations or financial condition. For further discussion of those risks, see the Item 1A.—Risk Factors of this Form 10-K.

Latin America and Africa

Argentina

Structure of Electricity Market. The Argentine electricity market is divided into three separate lines of business: generation, transmission and distribution. AES Argentina operates 11% of the installed capacity of the Wholesale Electricity Market (“WEM”). The law recognizes a category of large users made up of industrial companies and other consumers with substantial electricity supply needs.

The WEM is comprised of:

 

   

A Term Contracts Market, with contracts freely agreed amongst producers and consumers;

 

   

A Spot Market, with prices sanctioned on an hourly basis considering the economic cost of production represented by the short-term marginal cost (spot prices); and

 

   

A Stabilization System on a quarterly basis of the prices forecasted for the spot market, created for the purchase of the distributors (seasonal prices).

Principal Regulators. The National Electricity Regulating Agency (“ENRE”) is responsible for ensuring that transmission and distribution companies comply with the concessions granted by the Argentine government and approving distribution tariffs. The WEM is managed by Compañía Administradora del Mercado Mayorista Eléctrico, Sociedad Anónima (“CAMMESA”), the independent system operator. CAMMESA also acts as the dispatch entity, or OED (Organismo Encargado de Desapacho), and manages the organization, dispatch and operations of the WEM at large according to the policies established by the Energy Secretariat, under the Ministry of Federal Planning, Public Investment and Services. In this capacity, CAMMESA is empowered to interpret the rules relating to the organization, dispatch and energy agreements in the WEM. In addition to these duties, CAMMESA manages the information on supply and demand in the WEM, which is used by the Energy Secretariat to fix the seasonal prices and the market’s operational rules. CAMMESA’s operating costs are borne by the WEM’s participants and agents.

Principal Regulations. The electricity sector activities are regulated by the Electricity Act. Law 24.065 and Law 11.796 regulate the activities of generation, transmission and distribution of electric energy in the territory of the Province of Buenos Aires, determining that the activities of transmission and distribution of energy are public services, while the generation is an activity of general interest.

Currently, the price of electric energy is determined assuming all generating units in Argentina are operating with natural gas, even though the generators may be using more expensive, alternative fuels. In the case of generators using alternative fuels, CAMMESA pays the total variable cost of production, which may exceed the established spot price. Additionally, in the spot market, generators are also remunerated for their capacity to generate electricity in excess of supply agreements or private contracts executed by them.

The Argentine government has adopted many new economic measures since 2002, by means of the “Emergency Law” 25561, as amended and extended by various supplemental laws and regulations. These laws and regulations effectively terminated the use of the United States Dollar as the functional currency of the Argentine electricity sector.

Environmental Regulations. All electricity facilities are regulated by federal and local laws and regulations. The main federal acts are the following: the General Environmental Act 25.675, the Industrial Disposals Act: 25.612, the Standards for handling and elimination of PCBs 25670, and the Harmful Wastes Act, 24051. Within

 

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the Province of Buenos Aires, the principal acts are: the General Environmental Law 13.516 and the Industrial and Special Wastes Act 13.515. These main laws are complemented by several federal and local decrees and resolutions. The main authorities responsible for environmental regulation related to our businesses are: the National and Provincial Ministers of Public Health and Environment, the Federal and the Provincial Secretaries of Environment and Sustainable Development; and the National Electricity Regulatory Commission.

Material Regulatory Actions. During 2004, the Energy Secretariat reached agreements with natural gas and electricity producers to reform the energy markets. In the electricity sector, the Energy Secretariat passed Resolution 826/2004, inviting generators to contribute a percentage of their sales margins to fund the development and construction of two new combined cycle power plants to be installed by 2008/2009 (“FONINVEMEM I & II”). The time period for the funding was set from January 2004 through December 2006 and was subsequently extended through December 2007. During 2008, both power plants started operation of the gas turbines, and since March 2010, the plants started operations in combined cycle mode after receiving commercial habilitation. In exchange, the Argentine government committed to reform market regulation to match more favorable regulations that existed prior to 2001. Additionally, participating generators will receive a pro rata ownership share in the new generation plants for ten years. Since March 2010, our participating generation companies are collecting their sales margin contributed for the construction of the facilities in monthly installments.

A general agreement with the rest of the Generators operating in Argentina and the government was signed on November 25, 2010 to address a nation-wide problem of overdue accounts receivable in the generation market. The agreement established the guidelines for the detailed documentation that will allow the execution of the FONINVEMEM III project agreement and some additional cash revenues. Under the agreement, accounts receivable accrued for Alicura (our subsidiary) from July 2009 to December 2011, for an amount of approximately $170 million, will be converted into a generation asset to be built under the FONINVEMEM III project. The government will provide the funds necessary to finance the project. The plant will have a PPA with CAMMESA for ten years, calculated to recover 100% of the receivables invested plus a margin of LIBOR + 5%. Payments will be made once the project begins operations. We expect the existing FONINVEMEM I & II documents will be taken as a basis for the future contracts; assuming this, the collection of the 120 payments will not be tied to the availability of the plant. Availability risk will be assumed by the operator through a Long-Term Service Agreement (“LTSA”). Some penalties may apply to the generating companies, but only in those cases where the unavailability is caused by their operating decisions not considered in the LTSA. The yearly penalty would be capped at 10% of the yearly amount required under the PPA.

As a result of the above mentioned agreement, AES incorporated a new controlled company (“Central Termoelectrica Guillermo Brown S.A.”) that will manage the construction of a new 300MW power plant to be located in the south of the Province of Buenos Aires. During 2012, the execution of an EPC agreement with the selected bidder is expected to complete the construction of the new plant by 2013 and to start commercial operations by October 2013.

Brazil

Structure of Electricity Market. In Brazil, there are two contracting environments that regulate PPAs: the Regulated Contracting Environment (“ACR”), for the Generation and Distribution of Electric Power Agents, and the Free Contracting Environment (“ACL”), for the Generation, Commercialization, Importers and Exporters of Energy Power Agents as well as consumers.

This model establishes a number of requirements to be followed by the participants in the industry, such as the obligation for distributors to contract for their market growth years in advance only through regulated auctions; hydro and thermal energy contracting conditions to ensure better balance between supply cost and system stability; and a permanent supply monitoring structure to detect possible imbalances between supply and demand.

 

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Principal Regulators. In Brazil, there are a number of institutions that govern the electricity sector including the Brazilian Electricity Regulatory Agency (“ANEEL”), the National System Operator (“ONS”) and the Electrical Energy Commercialization Chamber (“CCEE”).

ANEEL’s responsibilities are to regulate and inspect production, transmission, distribution and commercialization of electricity in order to assure quality of provided services and universal access. ANEEL is also responsible for the establishment of tariffs for end consumers, in a way that the economic and financial feasibility of power sector participants as Generation, Transmission and Distribution companies and the industry as a whole is preserved. The changes brought about in 2004 by the new model made ANEEL responsible for promoting, directly or indirectly, auctions for the Distribution companies to purchase energy through long-term contracts within the National Interconnected System (Sistema Interligado Nacional) (“SIN”).

The paramount obligations of the CCEE (formerly, the Wholesale Energy Market) include: the determination of the Differences’ Price Settlement (Preço de Liquidação de Diferenças) (“PLD”), or Spot Price, used to value short-term market transactions; the execution of the energy accounting process, identifying who and how much electricity is involved in multilateral short-term market transactions; the financial settlement of the amounts calculated in the energy accounting process; and preparation and execution of energy auctions within the ACR by ANEEL’s delegation process.

Principal Regulations.

Distribution Companies. AES has two distribution businesses in Brazil: AES Eletropaulo and AES Sul. Under the power sector model, distribution companies have to purchase electricity at the regulated market through auctions. Every distribution utility is obligated to contract to meet 100% of its energy needs in the ACR. Self-dealing is no longer allowed; however, existing bilateral contracts are being honored but cannot be renewed. The tariff charged by distribution companies to captive customers is composed of a nonmanageable cost component (“Parcel A”), which includes energy purchase costs and charges related to the use of transmission and distribution systems and is for the most part directly passed through to customers, and a manageable cost component (“Parcel B”), which includes operation and maintenance costs defined by ANEEL, recovery of assets and a component for the value added by the distributor (calculated as the net asset base multiplied by the pre-tax weighted average cost of capital). Parcel B is reset every four years for AES Eletropaulo and every five years for AES Sul. There is an annual tariff adjustment to pass through Parcel A costs to customers and to adjust the Parcel B costs by inflation, less an efficiency factor. Distribution companies could also be entitled to extraordinary tariff revisions in the event of significant changes to their cost structure.

In the first half of 2010, all distribution companies signed amendments to the Concession Contracts, capturing market variance effects over sector charges. AES Eletropaulo signed its amendment on May 3, while AES Sul signed it on April 12.

Generation Companies. AES has two generation businesses in Brazil: AES Tietê and AES Uruguaiana. Under the power sector model, the Ministry of Mines and Energy (“MME”) determines the maximum amount of energy to be sold through contracts by each plant known as “assured energy” or the amount of energy representing the long-term average of the expected energy production of the plant defined by ANEEL.

AES Tietê must provide physical coverage, i.e. its assured energy from its own power generation or purchase contracts to cover 100% of its sales contracts. The failure to provide the required physical coverage and/or present purchase contracts, which is subject to monthly verification, exposes the generation company to the payment of penalties, which could be material. At this time, all of AES Tiete’s assured energy has been sold to AES Eletropaulo. The PPA entered into with AES Eletropaulo, which expires on December 31, 2015, and requires that the price of energy sold be adjusted annually based on the Brazilian inflation variation. Before the end of the PPA in 2015, AES Tietê must seek alternatives to the immediate recontracting of its assured energy from 2016 onwards. Existing legislation allows AES Tietê to allocate its energy to the regulated auctions of existing energy, or through bilateral contracts for private clients.

 

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In addition, the State of São Paulo established some conditions to privatize the generation sector in São Paulo state including an obligation for the winners of the bid to increase their generation capacity by 15%, originally to be accomplished by the end of 2007. AES Tietê, as well as other concessionaire generators, was not able to meet this requirement due to regulatory, environmental, hydrological and fuel constraints. Although AES Tietê has addressed the issue with the State of São Paulo in order to make the obligation viable under the new business, regulatory, and sectional reality, in August 2011, the State of São Paulo filed a lawsuit seeking to compel AES Tietê to expand its generation capacity by 15% or pay unspecified damages. In that case, the State of São Paulo sought and received an injunction from the first instance court requiring AES Tietê to present its plan on how it intended to fulfill its obligation to expand its capacity. AES Tietê has appealed the injunction and the matter is ongoing. AES Tietê has developed a 550 MW gas-fired thermal power project called Termo São Paulo in order to meet this obligation of 398 MW in its installed capacity. AES Tietê is also analyzing other wind, thermo and hydro projects in order to expand its generation. Compliance with these rules could have a material impact on the Company.

Environmental Regulations. Electric sector companies are subject to strict federal, state and municipal environmental legislation and regulations, relating to atmospheric emissions and specially protected areas. Such companies depend on permits and authorizations from government bodies in order to conduct their activities. In the event of a violation or noncompliance with such laws, regulations, permits and authorizations, the company may suffer administrative sanctions such as fines, shutdown of activities, as well as revocations or invalidations of its permits and authorizations. In addition, the Public Prosecutor’s Office may initiate both civil and criminal investigations and lawsuits against a company and its agents that are not in compliance with such laws, regulations, permits and authorizations, which may result in indemnities and penalties. In addition, government agencies and other public authorities may delay the issuance of permits and necessary authorizations for the development of power companies causing project implementation delays and, consequently, unfavorable effects in the companies’ businesses and results. Any such action by the government agencies may negatively affect businesses in the power sector and have adverse effects on the business and results of the companies, including our subsidiaries in Brazil.

In 2011, a new Forestry Code bill was submitted to the Brazilian Congress for approval. The Forestry Code bill provides for new rules regarding the use of the land and forests, such as the maximum extension of specially protected areas and the dismissal to reserve a specific area to be permanently preserved for generation companies. The impact of the new rule on the energy sector depends on the final drafting of the bill which is currently under discussion.

Material Regulatory Actions. On May 16, 2002, ANEEL issued Order #288, a regulation that established the retroactive denial of the choice of not participating in the “exposition relief mechanism,” a mechanism that allowed the sale of energy from Itaipu Generating Co. in the spot market. Due to its negative impact, AES Sul filed a lawsuit seeking the annulment of Order #288. For a further discussion of this dispute see Item 3.—Legal Proceedings in this Form 10-K.

Potential or Proposed Regulations. AES Sul’s third tariff reset process will occur in 2013. AES Eletropaulo’s tariff reset contractual date was originally in July 2011, but due to ANEEL’s delay in defining third cycle methodology, the process was postponed to 2012. AES Eletropaulo’s new tariffs, arising from the tariff reset process, will produce retroactive effects on revenues as of July 4, 2011. Based on the best available information currently available, AES Eletropaulo has recorded a regulatory liability of $190 million related to effects from July 2011 to December 2011. However, the ultimate impact on AES Eletropaulo’s results will not be determined until the methodology regarding the third cycle of tariff reset is fully defined, disclosed and applied to AES Eletropaulo and the regulatory asset base for AES Eletropaulo is approved by ANEEL. It is possible that the final methodology may be less favorable than we anticipate, which could have a material adverse effect on our results of operations.

 

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Cameroon

Structure of Electricity Market. Our subsidiaries in Cameroon are involved in the generation, transmission, distribution and sale of electricity through AES SONEL, Dibamba Power Development Company (“DPDC”) and Kribi Power Development Company (“KPDC”). AES SONEL is an integrated utility that operates approximately 930 MW of generation capacity, two interconnected transmission networks and distributes electricity to approximately 700,000 customers under a 20-year concession agreement that was signed in July 2001. AES SONEL has the exclusive distribution rights to all medium voltage and low voltage customers, except for customers with an installed capacity of more than 1 MW (“Major Customers”) who are free to negotiate bilateral agreements. Generation in Cameroon is open to competition and our subsidiary, DPDC, developed, built and is currently operating an 86 MW heavy fuel oil power plant near Douala as an IPP, which provides power to AES SONEL under a tolling agreement. In order to meet increasing demand for power, the government is developing the Lom Pangar Dam project on the Sanaga River, which will increase the flow of the Sanaga River and increase the generation capacity of the two major hydroelectric power plants currently operated by AES SONEL. The Lom Pangar Dam will also generate 50 MW. Another AES subsidiary, KPDC, is currently building a 216 MW gas-fired power plant in Kribi as another IPP, which will provide power to AES SONEL under a power purchase agreement.

Under its Concession Agreement, AES SONEL operates the two interconnected transmission networks in the country: the Southern Grid with a length of 1550 km and the Northern Grid with a length of 665 km. Major customers, distributors, or vendors can access the grid subject to paying a fee. Sales to low voltage and medium voltage customers are subject to tariff levels agreed to between AES SONEL and the regulator based on the framework established in the AES SONEL Concession Agreement. Management of energy flow on the transmission network is currently undertaken by AES SONEL. Under the concession requirements, AES SONEL will be required to create a separate legal entity under which the transmission system will operate. Under the current regulation, such entity is deemed to be a wholly-owned subsidiary of AES SONEL whose share capital will be opened up to other operators in the sector in accordance with procedures to be approved by the regulator.

Principal Regulators. Cameroon’s electricity regulatory agency, ARSEL, has functional and decision-making autonomy, and is run by a Board of Directors and a General Manager assisted by a Deputy General Manager. Its financing is provided by the state budget and fees collected from revenues generated from activities carried out by operators of the sectors concerned. ARSEL’s decisions are highly influenced by the government via the Ministry of Power, the Prime Minister’s Office and the General Secretariat of the Presidency of the Republic. The Ministry of Energy and Water is the Ministry mandated to issue specific regulations relating to the electricity sector and to issue the concessions, licenses and authorizations to be granted to the operators in the sector.

Principal Regulations. The principal legislative instrument governing the power sector is Law No. 2011/022 of December 14, 2011, which sets out a new institutional framework for the Power Sector and lays the foundation for competition in the power market in Cameroon. It is supplemented by the following instruments:

 

   

Decree No. 2000/464/PM of June 30, 2000, governing the activities of the power sector;

 

   

Decree No. 2001/021/PM of January 29, 2001, setting out the rates and methods of calculation, collection and distribution of the fees payable by operators involved in the power sector;

 

   

Ministerial Order No. 061/CAB/MINMEE of January 30, 2001, setting out the documents and fees required in applying for concessions, licenses, authorizations and declarations for the generation, transmission, distribution, export and sale of power;

 

   

Ministerial Order No. 000013/MINMEE of January 26, 2009, approving the regulation of the public distribution of electricity in Cameroon; and

 

   

Concession Agreements and licenses agreements between the Republic of Cameroon and AES SONEL signed on July 18, 2001 and amended in 2006.

 

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Material Regulatory Issues. A tariff compensation agreement between AES Sonel and the Republic of Cameroon was signed in November 2010. Abiding by the agreement, approximately $36 million of compensation was owed by the Republic of Cameroon to AES Sonel in December 2011 and an initial payment of approximately $11 million was paid at that time. Further payments are scheduled for the first quarter of 2012. Agreement with the Regulator on the tariff mechanism for 2012 was reached in December 2011. The tariff reset is expected to be finalized by the end of January 2012.

The new Electricity Law promulgated in December 2011 established a Transmission Network Organization in the form of a Public Liability Company. The law indicates that this organization’s “missions, organization and functioning shall be laid down by decree of the President of the Republic.” It is not yet clear when the Presidential Decree will be issued. It is also unclear whether the new entity will operate the system, or operate, maintain and develop the system. In either case, this entity could possibly take responsibility for transmission activity and management of the transmission grid away from AES SONEL. The impact on AES is not known at this time; however, it could be material to our results of operations.

Environmental Regulations. The principal environmental regulation is derived from Law No. 96/12 of August 5, 1996 and various implementing decrees and ministerial orders. This regulation applies to all sectors but there are some specific requirements relating to the electricity sector. The main requirement of this regulation for our subsidiaries in Cameroon is the obligation to conduct an environmental impact analysis for the planned construction of new generation installations, new transmission lines or substations.

Potential or Proposed Regulations. There are other generation projects whose regulatory specifications have yet to be clearly determined. The regulatory framework relating to the development of this new capacity and to the future contractual relationship between these new projects and AES SONEL is still unclear. However, the tariff compensation agreement referred to above provides that additional costs imposed on AES SONEL with regard to these projects shall be fully passed through in tariffs charged to end-users.

Chile

Structure of Electricity Market. In Chile, except for the small isolated systems of Aysén and Punta Arenas, generation activities are principally in two electric grids: the Central Interconnected Grid (“SIC”), which supplies approximately 92% of the country’s population; and the Northern Interconnected Grid (“SING”), in which the principal users are mining and industrial companies. Power generation is based primarily on long-term contracts between generation companies and their customers specifying the volume, price and conditions for the sale of energy and capacity. The law recognizes two types of customers for generation companies: unregulated customers and regulated customers. Unregulated customers are principally consumers whose connected capacity is higher than 2 MW and consumers whose connected capacity is between 500 kW and 2 MW who have selected the unregulated pricing mechanism for a period of four years. These customers are not subject to price regulation and are able to freely negotiate prices and conditions for electricity supply with generation and distribution companies. Regulated customers are those whose connected capacity is less than or equal to 500 kW and those with connected capacity between 500 kW and 2 MW who have selected, also for four years, the regulated pricing system.

Electricity generation in each of the SIC and the SING is coordinated by the respective independent Economic Load Dispatch Center (“CDEC”) in order to minimize operational costs and ensure the highest economic efficiency of the system, while fulfilling all quality of service and reliability requirements established by current regulations. In order to satisfy demand at the lowest possible cost at all times, each CDEC orders the dispatch of generation plants based strictly on variable generation costs, starting with the lowest variable cost, and does so independently of the contracts held by each generation company. Thus, while the generation companies are free to enter into supply contracts with their customers and are obligated to comply with such contracts, the energy needed to satisfy demand is always produced by the CDEC members whose variable production costs are lower than the system’s marginal cost at the time of dispatch. For this reason, in each hour a

 

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given generator is either a net supplier to the system or a net buyer. Net buyers pay net suppliers for energy at the system’s marginal cost. In addition, the Chilean market is designed to include payments for capacity (or firm capacity), which are explicitly paid to generation companies for contributing to the system’s sufficiency. The cost of investment and operation of transmission systems is paid for by generation companies and consumers (regulated tolls) in proportion to their use.

Principal Regulators. The Chilean Ministry of Energy, created in 2010, grants concessions for the provision of the public service of electric distribution and the National Commission for the Environment administers the system for evaluating the environmental impact of projects. Thermoelectric plants do not require electrical concession agreements from the government in order to be built or to operate. The Ministry of Energy works with several agencies related to energy issues, such as the National Energy Commission (“NEC”), the Electricity and Fuels Superintendent, Energy Efficiency Agency and the Chilean Nuclear Commission, among others, in order to coordinate energy affairs. The NEC establishes, regulates and coordinates energy policy. The Superintendent of Electricity and Fuels oversees compliance with service quality and safety regulations. The General Water Authority issues the rights to use water for hydroelectric generation plants. The Chilean electrical system includes a Panel of Experts—an independent technical agency whose purpose is to analyze and resolve in a timely fashion conflicts arising between companies within the electric sector and among one or more of these companies and the energy regulators. In addition, the Ministry of Environment is responsible for the development and implementation of environmental regulations, protection of the environment, environmental education and pollution control, among others.

Principal Regulations. The distinct electricity sector activities are regulated by the General Electricity Services Law. Sector activities are also governed by the corresponding technical regulations and standards. The keystones of electricity regulation include: (i) the regulated compulsory marginal cost dispatch based on audited variable costs; (ii) the contract-based wholesale generation market; (iii) an open-access regime for transmission with benchmark regulation for existing transmission lines and auctions for new transmission facilities; (iv) benchmark regulation for the distribution grid; and (v) electricity retailing by distribution companies in their exclusive concession areas.

In accordance with the law, new contracts assigned by distribution companies for energy consumption must be awarded to generation companies based on the lowest supply price offered in public bid processes. These prices, called “long-term node prices,” include indexation formulas and are valid for the entire term of the contract, up to a maximum of 15 years. More precisely, the long-term energy node price for a particular contract is the lowest energy price offered by the generation companies participating in each respective bid process, while the long-term capacity node price is that set in the node price decree in effect at the time of the bid.

In August 2011, President Sebástian Piñera’s administration extended the energy decree that enables the government to take preventive measures to reduce the risk of future energy shortages in the SIC. At present, Chile is experiencing a significant drought that has diminished the country’s reservoir levels and hydroelectric power capacity in the SIC. The decree will remain in force until April 2012 and includes three main actions: (i) diminishing available voltage by 10%-12.5%; (ii) saving reservoir capacity for up to 500 GWh; and (iii) offering incentives for consumers to save electricity. The decree is not expected to have a material impact on AES Gener’s results.

Environmental Regulations. Law 20,257, enacted in April 2008, promotes nonconventional renewable energy sources, such as solar, wind, small hydroelectric and biomass energy sources. This law requires every electricity generator to supply a certain portion of its total contractual obligations to supply electricity with nonconventional renewable energy (“NCRE”). The required amount is determined based on contract agreements executed after August 31, 2007. The NCRE requirement is equal to 5% for the period from 2010 through 2014, and thereafter the required percentage increases by 0.5% each year, to a maximum of 10% by 2024. The obligation to supply a required percentage is currently required through 2034. Generation companies are able to meet this requirement by developing their own NCRE generation capacity (wind, solar, biomass, geothermal and

 

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small hydroelectric technology), or purchasing their NCRE supply from qualified generators, purchasing from other generators that generated NCREs in excess of their own requirements during the previous year or by paying the applicable fines for noncompliance.

Our businesses in Chile currently fulfill our NCRE requirements by utilizing our own biomass power plants and by purchasing NCREs generated by other generation companies. To date, we have sold certain water rights to companies that are developing small hydroelectric projects, entering into power purchase agreements with these companies in order to promote development of these projects, while at the same time meeting our own NCRE requirements.

On June 23, 2011, a new regulation on air emission standards for thermoelectric power plants became effective. This regulation provides for stringent limits on emission of particulate matter and gases produced by the combustion of solid and liquid fuels, particularly coal. For existing plants, including those currently under construction, the new limits for particulate matter emission will go into effect by the end of 2013 and the new limits for SO2, NOX and mercury emission will begin to apply in June 2015. In order to comply with the new emission standards, we estimate that AES Gener will have to invest approximately $280 million between 2012 and 2015, including its proportional investment in an equity-method investee, Guacolda. AES Gener is currently in the process of requesting equipment offers in order to determine the exact investment amounts and the timing of each investment.

Potential or Proposed Regulations. A proposed law that would provide new NCRE incentives is under discussion in the Congress. The proposed law increases the requirements of NCRE beginning 2015, such requirements reaching 20% as a percentage of customer demand in 2020. The new requirements would need to be fulfilled with NCRE coming from the same grid (the SIC or the SING) as the electricity it offsets. The NCRE would have to be accredited by the NEC, which may impose fines for noncompliance. The impact to AES Gener is under analysis; however, it will depend on the new size limit of small run-of-river hydroelectric units and if the new requirement is applied to existing power supply contracts, which only include the 10% NCRE component required by the current law. The proposed law, if passed, could result in increased costs or otherwise have a material impact on our results of operations.

In September 2010, the NEC proposed new Ancillary Services (“AS”) standards designed to regulate AS transactions among generators for frequency regulation, spinning reserve, nonoperating reserve and automatic load shedding. AES Gener submitted comments on the proposed standards. AES Gener is assessing the potential impact of this regulation, although an estimate of the impact can only be established when the final regulation is issued. However, if passed, the regulations could result in required investments or other increased costs which could have a material and adverse impact on our results of operations.

In May 2011, the government created a Commission on Electric Power Development (“CADE”), formed by independent specialists in the sector. The administration requested that the CADE review the current problems in the electricity sector. This commission presented its final report in November 2011 with suggestions for distinct electric regulations including: energy policy and institutional framework, penetration of renewables, transmission system expansions, and competition in generation and generation planning. AES Gener expects the government to adopt certain proposals based on the CADE’s recommendations.

Colombia

Structure of Electricity Market. Colombia has one main national interconnected system (the “SIN”). The wholesale market is organized around both bilateral contracts and a mandatory pool and spot market for all generation units larger than 20 MW.

In the spot market, each unit bids its availability and a set price for a 24-hour period. The dispatch is arranged from lowest to highest bid price and the spot price is set by the marginal price. There are two types of customers: unregulated customers and regulated customers. Unregulated customers are consumers whose

 

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maximum capacity consumption is higher than 0.1 MW, or whose energy demand is greater than 55 MWh/month. These customers are not subject to price regulation; therefore, generators or trader companies are able to freely negotiate prices and conditions for electricity supply with them. Regulated customers have their prices determined by means of public tenders.

Electricity generation in the Colombian system is coordinated by the market administrator whose goal is to minimize operational costs while fulfilling all quality-of-service and reliability requirements established by current regulations. In order to satisfy demand at the lowest possible cost at all times, market administrator orders the dispatch of generation plants based on offer price (variable cost plus reliability charge) by merit, starting with the lowest offer price, and does so independent of the contracts held by each generation company. For this reason, in each hour a given generator is either a net supplier to the system or a net buyer. Net buyers pay net suppliers the system’s spot price. In addition, the Colombian market is designed to include reliability payments, which are paid to generation companies for contributing to the system’s sufficiency. The costs of investment and operation of transmission systems are borne by the consumers in proportion to their use.

Principal Regulators. The Ministry of Mines and Energy (“MME”) establishes the energy policies and 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 integration. The Ministry of the Environment (“MMA”) establishes the environmental policies.

The Public Services Superintendence supervises the correct provision of utilities and the Industry and Commerce Superintendence is in charge of sanctioning any anticompetitive practice. Other entities that have an impact on the electric system include the Energy Planning Unit (“UPME”), in charge of planning the electricity and gas system, and the National Development Planning Office (“DNP”), whose main role is to develop a general development plan for the government.

Principal Regulations. The laws of Domiciliary Public Services and the Electricity Law set the institutional arrangement and the general regulatory framework for the electricity sector. The keystones of the electricity regulation are: (i) the dispatch is based on an offer price that represents the variable cost of the plants; (ii) a contract-based wholesale generation market; (iii) an open access regime for transmission with revenue regulated for existent transmission lines and open bids for new lines; (iv) revenue regulated for the distribution grid; and (v) electricity retail can be performed by distribution and/or traders.

The spot market started in July 1995, and in 1996 a capacity payment was introduced for a term of ten years. In December 2006, a regulation was enacted that replaced the capacity charge with the reliability charge and established two implementation periods. The first period consists of a transition period from December 2006 to November 2012 during which the price is equal to $13.045 per MWh and volume is determined based on each plant’s firm energy which is prorated so that the total firm energy level does not exceed system demand. During the second period, which begins on December 2012, the reliability charge will be determined based on the energy price and the volume of offers submitted by market participants bidding for new capacity for the system. The first reliability charge auction was held in May 2008 with the following results: (i) the reliability charge for existing plants for the period between December 2012 and November 2013 will be $13.998 per MWh; (ii) for new plants that won the auction, the charge will be paid for twenty years starting December 2012; and (iii) three new projects won the auction for a total capacity of 430 MW starting in 2012. The new methodology established in 2006 recognized the reliability provide by Chivor’s system and favored the company by increasing the reliability charge by approximately 120%, moving from $18 million in 2006 to almost $40 million in 2007 and is expected to remain at the same amount per year until 2015.

Environmental Regulations. In Colombia, Law 99 created the MMA (Ministry of the Environment) in 1993. This law requires projects that affect the land or impact the environment to obtain a license from the MMA. While regional environmental authorities can issue licenses for generation projects with capacity of less than

 

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100 MW, only the MMA has the authority to issue licenses for the construction of large-scale generation or transmission projects with 100 MW capacity or greater. Chivor initiated operations in 1977 through a water concession, the only environmental requirement at that time. In August 1995, the MMA began requiring hydroelectric plants, including Chivor, to fulfill the requirements of an “Environmental Management Plan,” which serves as an environmental operating permit. Each year, Chivor has to demonstrate to the environmental authorities that the obligations included in such plan are being fulfilled. Additionally, hydroelectric plants must contribute 6% of their gross generation and thermal plants 4% of their gross generation to the area of influence valued at a special tariff defined by CREG. In 2008, MMA issued Resolution 909 that regulates the emission of thermal power plants. This resolution is not expected to affect Chivor because it is a hydroelectric plant, but could affect AES if we decide to acquire or build a thermal plant in Colombia.

Potential or Proposed Regulations. CREG (Regulatory Commission of Electricity and Gas) issued a proposal to create the Organized Regulated Market (“MOR”). The MOR will replace the current bilateral contracts markets (between traders/utilities and generators) by putting in place a centralized auction in which the market administrator buys energy for all regulated customers served by the traders/utilities. The main provisions contained in the proposal are: (i) it is mandatory for all traders/utilities to buy energy at the auction price and it is voluntary for sellers (generators and trade companies) to offer energy in each auction; (ii) there is one single price for the energy sales in the auction; (iii) the auctions are held one year before the actual dispatch and the commitment period of the auction is one year; and (iv) four auctions are to be established per year. Bilateral contracts executed before the beginning of the MOR’s operation will not suffer any change and will remain valid. A definitive resolution will be issued in the first half of 2011.

During 2010, MME (Ministry of Mines and Energy) issued Decree 2730 which intends to solve the potential long-term and/or cyclical unavailability of gas by (i) importing LNG and (ii) establishing strategic storage alternatives. Also, the government presented the basis for the “National Development Plan 2011–2014.” For the electricity sector, the plan mainly focuses on: (i) maintaining stability of the current regulatory framework, supporting the current reliability charge structure, promoting fair competition among technologies and guaranteeing no new taxes to transactions made in the wholesale market; (ii) assuring energy supply for the medium and long term; (iii) enhancing and strengthening the electricity market’s competitiveness in order to maintain investment confidence and convert the electricity system in Colombia into a world class sector; (iv) making the right decisions in the natural gas sector to make it reliable; and (v) promoting institutional improvement guided by transparency, independence and efficiency. Among these initiatives, they are considering reviewing the separation of National Dispatch Center from the Commercial Transactions Administrator and self-regulation initiatives to avoid or minimize interventions in the market by the government. These initiatives also seek to resolve the gas supply problem for thermal plants. Furthermore, the National Development Plan proposal aims to maintain the stability and certainty of the market rules in order to consolidate the investor trust.

As a part of CREG regulatory agenda for 2011, the regulator is planning to review the lessons learned from the dry conditions brought by the 2009-10 “El Niño” phenomenon and issue regulations for these extreme events, permitting players to know in advance the additional reliability measures that the regulator may take under those circumstances. Also, CREG is planning to issue regulations that will strengthen the energy market by improving the spot market guarantees plan, and establish measures to control market power from pivotal agents (agents needed at any cost to fulfill the demand requirements). This last initiative may affect spot prices which could impact our sales not covered by contracts.

Dominican Republic

Structure of Electricity Market. The Dominican Republic has one main interconnected system with approximately 3,000 MW of installed capacity, composed primarily of thermal generation (85%) and hydroelectric power plants. AES Dominicana has 28% share of this capacity (849 MW) and supplies approximately 40% of energy demand through 3 power generators. The regulatory framework in the Dominican Republic consists of: decentralized industry; unbundled generation, transmission and distribution; regulated

 

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prices in monopolistic segments (transmission and distribution); and a competitive wholesale generation market. In accordance with this regulatory structure, all agents and electric generation, transmission and distribution companies must conduct their operations to provide the best service at minimum cost and comply with standards of quality, safety, continuity of services and conservation of the environment.

The wholesale market is composed of the long-term Power Purchase Agreements and the spot market. The wholesale market is based on a marginal market divided in capacity, energy and ancillaries services (frequency regulation, compensation, and reactive power).

The energy market is based on a centralized economic dispatch. The Organismo Coordinador (“OC”) is in charge of planning and supervision of operations through the “Centro del Control del SENI,” which is in charge of real-time dispatch. The dispatch of the thermal units is based on auditable declared variable costs and, for the hydroelectric units, the variable cost is equal to zero, meaning that these units are the first for dispatch and reflect optimal system costs. The spot market relies on competitive bidding based on each generator’s variable costs as a means of providing a merit order for dispatch. Variable cost information is submitted weekly by the generators to the OC, which then determines the merit order for dispatch based on this information.

The capacity market is based on the availability of a power plant to cover the maximum demand during the year with a price that financially covers the fixed cost of a 50 MW gas turbine generation installed in Dominican Republic with a 10% of reserve.

For the sale of electricity under long-term contracts, the regulatory framework establishes that the sale of electricity of a generating company to a distribution company will be done at prices resulting from the competitive procedures of public bidding. These bids are governed by the conditions established by the Superintendency of Electricity (“SIE”) which supervises the bidding and awarding process. With the objective of ensuring that generation prices represent reasonable values in the market, the SIE ensures that the sale of electricity through contracts is not greater than 80% of interconnected electric energy demand, and that the spot market represents a minimum of 20% of the total national consumption of the interconnected system annually. AES Dominicana has 90% of its capacity under long term contracts and is the main generator that provides frequency regulation services.

The electricity tariff applicable to regulated customers is subject to regulation within the concessions of the distribution companies. Electricity end-users are considered customers of public services according to regulations, hence the tariff is set by resolution of the SIE. For clients with demand above 1.2 MW who are classified as unregulated customers, tariffs are unregulated.

Principal Regulators. In order to regulate the electric sector and implement the provisions contained in the General Electricity Law No. 125-01 and its by-law, two regulators are responsible for monitoring and ensuring compliance with the law: the National Energy Commission (“CNE”) and the SIE. All electric companies (generators, transmission and distributors), are subject to and regulated by the General Electricity Law, whether they are of national and/or foreign capital, private and/or public.

In general, CNE’s main responsibilities are to draft and coordinate the legal framework and regulatory legislation; propose and adopt policies and procedures to assure best practices; draft plans to ensure the proper functioning and development of the energy sector and propose them to the Executive Branch; ensure compliance with the law; promote investment decisions in accordance with these plans; and advise the Executive Branch on all matters related to the energy sector. The SIE’s main responsibilities are to develop, ensure compliance with and analyze the structure and level of prices of electricity and to set the rates and tolls subject to regulation. SIE also reviews electricity rate levels requested by companies, monitors and supervises compliance with legal provisions and rules and monitors compliance with the technical procedures governing generation, transmission, distribution and commercialization of electricity. In addition, SIE supervises electric market behavior in order to avoid monopolistic practices and applies penalties and fines in the cases of noncompliance with the laws and regulations.

 

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Principal Regulations. The energy sector regulatory framework in the Dominican Republic is governed primarily by:

 

   

General Electricity Law 125-01, its by-law and its amendment by Law 186-07 constitute the legal framework that regulates all phases related to the production, transmission, distribution and commercialization of electricity, as well as the functions of state agencies created by this law and related to these matters. The regulatory framework in the Dominican electricity market establishes a methodology for calculating the firm capacity for each power generation unit.

 

   

Renewable Energy Incentives Law 57-07 establishes incentives for renewable energy, mainly income tax exemption, import taxes reduction, as well as special operational, technical and commercial treatment. The law applies to hydroelectric generation with a capacity equal to or below 5 MW, wind generation with a capacity less than 50 MW, biomass generation with a capacity less than 80 MW, photovoltaic generation, and thermo-solar generation with a capacity less than 120 MW.

 

   

Hydrocarbons Law 112-00 establishes a tax on consumption of fossil fuels. All fossil fuels including natural gas used to produce electricity have a tax exemption under the law and any change in this regulation does not affect AES Dominicana as a natural gas provider. All agents that use any fossil fuel to produce electricity must file a request to the CNE and the Industry and Commerce Ministry to apply for this exemption.

 

   

Industry and Commerce Ministry periodic resolutions for technical and price regulations for vehicular natural gas use (transportation).

In addition, the Dominican government has directly exercised varying degrees of regulation over the electricity market and AES Dominicana’s businesses in the past, such as involvement in the renegotiation of the existing PPAs, oversight responsibilities of the SENI and environmental controls. No assurance can be given that the Dominican government will not alter regulations in the future in a way that will negatively affect AES Dominicana’s businesses, financial conditions or results of operations.

Environmental Regulations. The main environmental regulations are the General Law on Environment and Natural Resources 64-00 and the Regulation and Licensing Systems Environmental Permits by-law. These regulations provide for centralized environmental planning by the state through the integration of environmental protection and economic development plans in a common approach and policy throughout the sector. Environmental regulation takes the form of permits or environmental licenses, environmental quality standards and environmental reporting. The main regulatory institutions are:

 

   

The Ministry for the Environment and Natural Resources, which is responsible for implementing and designing the policy for the conservation and protection of the environment and natural resources in the Dominican Republic;

 

   

National Council of Environment and Natural Resources, which is the link between the various Ministries of State in charge of evaluating the impact of environmental policies; and

 

   

Deputy Attorney General for the Defense of the Environment and Natural Resources, which is responsible for performing the actions by the State Environmental conflicts environment.

Despite extensive compliance plans in place by each of the entities, it is possible AES Dominicana generating units could fall out of compliance with such environmental standards. Such non-compliance, and resulting penalties or bad publicity might negatively affect the financial results of AES Dominicana. One such penalty could be a requirement that AES Dominicana operates its offending unit below its rated capacity, and such unavailability might affect compliance with obligations under its PPAs. In such a scenario, AES Dominicana might need to make significant investments in environmental-related infrastructure. In addition, the environmental laws and regulations may become more stringent and AES Dominicana might be forced to make certain investments to be compliant with the new standards.

 

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Potential or Proposed Regulations. During the last quarter of 2011 the regulatory agencies, CNE, SIE and OC set up a task force to review some elements of current regulations. The three regulatory proposals being discussed would: (1) modify the spot price cap with a 5% increase; (2) provide compensation to generation companies in situations where variable costs exceed the spot price (making production of electricity uneconomical) to help meet demand and ensure energy security; and (3) modify the regulations related to frequency regulation, under which (a) generators may have to contribute a percentage of available power as frequency margin which may or may not be paid and plants unable to provide the margin will be required to purchase it or (b) higher variable cost units will provide the margin with compensation.

El Salvador

Structure of Electricity Market. The Salvadorean electricity market is composed of a single interconnected system. Under the General Electricity Law (“GEL”), competition was introduced in generation and trading; additional regulations were implemented related to price and quality of service in non-competitive segments such as distribution, transmission, system operation and administration.

The wholesale electricity market is based on a contract market and a spot market. The contract market is further classified into bilateral contracts, which are freely negotiated by electricity generators, distributors, and trading companies, and regulated contracts, which are the product of regulated public bids carried out by the distribution companies under the supervision of the Regulator, Superintendencia General de Electricidad y Telecomunicaciones (“SIGET”). The Spot Market operates on the basis of bids and prices corresponding to increases or decreases of the quantities of electricity established in a scheduled dispatch.

Starting in February 2012, the distribution companies are required to acquire 70% of their forecasted demand through regulated bids. The spot market is structured as a day-ahead market, and transactions are settled on a monthly basis. The Transmission System and Wholesale Market Operating Rules have been amended to convert the wholesale market price-setting mechanism from a competitive bidding process into audited variable production costs and the amendments became effective on August 1, 2011.

Distribution companies are regulated under an incentive system, specifically a Revenue Cap system, whereby the maximum tariff to be charged to the end-users is subject to the approval of SIGET. The components of the electricity tariff are (i) charges for the use of the distribution network (the “Distribution Charge”), (ii) customer service costs (the “Service Charge”) and (iii) average energy price (the “Energy Charge”). Both the Distribution Charge and Service Charge are based on average capital costs as well as operation and maintenance costs of an efficient distribution company. The Distribution Charge and Service Charge are approved by SIGET every five years and have two adjustments: (i) an annual adjustment considering the inflation variation and (ii) an automatic adjustment in April, July and October, provided that the change in inflation is greater than 10%.

Competition is encouraged by the GEL and it provides the end user with the option to acquire its electricity from a distribution company or an electricity trader. The distribution and transmission companies are mandated by the GEL to allow the use of the distribution grid to traders in order to deliver electricity to their customers. The grid access terms, including tariffs, are detailed in a “distribution contract” registered and regulated by SIGET.

Principal Regulators. SIGET is the independent regulatory authority established through the GEL. SIGET’s principal responsibilities and attributions are the approval of Distribution Value Added Charges (“DVA”), enforcement of sector regulation, dispute resolution among market participants, granting concessions for hydroelectric and geothermal projects, among others.

In addition, the National Energy Council (Consejo Nacional de Energia or CNE), formed in 2007, is the policy-making entity, whose board of directors is composed of the Secretaries of Treasury, Economy, Public Works, Environmental and Natural Resources and the Consumer Protection Agency.

 

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Principal Regulations. The electricity sector is governed by the General Electricity Act, the General Electricity Act Regulations, the Transmission System & Wholesale Market Operating Regulations and the general and specific orders issued by SIGET, under its statutory attributions.

Environmental Regulations. The Environment and Natural Resources Act (“ENRA”), enacted in 1998, and the regulation promulgated therein, enacted in 2000, set forth environmental requirements in El Salvador. These statutes empower the Environment and Natural Resources Secretary to set environmental policy, and ENRA establishes a duty of care to the environment and orders the sustainable use of natural resources. Additionally, ENRA sets forth environmental permitting requirements for the handling of certain potentially hazardous or risky materials or performing certain activities in the environment, such as the construction and operation of power plants (except fuel oil) and transmission lines.

Material Regulatory Actions. The Energy Charge has been, under current methodology, adjusted every six months to reflect the spot market price for electricity during the previous six months. However, starting on January 12, 2011, the energy charge has been adjusted quarterly. Presidential Decree 160 was published on December 23, 2010 and went into effect on January 1, 2011. This decree shortens the Energy Charge reset period from six months to three months; the new Energy Charge reset dates will be January 12th, April 12th, July 12th and October 12th each year. The reduction of the Energy Charge reset period reduces the distribution companies’ cash flow exposure before any significant spike in energy prices since the lag between energy revenues and costs has been reduced by half.

Potential or Proposed Regulations. The Regulator, jointly with the Distribution Companies of El Salvador (AES El Salvador and Del Sur) are in the process of reviewing and changing the methodology of the tariffs calculation, and this process will take place during the first quarter of 2012. The outcome of the new methodology will be used to calculate the new tariffs to be applied for the period from 2013 to 2017.

Currently the calculation of the distribution and commercialization charges are carried out by the evaluation/comparison against a model company, which will be replaced by the utilization of a real company (using actual costs instead of modeled costs). The impact of a change in methodology is not known, but it could be material.

Nigeria

Structure of Electricity Market. In Nigeria, the state-owned entity, Power Holding Company of Nigeria (“PHCN”), holds approximately 80% of the electricity market share. Private power generating companies account for the remaining 20%. The private power generating companies, one of which is AES Nigeria Barge Ltd. (“AESNB”), maintain long-term contracts with PHCN, the sole off taker.

All power transmission operations are currently carried out by PHCN. Under new political initiatives and reforms, as provided under the Roadmap for Power Sector Reforms (“the Power Roadmap”), there are indications that 11 distribution companies and six generation companies would be fully privatized while the Transmission Company of Nigeria (“TCN”) would continue to be owned by the government, but managed by the private sector. Currently, all electricity generation is from either gas-fired or hydro power plants. Most assets are owned by state-owned companies, though some private investors have been able to establish IPPs following recent reforms. In addition, the government is developing approximately 4,800 MW of installed capacity intended to be completed by 2013, known as the National Integrated Power Plants (“NIPPs”). The Presidential Task Force on Power has announced its intention to privatize the NIPPs in future rounds of privatization, following completion of construction.

Principal Regulators. The Nigerian Electricity Regulatory Commission (“NERC”) is an independent regulatory agency that was established under the 2005 Reform Act to undertake both the technical and economic regulation of the Nigerian electricity sector. It is responsible for general oversight functions, including the licensing of operators, setting of tariffs and establishing industry standards for future electricity sector development.

 

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Two of the NERC’s key regulatory functions are licensing and tariff regulation. Since AESNB operates under a long-term bilateral agreement with PHCN, it is not subject to the tariff setting process. On the basis of the current reforms embodied in the Power Roadmap, a number of new regulatory and/or other governing bodies will be established to regulate the industry.

Principal Regulations. In March 2005, the Nigerian President signed the Electric Power Sector Reform Bill into law, enabling private companies to participate in transmission and distribution, in addition to electricity generation that had previously been legalized. The government has since separated PHCN into eleven distribution firms, six generating companies, and a transmission company, in preparation for privatization.

Several events, including union opposition, have delayed the privatization indefinitely; however, the current government has put significant emphasis on completing the privatization of the eighteen successor companies of the PHCN in 2012. There are clauses in the AESNB PPA that, upon the effective date of a privatization, require the business to use all reasonable endeavors to obtain and acquire all fuel necessary for the operation of the plant. Additionally, the off-taker will be transferred from PHCN to Lagos State as also stated in the PPA. However, the government has recently set up the Nigerian Bulk Electricity Trader (“NBET”), an entity that is intended to be the off-taker between the generation and distribution companies backed by World Bank Partial Risk Guarantees (“PRGs”). The NEBT is expected to take over the off taker function from PHCN once it becomes fully privatized. No material impact to our operations is expected at this time because of this reform.

The 2005 Reform Act and NERC regulations provides for a generation license to have duration of 10 years, renewable for a further five years. This is in line with a current proposal for a uniform tariff for the power sector, MYTO, which is derived from a building blocks approach that anticipates a cost-reflective outcome, including a capacity and an energy component; financing costs and other key costs (operating costs, depreciation) and key fluctuating costs (fuel costs, foreign exchange, inflation). A total license and uniform tariff duration of 15 years may present challenges to potential investors given that 15 years may be shorter than the useful life of assets and shorter than the tenor of potential long-term debt financing. A new proposal to increase the license duration to 20 years has been proposed, but this issue has not been resolved. Potential inadequate gas supply and transmission constraints, which may pose a risk to continuous generation in the numerous proposed gas generation plants, may be viewed as additional risks by investors.

Panama

Structure of Electricity Market. In Panama, distribution companies are required to contract 100% of their annual power requirements (although they can self-generate up to 15% of their demand). Generators can enter into long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into alternative supply contracts with each other. The terms and contents of PPAs are determined through a competitive bidding process and are governed by the Commercial Rules. Besides the PPA market, generators may buy and sell energy in the spot market. Energy sold in the spot market corresponds to the hourly differences between the actual dispatch of energy by each generator and its contractual commitments to supply energy. The energy spot price is set by the order in which generators are dispatched. The National Dispatch Center (“CND”) ranks generators according to their variable cost (thermal) and water value (hydroelectric), starting with the lowest value, thereby establishing on an hourly basis the merit order in which generators will be dispatched the following day in order to meet expected demand. Concessions granted to distribution companies (15 years and 51% of ownership) will end in October 2013; the regulator will call for a bidding process to sell the majority of the shares of the three distribution companies. It is expected for the three current holders of the share packages: Empresas Publicas de Medellin (Colombia) shareholder in ENSA and Gas Natural Fenosa (Spain) shareholder in EDEMET and EDECHI to participate. The law provides that if a current shareholder offers no less than the highest price offered by any other participants it will retain ownership of the shares.

Principal Regulators. The National Secretary of Energy (“SNE”) was created by Law 52 on July 30, 2008 and reorganized by Law 43 of April 2011 (in which SNE became a Ministry); and has the responsibilities of

 

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planning, investigating, directing, supervising and controlling policies of the energy sector within Panama. With these responsibilities, the Secretariat has defined strategies and policies for the Republic of Panama, which include promoting energy security for the benefit of the population and the country’s development, and proposing laws and regulations to the executive agency that promote the procurement of electrical energy, hydrocarbons and alternative energy in the best conditions for the country.

The regulator of public services, known as the National Authority of Public Services (“ASEP”), was created by Law 26 on January 29, 1996. ASEP is an autonomous agency of the government, with legal responsibility and self-patrimony. ASEP is responsible for the control and oversight of public services, such as potable water, sewerage, electricity, telecommunications and radio and television systems, as well as the transmission and distribution of natural gas utilities and the companies that provide such services. ASEP’s mission is to ensure the efficient provision of the public services, as well as national, technical, commercial, and environmental quality standards.

Principal Regulations. In the Republic of Panama, the electricity sector is regulated by Law No. 6 issued in February 1997 which was subsequently amended several times. The most recent amendment was Law 58 on May 30, 2011. Some notable amendments by Law 58 were: (i) creation of the Rural Electrification Fund, which will be administered by the government to provide service to rural and poor areas of the country; and (ii) obligation of all market participants to contribute up to 1% of their net income before income tax to the Fund. A compilation of Law 6, including all amendments, was issued on September 14, 2011.

Environmental Regulations. ASEP issued Resolution AN No. 3932-Elec on October 22, 2010 related to the security of dams in the electricity sector. The Law became effective on November 9, 2011 but provided for a two month grace period for compliance. This legislation set a number of protocols for modifications of the dam structure, dam operations and reservoirs monitoring during floods, among others. In order to comply with such regulations, our subsidiaries in Panama have conducted an internal review of emergency procedures during flood events and reviewed dam safety requirements, processes and procedures. These requirements, processes and procedures have been submitted to external consultants in order to verify full compliance with the regulations and to advise and update any of our processes and procedures as necessary.

Material Regulatory Actions. By virtue of Resolutions No. 4493 and 4494 of June 7, 2011 ASEP cancelled the Concession Rights for the CHAN 140 project and administratively terminated the CHAN 220 Concession (both Concessions were to become the Changuinola II Project). AES subsidiaries filed two reconsideration actions before the regulator but both were denied. Following the judicial alternatives provided by the Panamanian legal framework, our subsidiaries filed actions for the protection of constitutional guarantees and claims before the Third Chamber of the Supreme Court against both resolutions.

ASEP has started a sanctioning process against certain of our subsidiaries in Panama due to the late payment of the market settlement for the month of August 2011. AES paid the settlement on October 20, 2011 (approximately 15 days late) once it received the over cost payment (due to the previously disclosed Esti tunnel collapse) from the government. The regulator has the legal capacity to issue fines up to $20 million.

Potential or Proposed Regulations. ASEP has made a proposal to modify the regulatory criteria for the design of bids for Financial Rights of Access to Interconnection Capacity (“DFACI”) between Panama and Colombia, which were approved by Resolution 4507 of June 2011. This proposal includes restrictions on generators’ ability to acquire DFACI if their capability to generate exceeds the maximum percentage of electric consumption that the local laws allow them to provide, which could adversely affect our ability to bid for interconnection capacity in the market.

 

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North America

Mexico

Structure of Electricity Market. Mexico has a single national electricity grid (referred to as the “National Interconnected System”), covering nearly all of Mexico’s territory. The only exception is the Baja California peninsula which has its own separate electricity system. Article 27 of the Mexican Constitution reserves the generation, transmission, transformation, distribution and supply of electric power exclusively to the Mexican State for the purpose of providing a “public service.”

Since 1995 the power sector legal framework partially opened to private entities under the following schemes: cogeneration; self supply; IPP exports; and imports for self consumption. Private investments are allowed today in the sectors: transport, storage, and distribution. The Energy Regulatory Commission (“CRE”) is in charge of issuing the permits related to the activities from the power and natural gas sectors that were open to private investment since 1995.

Principal Regulators. The Federal Electricity Commission (“CFE”), by virtue of Article 1 of the Energy Law, is granted sole and exclusive responsibility for providing this public service as it relates to the supply, transmission and distribution of electric power.

Principal Regulations. In 1992, the Energy Law was amended to allow private parties to invest in certain activities in Mexico’s electrical power market, under the assumption that “self-supply” generation of electric power is not considered a public service. These reforms allowed private parties to obtain permits from the Ministry of Energy for (i) generating power for self-supply; (ii) generating power through co-generation processes; (iii) generating power through independent production; (iv) small-scale production; and (v) importing and exporting electrical power. Beneficiaries holding any of the permits contemplated under the Energy Law are required to enter into PPAs with the CFE with regard to all surplus power produced. It is under this basis that AES’ Mérida and TEG/TEP facilities operate. Mérida provides power exclusively to CFE under a long-term contract. TEG/TEP provides the majority of its output to two offtakers under long-term contracts, and can sell any excess or surplus energy produced to CFE at a predetermined day-ahead price.

Environmental Impact. Projects or activities that may disrupt the ecological balance or exceed the limits and conditions established in the applicable laws or the regulations are subject to the conditions established by regulatory authorities to minimize the negative effects on the environment. Our businesses in Mexico must obtain authorization for matters with environmental impacts from the regulatory authorities.

High risk activities are also regulated, even though there is no specific definition for “high risk.” The Mexican Department of the Interior issued two lists defining high risk substances. The criteria used to determine whether an activity is of high risk is based on the characteristics or volume of the substance used. If, in the event of a spill or release of a substance, it is possible to cause an explosion or significantly affect the environment, people or property, such substance will be considered “high risk.” Further, if a project contemplates the use of a compound included in the lists issued by the regulator, in the necessary volumes, the responsible party must present a risk evaluation before the regulator.

Environmental Sanctions. The Attorney General’s Office for the Protection of the Environment is in charge of enforcing environmental legal provisions in Mexico. The sanctions depend on the environmental obligations violated by individuals or corporations, and vary from fines that range from 50 to 50,000 days of minimum wage pay. Additional sanctions may also be imposed, including the annulment of environmental permits and authorizations, partial or total closures of a facility, and administrative arrest.

Mexican Legislation provides that the energy sector is integrated by the electrical and petroleum sectors. Federation is the only one entitled to extract and process fossil fuels, as well as to generate electricity; however, certain exceptions apply.

 

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Renewable Energy. On October 25, 2008, the Renewable Energies and Financing of the Energy Transition Law was approved by the Energy Committee of the Mexican House of Representatives. The law encourages generation and transportation of energy generated by renewable sources, giving certainty and lower costs to provide incentives to participate in the private sector of this field.

In addition, the Federal government’s broad Special Program on Climate Change (“SPECC”) was formally approved. The SPECC provides a program to reduce the effects of climate change. The principal actions proposed to achieve competitive levels, include the gradual substitution of oil for natural gas, stimulating the implementation of cogeneration and other efficiency saving technologies and strongly stimulating the development of renewable energies.

Priority will be given to electricity generation from wind (up to 507 MW installed by 2012), geothermal energy (up to 153 MW installed by 2012), hydroelectric and solar power. The SPECC proposes a joint program between public bodies and private investors in order to increase the amount of electricity generation capacity from renewable sources up to 1,957 MW by 2012.

The SPECC makes it clear that many of its objectives will be achieved through the following normative, economic and market instruments: accessible financing mechanisms; simplification procedures for permitting; facilitation of electrical grid interconnection and transmission contracts; and stimulus for private investment in energy infrastructure. Our businesses in Mexico are still reviewing the impact of these developments on their operations; however, they could be material to the business and results of operations.

United States

Structure of Electricity Market. The United States wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by the U.S. Federal Energy Regulatory Commission (“FERC”), and regional regulation as defined by rules designed and implemented by the Regional Transmission Organizations (“RTOs”), non-profit corporations that operate the regional transmission grid and maintain organized markets for electricity. These rules for the most part govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. The current regulatory framework in the United States is the result of a series of regulatory actions that have taken place over the past several decades, as well as numerous policies adopted by both the federal government and the individual states that encourage competition in wholesale and retail electricity markets.

Principal Regulators. The federal government, through regulations promulgated by FERC, has primary jurisdiction over wholesale electricity markets and transmission services. While there have been numerous federal statutes enacted during the past 34 years, including the Public Utility Regulatory Policy Act of 1978 (“PURPA”), the Energy Policy Act of 1992 (“EPAct 1992”) and the Energy Policy Act of 2005 (“EPAct 2005”), there are two fundamental regulatory initiatives implemented by FERC during that time frame that directly impact our United States businesses:

 

   

FERC approval of market-based rate authority beginning in 1986 for many providers of wholesale generation; and

 

   

FERC issuance of Order #888 in 1996 mandating the functional separation of generation and transmission operations and requiring utilities to provide open access to their transmission systems.

FERC has civil penalty authority over violations of any provision of Part II of the Federal Power Act (“FPA”) which concerns wholesale generation or transmission, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA. This penalty authority was enhanced in EPAct 2005. With this expanded enforcement authority, violations of the FPA and FERC’s regulations could potentially have more serious consequences than in the past.

 

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Pursuant to EPAct 2005, the North America Reliability Corporation (“NERC”) has been certified by FERC as the Electric Reliability Organization (“ERO”) to develop mandatory and enforceable electric system reliability standards applicable throughout the United States to improve the overall reliability of the electric grid. These standards are subject to FERC review and approval. Once approved, the reliability standards may be enforced by FERC independently, or, alternatively, by the ERO and regional reliability organizations with responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation may be assessed for violations of the reliability standards.

Principal Regulations for Generation Businesses. Several of our generation businesses in the United States currently operate as Qualifying Facilities (“QFs”) as defined under PURPA. These businesses entered into long-term contracts with electric utilities that had a mandatory obligation at that time, as specified under PURPA, to purchase power from QFs at the utility’s avoided cost (i.e., the likely costs for both energy and capital investment that would have been incurred by the purchasing utility if that utility had to provide its own generating capacity or purchase it from another source). EPAct 2005 later amended PURPA to provide for the elimination of the mandatory purchase obligation in certain markets, but did so only on a prospective basis. Cogeneration facilities and small power production facilities that meet certain criteria can be QFs. To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility’s total energy output, and must meet certain efficiency standards. To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet certain size criteria.

Our non-QF generation businesses in the United States currently operate as Exempt Wholesale Generators (“EWGs”) as defined under EPAct 1992. These businesses were historically exempt from the Public Utility Holding Company Act of 1935 and are also exempt from the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), and, subject to FERC approval, have the right as public utilities under the FPA to sell power at market-based rates, either directly to the wholesale market or to a third-party offtaker such as a power marketer or utility/industrial customer. Under the FPA and FERC’s regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to FERC that the seller lacks market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. To prevent market manipulation, FERC requires sellers with market-based rate authority to file certain reports, including a triennial updated market power analysis for markets in which they control certain threshold amounts of generation. As part of the acquisition through merger completed in 2011 with DPL Inc., the Company slightly expanded the number of EWGs that it operates. One of DPL Inc.’s subsidiaries was DPL Energy, LLC, which owns about 584 MW of natural gas fired generation located at two sites, one in Ohio and the other in Indiana.

Principal Regulations for Traditional Utility Business. In addition to our generation businesses, we also own IPL, a vertically integrated utility located in Indiana and DP&L, a vertically integrated utility located in Ohio.

A description of the regulatory environment under which each operates is provided below:

Indianapolis Power & Light Company (“IPL”)

As a regulated electric utility, IPL is subject to regulation by the FERC and the Indiana Utility Regulatory Commission (“IURC”). As indicated below, the financial performance of IPL is directly impacted by the outcome of various regulatory proceedings before the IURC and FERC.

IPL is subject to regulation by the IURC with respect to the following: 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 some public utility properties or securities; and certain other matters.

 

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IPL’s tariff rates for electric service to retail customers (basic rates and charges) are set and approved by the IURC after public hearings (“general rate cases”). General rate cases, which have occurred at irregular intervals, involve IPL, consumer advocacy groups, and other interested stakeholders. The last general rate case for IPL was completed in 1995. In addition, pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time it chooses. Such reviews have not been subject to public hearings.

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 (including purchased power costs) consumed from estimated fuel costs embedded in basic rates, subject to certain restrictions on the level of operating income. These billing or crediting mechanisms are referred to as “trackers.” This is significant because fuel and purchased power costs represent a large and volatile portion of IPL’s total costs. 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 certain IURC-approved environmental investments. The trackers allow IPL to recover the cost of qualifying investments, including a return on investment, without the need for a general rate case.

IPL may apply to the IURC for a change in its fuel charge every three months to recover its estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in its basic rates and charges. IPL must present evidence in each fuel adjustment charge (“FAC”) proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power, or both, so as to provide electricity to its retail customers at the lowest cost reasonably possible.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. Additionally, customer refunds may result if IPL’s rolling twelve-month operating income, determined at quarterly measurement dates, exceeds IPL’s authorized annual jurisdictional net operating income and there are no sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve-month jurisdictional net operating income can be offset.

In IPL’s fourteen most recently approved FAC filings (FAC 81 through 94), the IURC found that IPL’s rolling annual jurisdictional retail electric net operating income was lower than the authorized annual jurisdictional net operating income. FAC 94 includes the twelve months ended October 31, 2011. In IPL’s FAC 76 through 80 filings, the IURC found that IPL’s rolling annual jurisdictional retail electric net operating income was greater than the authorized annual jurisdictional net operating income. Because IPL has a cumulative net operating income deficiency, IPL has not been required to make customer refunds in its FAC proceedings. However, IPL has previously offered voluntary credits to its customers to allay concerns raised by the IURC regarding IPL’s level of earnings.

IPL may apply to the IURC for approval of a rate adjustment known as the Environmental Compliance Cost Recovery Adjustment (“ECCRA”) every six months to recover costs to install and/or upgrade Clean Coal Technology (“CCT”) equipment. The total amount of IPL’s CCT equipment approved for ECCRA recovery as of December 31, 2011 was $615 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six month period from September 2011 through February 2012 was $49 million.

In February 2009, an IPL customer filed a complaint claiming IPL’s tree trimming practices were unreasonable and expressed concerns with language contained in IPL’s tariff that addressed IPL’s tree trimming and tree removal rights. Subsequently, the IURC initiated a generic investigation into electric utility tree trimming practices and tariffs in Indiana. In November 2010, the IURC issued an order in the investigation, which imposed additional requirements on the conduct of tree trimming. The order included requirements on utilities to provide advance customer notice and obtain customer consent or additional easements if existing

 

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easements and rights of way are insufficient to permit pruning in accordance with the required industry standards or in the event that a tree would need to have more than 25% of its canopy removed. The order also directed that a rulemaking would be initiated to further address vegetation management practices.

On July 7, 2011, the IURC issued an additional tree trimming order which did not provide the relief IPL was seeking, but clarified utility customer notice requirements and the relationship of the order to property rights and tariff requirements. It also clarified that in cases of emergency or public safety, utilities may, without customer consent, remove more than 25% of a tree or trim beyond existing easement or right of way boundaries to remedy the situation. The IURC is currently in the process of promulgating formal rules to implement the order. IPL and other interested parties are participating in this rulemaking process. It is not possible to predict the outcome of the rulemaking process, but this could adversely impact IPL’s distribution reliability and significantly increase IPL’s vegetation management costs and the costs of defending IPL’s vegetation management program in litigation, which could have a material impact on IPL’s consolidated financial statements.

IPL is a member of the Midwest Independent System Operator, Inc. (“MISO”). The MISO serves as the third-party operator of IPL’s transmission system and runs the day-ahead and real-time energy and ancillary services markets (“ASM”) for its members.

IPL previously transferred functional control of its transmission facilities to the MISO and IPL’s transmission operations were integrated with those of the MISO. IPL’s participation and authority to sell wholesale power at market-based rates are subject to the FERC jurisdiction. Transmission service over IPL’s facilities is now provided through the Midwest ISO’s tariff.

As a member of the MISO, IPL offers its generation and bids its demand into the market on a day ahead basis and settles differences in real-time. The MISO settles energy hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the MISO region. The MISO evaluates the market participants’ energy offers and demand bids optimizing for energy and ancillary services products to economically and reliably dispatch the entire MISO system. The IURC has authorized IPL to recover the fuel portion of its costs from the MISO, including all specifically identifiable ASM costs, through FAC proceedings, and to defer certain operational, administrative and other costs from the MISO and seek recovery in IPL’s next basic rate case proceeding. Total MISO costs deferred by IPL as long-term regulatory assets were $80.4 million and $71.0 million as of December 31, 2011 and December 31, 2010, respectively.

Beginning in 2007, MISO transmission owners including IPL began to share the costs of transmission expansion projects with other transmission owners after such projects were approved by the MISO board of directors. Upon approval by the MISO board of directors the transmission owners must make a good faith effort to build and/or pay for the projects. Costs allocated to IPL for the projects of other transmission owners are collected by the MISO per their tariff.

On July 21, 2011, the FERC issued Order 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC:

 

  (1) requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan;

 

  (2) requires public utility transmission providers to amend their open access transmission tariffs to describe how public policy requirements will be considered in local and regional transmission planning processes;

 

  (3) removes the federal right of first refusal for certain transmission facilities; and

 

  (4) seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

 

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The MISO’s approved tariff in part already complies with Order 1000. However, Order 1000 will result in changes to transmission expansion costs charged to IPL by the MISO. Such changes relate to public policy requirements for transmission expansion within the MISO footprint, such as to comply with renewable mandates of other states within the footprint. These charges are difficult to estimate, but are expected to be material to IPL within a few years; however, it is probable, but not certain, that these costs will be recoverable, subject to IURC approval. Through December 31, 2011, IPL has deferred as a regulatory asset $2.3 million of MISO transmission expansion costs.

In 2004, the IURC initiated an investigation to examine the overall effectiveness of Demand Side Management (“DSM”) programs throughout the State of Indiana and to consider any alternatives to improve DSM performance statewide. On December 9, 2009, the IURC issued a Generic DSM Order that found that electric utilities subject to its jurisdiction must meet an overall goal of annual cost-effective DSM programs that reduce retail kWh sales (as compared to what sales would have been excluding the DSM programs) of 2% per year by 2019 (beginning in 2010 at 0.3% and growing to 2.0% in 2019, and subject to certain adjustments). The IURC also found that all jurisdictional electric utilities have to participate in five initial, statewide core DSM programs, which will be administered by a third party administrator. Consequently, IPL’s DSM spending, both capital and operating, will increase significantly going forward, which will likely reduce IPL’s retail energy sales and the associated revenues.

Prior to the issuance of the Generic DSM Order, IPL filed a petition seeking relief for substantive DSM programs. IPL proposed a DSM plan to be considered in two phases. The first phase (Phase I) sought recovery for traditional-type DSM programs such as residential home weatherization and energy efficiency education programs. The IURC issued an Order in February 2010 that approved the programs included in IPL’s Phase I request. In addition to IPL’s recovery of the direct costs of the DSM program, the Order also included an opportunity for IPL to receive performance based incentives. The second phase (Phase II) sought recovery for “Advanced” DSM programs and was coincident with IPL’s application for a smart grid funding grant from the Department of Energy. The Advanced DSM programs included an Advanced Metering Infrastructure communication backbone as well as two-way meters and home area network devices for certain of IPL’s customers. In February 2010, the IURC issued an Order that approved IPL’s Phase II program, but denied IPL’s request to timely recover its expenditures. Instead, IPL would need to seek recovery of the costs incurred under its Phase II program during its next basic rate case proceeding.

In October 2010, IPL filed a petition with the IURC for approval of its plan to comply with the IURC’s Generic DSM Order. In November 2011, IPL received approval from the IURC for a new three-year DSM budget totaling $63.1 million that includes the opportunity for performance based incentives.

In 2010, IPL was awarded a smart grid investment grant for $20 million as part of its $48.9 million Smart Energy Project (including smart grid technology), which will provide its customers with tools to help them more efficiently use electricity and upgrade IPL’s electric delivery system infrastructure. Under the grant, the U.S. Department of Energy is providing nontaxable reimbursements to IPL for up to $20 million of capitalized costs associated with IPL’s Smart Energy Project. These reimbursements are being accounted for as a reduction of the capitalized Smart Energy Project costs. Through December 31, 2011, IPL has received total grant reimbursements of $13.0 million since the 2010 project inception.

The Dayton Power and Light Company (“DP&L”)

As a regulated electric utility, DP&L is subject to regulation by the FERC and the Public Utilities Commission of Ohio (“PUCO”). Additionally, construction of large generation facilities and high voltage transmission facilities is subject to regulation by the Ohio Power Siting Board. As indicated below, the financial performance of DP&L is directly impacted by the outcome of various regulatory proceedings before the PUCO and FERC.

 

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DP&L is subject to regulation by the PUCO with respect to the following: its distribution services and facilities; the valuation of distribution property; the sale or abandonment of electric generating facilities; the classification of accounts; rates of depreciation on distribution plant; retail rates and charges; reliability of service, compliance with renewable energy portfolio and energy efficiency program requirements, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), and certain other matters. The PUCO also has the authority to consider and approve individually negotiated contracts with customers who meet certain criteria such as job creation, peak demand reduction or energy efficiency programs, or net-metering programs.

DP&L’s historic tariff rates for electric service to retail customers (basic rates and charges) were traditionally set and approved by the PUCO after public hearings (“general rate cases”) that include the participation of consumer advocacy groups and certain customers. The last general rate case for DP&L was decided in 1991 with rates being phased-in over a three year period (1992-1994). Since that time, DP&L has operated under a variety of regulatory arrangements including PUCO-approved stipulations that had the effect of freezing certain components of its rates for specified periods of time while allowing other components to be reset periodically or added. The PUCO has typically permitted stipulations to operate for whatever period is specified within the stipulation, but it retains the authority to review the rates of any Ohio utility at any time it chooses.

Since January 2001, electric customers within Ohio have been permitted to choose to purchase power under a contract with a Competitive Retail Electric Service Provider (“CRES Provider”) or continue to purchase power from their local utility under Standard Service Offer (“SSO”) rates established by tariff. DP&L and other Ohio utilities continue to have the exclusive right to provide delivery service in their state certified territories and DP&L has the obligation to supply retail generation service to customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services. For customers that choose a CRES Provider, the local utility may issue a joint bill and divides the collected revenue between itself and the CRES Provider based on PUCO rules. The PUCO has issued extensive rules on how and when a customer can switch generation suppliers, how the local utility will interact with CRES Providers and customers, including for billing and collection purposes, and which elements of a utility’s rates are “bypassable” (i.e., avoided by a customer that elects a CRES Provider) and which elements are “non-bypassable” (i.e., charged to all customers receiving a distribution service irrespective of what entity provides the retail generation service).

Overall power market prices, as well as government aggregation initiatives within DP&L’s service territory, have led or may lead to the entrance of additional competitors in its service territory. During the year ended December 31, 2011, approximately 13% of customers representing 47% of 2011’s overall energy usage (kWh) within DP&L’s service area had elected to obtain their supply service from CRES Providers. DPL Energy Resources, Inc. (“DPLER”), an affiliated company that is a CRES Provider, has been marketing transmission and generation services to DP&L customers. During 2011, DPLER accounted for approximately 5,731 million kWh and other CRES Providers accounted for about 862 million kWh of the total 6,594 million kWh supplied by CRES Providers within DP&L’s service territory. The volume supplied by DPLER represents 41% of DP&L’s total distribution volume during 2011. The reduction to gross margin in 2011 as a result of customers switching to DPLER and other CRES Providers was approximately $35.4 million and $22.8 million respectively for DPL. DPL currently cannot determine the extent to which customer switching to CRES Providers will occur in the future and the impact this will have on its operations, but any additional switching could have a significant adverse effect on its future results of operations, financial condition and cash flows.

Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering retail generation service to their residence. As of February 1, 2012, two communities have filed at the PUCO to implement opt out government aggregation programs.

Substitute SB 221, an Ohio energy bill, went into effect July 31, 2008. This law required that all Ohio distribution utilities file either an Electric Security Plan (“ESP”) or a Market Rate Offer (“MRO”). An ESP

 

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typically involves establishing a rate structure for SSO that remains relatively fixed for some period of time, but may include trackers or other mechanisms to adjust rates for certain cost changes. Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still owned generation in the state as of July 2008 are required to phase-in the MRO over a period of not less than six years. Both the MRO and ESP option involve a significantly excessive earnings test (“SEET”) based on the earnings of comparable companies with similar business and financial risks. The PUCO has issued extensive regulations under SB 221 addressing the information that must be included in an ESP as well as a MRO, the SEET requirements, corporate separation revisions, rules relating to the recovery of transmission related costs, electric service and safety standards dealing with reliability standards and a statewide line extension policy, and rules relating to advanced energy portfolio standards, renewable energy, peak demand reduction and energy efficiency standards.

In October 2008, DP&L filed an ESP proceeding that was ultimately resolved by stipulation among DP&L, the PUCO Staff, and most interveners (the “ESP Stipulation”). The ESP Stipulation was approved by the PUCO in June 2009. Among other aspects, the ESP Stipulation (i) established rate mechanisms to be in effect from January 1, 2010 until December 31, 2012, including a fuel rider to recover the actual, prudently incurred costs of procuring purchased power and fuel for generation, (ii) continued certain riders including a rate stabilization charge, and an environmental investment charge and (iii) implemented or permitted future filings to implement riders to recover costs associated with its membership in PJM Interconnection, LLC, and for compliance with certain SB 221 requirements such as procurement costs of renewable energy and the implementation of peak demand reduction and energy efficiency programs. The ESP Stipulation clarified that DP&L’s earning will be reviewed under the SEET in 2013 based on 2012 earnings results.

Pursuant to the ESP Stipulation, a fuel rider was implemented that tracks the cost of fuel and purchased power costs for supplying retail generation service to SSO customers. These costs are subject to quarterly adjustments to true up costs against revenues collected. On an annual basis, an outside auditor selected by the PUCO audits DP&L and issues a report regarding DP&L’s contracting practices to acquire fuel and purchased power and its accounting practices that assign the appropriate portion of costs to SSO customers. In the most recent report for calendar year 2010, the outside auditor recommended and DP&L agreed to implement certain changes in operational and accounting practices, removing certain costs from being included in the rate. The current fuel cost tracking mechanism is set to expire at the end of 2012, at the time when the new ESP or MRO regulatory structure is expected to become effective. An audit of calendar year 2011 will occur in 2012. The outcome of that audit cannot be predicted at this time.

Certain PJM-related costs are recovered through riders that assign costs and revenues from PJM monthly bills to SSO customers based on the ratio of SSO customer load and sales volumes to total retail load and total retail and wholesale volumes. Customer switching to CRES Providers decreases DP&L’s SSO customer load and sales volumes and costs. Therefore, increases in customer switching cause more of these PJM-related costs to be excluded from SSO rate recovery. The net charges incurred from PJM that are reflected in SSO rates are trued-up annually.

The ESP Stipulation also provided for recovery of compliance costs for the SB 221 targets relating to advanced energy portfolio standards, renewable energy, peak demand reduction and energy efficiency standards. If any of the SB 221 targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. A partial waiver of the Ohio solar requirement was granted in 2009, and made up in 2010. DP&L fully complied with these requirements in 2010 and expects to be found in full compliance for 2011 when the PUCO reviews DP&L’s compliance in early 2012. Over time, the targets gradually increase for advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. DP&L is unable to predict the ultimate future costs of compliance for these requirements.

In 2012, DP&L is required to propose either a new ESP or an MRO to be effective January 1, 2013. It is expected that there will be a docketed proceeding in which intervener groups will participate along with the

 

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PUCO Staff and the Office of the Ohio Consumers’ Counsel. Under either regulatory structure, SSO rates will be reset and other retail rates may also be reset. DP&L is unable to predict at the present time what approach may be ultimately approved or the specific mechanisms that may be put into effect under either approach. Depending on those mechanisms, market and economic conditions, and other factors outside DP&L’s control, the outcome of this proceeding could be material.

DP&L is a member of the PJM Interconnection, LLC (“PJM”). PJM is a RTO that operates the transmission systems owned by utilities operating in all or parts of Pennsylvania, New Jersey, Maryland, Delaware, D.C., Virginia, Ohio, West Virginia, Kentucky, North Carolina, Tennessee, Indiana and Illinois. Collectively, these utilities serve approximately 58 million people. PJM has an integrated planning process to identify potential needs for additional transmission to be built to avoid future reliability problems. PJM also runs the day-ahead and real-time energy markets, ancillary services market, and forward capacity market for its members. As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC.

DP&L transferred functional control of its transmission facilities to PJM in 2004, and transmission service over DP&L’s facilities is now provided through the PJM Open Access Transmission Tariff (“OATT”).

As a member of PJM, DP&L offers its generation and bids its energy needs into the markets operated by PJM on an hourly basis. DP&L is eligible to sell power to PJM and elsewhere at market-based rates, subject to FERC jurisdiction. PJM settles energy hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market-clearing price that takes into account physical limitations, generation and demand throughout the PJM region. PJM evaluates the market participants’ energy offers and demand bids optimizing for energy products to economically and reliably dispatch the entire PJM system.

PJM operates an organized forward capacity market known as the Reliability Pricing Model (“RPM”). Utilities and other load serving entities are required to demonstrate that they have sufficient generation capacity to serve their retail customers or to purchase such capacity in the periodic RPM auctions. The PJM RPM capacity base residual auction for the 2014/2015 period cleared at a per megawatt price of $126/day for the RTO area encompassing DP&L. The per megawatt prices for the periods 2013/2014, 2012/2013, 2011/2012 and 2010/2011 were $28/day, $16/day, $110/day and $174/day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be affected by congestion as well as by PJM’s business rules relating to bidding for demand response and energy efficiency resources in the RPM capacity auctions. Increases in customer switching may cause more of the RPM capacity costs and revenues to be excluded from the RPM retail rate rider calculation. DP&L cannot predict the outcome of future auctions or customer switching. Additionally, while the most recent auction price has increased, it still is low relative to the actual costs that would be incurred to construct new generation or invest in substantial amounts of capital for environmental compliance. Future RPM auction results could have a material impact on DP&L’s future results of operations, financial condition and cash flows.

Future costs associated with the construction of large transmission facilities within PJM could be significant. DP&L among other interested parties successfully appealed decisions by FERC on how costs of such new facilities would be allocated across PJM. The 7th Circuit rejected FERC’s rationale for allocation and remanded to the FERC for further proceedings. The FERC has not yet issued a final order on remand, and DP&L is unable to predict the ultimate outcome of the proceeding. While the amount of costs assigned to DP&L may vary substantially depending on the final allocation method adopted, the effects are not likely to be material for DP&L financially because the costs are being recovered through a transmission cost recovery rider.

In connection with DP&L and other utilities joining PJM, the FERC ordered utilities to justify transitional charges and payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments from other utilities and market participants. A hearing was held, and an initial

 

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decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010, that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the time frame stated above. DP&L, along with other transmission owners in PJM and the MISO made a compliance filing at FERC on August 19, 2010, that fully demonstrated all payment obligations to and from all parties within PJM and the MISO. Certain aspects of the compliance filing are still under review by the FERC, while others have already been appealed for court reviewDP&L has entered into bilateral settlement agreements with all parties except one to resolve the matter, which by design will be unaffected by the final outcome of these proceedings. The only unsettled claim is a claim of about $18 million that DP&L has against another entity. It is not known how much of that claim will actually be collected or the timing of any such collection. The results of this proceeding are not expected to have a material effect on the results of operations.

NERC is a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, including Critical Infrastructure Protection (“CIP”) reliability standards, across eight reliability regions. An audit of DP&L in 2009 covering the period June 18, 2007, to June 25, 2009, identified five Possible Alleged Violations (“PAVs”) associated with five NERC reliability requirements of various standards. A mitigation plan and settlement was negotiated, including a non-material payment, which was approved on January 21, 2011 by the FERC. In 2010, DP&L self-reported a single CIP violation, for which a mitigation plan and settlement was negotiated and approved by the FERC in 2011, including a nonmaterial payment. DP&L’s next scheduled audit is in December 2012.

Environmental Regulations. See “Environmental and Land Use Regulations” below for a description of the United States Environmental Regulations.

Europe, Middle East & Asia

European Union

Structure of Electricity Market. All European Union (“EU”) member states are required to implement EU legislation, 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 the energy sector, including market liberalization and environmental legislation.

The Company has subsidiaries that operate existing generation businesses in a number of countries which are member states of the EU, including the Czech Republic, Hungary, the Netherlands, Spain and the United Kingdom. The Company also has subsidiaries that are in the process of commissioning a generation plant in Bulgaria. Bulgaria became a member state of the EU as of January 1, 2007.

Principal Regulations. The principles of market liberalization in the EU electricity and gas markets were introduced under the 2003 Electricity and Gas Directives. In 2005, the European Commission (the “Commission”) launched a sector-wide inquiry into the European gas and electricity markets. To tackle the issues identified in the inquiry and to further improve the regulatory framework for energy liberalization, the Commission launched the Third Energy Package in 2007. In the context of the electricity market, the inquiry has to date focused on identifying issues related to price formation in the electricity wholesale markets and the role of long-term agreements as a possible barrier to entry with a view to improving the competitive situation. In January 2007, the Commission published a proposal for a new common energy policy for Europe. In November 2008, the Commission published a nonbinding second Strategic Energy Review aimed at developing the concept of a common European energy policy. It focused mainly on security of supply and infrastructure development. The Strategic Energy Review proposed reviews of the Gas Storage Directive in 2010 and an update of the Oil Stocks Directives.

In October 2008, the Energy Ministers reached political agreement on the “Third Liberalization Package,” which includes five pieces of legislation, Electricity and Gas Directives, Electricity and Gas Regulations and a

 

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Regulation creating a new Agency for the Coordination of Energy Regulators, which will have limited powers to deal with cross-border interconnectors and related issues. This legislation was formally adopted in August 2009 and required implementation on a national level by March 2011.

Environmental Regulations. See “Environmental and Land Use Regulations—International” below for a description of these directives.

Bulgaria

Structure of Electricity Market. The Bulgarian energy sector model allows for trading at regulated prices, at freely negotiated prices between parties or on the organized market. Since an organized market has not evolved yet despite the availability of adequate legislative framework for it, the primary means for wholesale trading is the regulated market, the bilateral transactions market and the Electricity Balancing Mechanism. These arrangements are also supplemented by an imbalance settlement regime.

The Bulgarian power market has evolved from a system where the National Electricity Company (“NEK”), established in November 1991 as a fully state-owned vertically integrated utility, was responsible for the entire cycle of generation, transmission and distribution. After a decade of functioning in this role, NEK was vertically unbundled with a resulting legal separation of generation, transmission and distribution assets into different operating entities. While these structural reforms greatly helped create a competitive electricity sector, there are no actual trading rules to enable the market to operate freely. To ensure accessible customer prices and support to renewable energy supply (“RES”) producers and the highly efficient cogeneration assets, NEK is still acting as single buyer, purchasing the majority of power generated in Bulgaria and then selling the power to distribution companies and to some of the transmission network-connected consumers. NEK also owns the biggest hydro-electric and pump storage generation facilities in Bulgaria.

While the transmission system in Bulgaria remains under NEK’s formal ownership, to comply fully with EU legislation, NEK has spunoff transmission operations (i.e., system operation, balancing market administration and systems’ operation and maintenance) to the Electricity System Operator. The system also allows for regulated third-party access.

Principal Regulators. The State Energy and Water Regulatory Commission (“SEWRC”) established in 1999 is the independent regulator for both the energy and water markets. SEWRC’s key responsibilities are:

 

   

Licensing activities in the electricity, heat and natural gas sectors;

 

   

Regulating electricity, heat and natural gas prices (including those from RES and CHP power sources);

 

   

Regulating interconnection to distribution and transmission networks; and

 

   

Issuing of certificates of origin and green certificates for the electricity produced from RES and co-generation.

Principal Regulations. Bulgaria is at a juncture of adopting legislative packages that cover three key European policy goals—energy independence (Directive 2009/28/EC), environmental sustainability through GHG emission control (Directive 2009/29/EC) and market liberalization (Directive 2009/72/EC). In line with these EU-mandated goals, the government of Bulgaria has set the following key priorities: a 20% reduction of the energy intensity of GDP by 2013 and a 50% reduction by 2020; increased renewables’ share of the total energy consumption to 12% by 2013 and to a minimum of 16% by 2020; and competitive energy market through promoting new generation entry, security of supply, and sustainable development. A key milestone would be a 30% increase of bilateral contracts in the electricity market by 2013.

A key law that sets the stage for the above priorities is the Bulgarian Energy Act developed in 2004 (the “BEA”) with a view to a transparent and predictable regulatory environment to promote further liberalization

 

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through an independent regulatory authority. The BEA creates a framework for viable commercial companies in the sector through more investment, greater autonomy of SERWC and more effective commercial restructuring. The BEA is structured so that the market can shift away from the single-buyer model into a more market-oriented third-party network access model that allows for trading at regulated or freely negotiated prices, as well as at a free market exchange. To be in full compliance with the EU Third Energy Package, the BEA is being amended in order for the electricity market to be fully liberalized under clear regulatory rules and sustainable market mechanisms. Recent amendments to the BEA are making clear the commitment of the government to honoring long-term contracts for power purchasing with generators whose investments have helped upgrade the national asset base.

To help further develop the energy market, the SERWC developed new Trading Rules, adopted in 2010, where generators, consumers and grid operators are organized in balancing groups for the most cost-effective balance between energy supply and consumption. An underlying principle of the Trading Rules will be the presence of a “Day-ahead” market (a departure from the existing practice of weekly notification schedules). Importantly, the Trading Rules will also establish the principles for the Bulgarian power exchange, all in line with the EU’s Third Energy Liberalization legislation.

Environmental Regulations. The main environmental regulations reflect the implementation of EU environmental directives. In January 2007, Bulgaria introduced EU Emissions Trading Scheme (“ETS”) as the main mechanism for meeting Kyoto Protocol GHG reduction commitments. The Bulgarian Environmental Protection Act, amended on September 27, 2005, and all secondary legislation promulgated pursuant to it, have incorporated all EU and Kyoto emission reduction commitments. The Bulgarian National Allocation Plan (“NAP”) allows a total of 42.3 million tonnes of CO2 for the entire volume of fossil fuel-based generation in the country. The AES Galabovo coal-based power plant is permitted by the NAP to generate 80% of its projected generation for 2011 and 2012. The portion of CO2 generation that is not covered by NAP will be billed directly to NEK.

AES-3C Maritza East 1 EOOD (“AES-3C”) expects to receive, in accordance with the NAP its allocation of free emission quota which AES-3C was assured to receive by the Bulgarian Government in 2011. To date, AES-3C has not yet received its free allocations for the emitted volumes. AES-3C believes it is entitled to the allocation or that costs for the allocations if not provided would be borne by contractual third parties. However, if AES-3C does not receive such allocations within its reporting deadline of March 31, 2012, AES-3C may be held responsible for compliance costs in the form of penalties, in addition to the responsibility to purchase, on a free market basis, European Union Allowances for the said volumes, which may be material to the results of its operation. AES-3C is continuing to work with the relevant Bulgarian authorities towards opening its account at the National Registry of Carbon Quota and having free allocations deposited into it.

Bulgaria is also subject to the Large Combustion Plant Directive (2001/80/EC) (“LCPD”), which aims to reduce particulate emission by controlling SO2, NOX and dust from large combustion plants. The LCPD allows for existing plants to opt for exemption from the emission level values, as long as the operator undertakes not to operate for more than 20,000 hours starting from January 1, 2008 and ending no later than December 31, 2015. Major rehabilitation work has been taking place across units of various Bulgarian thermal power plants in the last decade. The rehabilitated Maritza East 2 complex is now fitted with electrical filters for capturing dust and Flue Gas Desulphurisation (“FGD”) units (more than 94% efficiency). The AES Galabovo power plant is equipped with a state-of-the-art wet FGD system that ensures up to 98% of SO2 removal.

Bulgaria is dependent on foreign imports for 70% of its primary fuel sources, which makes exploration of renewable energy sources of paramount importance for the country’s achievement of energy independence and environmental objectives. Bulgaria’s EU-mandated renewable targets have been met mostly by hydroelectric power plants with limited contribution to the fuel mix by wind energy and even less from biomass. The main goal of the Renewable and Alternative Energy Sources and Biofuels Act of 2007 is to encourage generation from and grid interconnection of installations utilizing renewable energy sources.

 

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Material Regulatory Actions. In connection with Bulgaria’s accession into the EU, the European Commission (the “Commission”) has opened an investigation into alleged anticompetitive behavior and possible restrictions of competition in the Bulgarian electricity markets. The current focus of the Commission’s investigation is NEK. As part of its investigation, the Commission is attempting to determine whether NEK’s long-term contracts are anticompetitive, including its long-term PPAs with AES’ Bulgarian entities, AES Maritza and AES Geo Energy. Accordingly, the Commission has issued separate information requests to AES Maritza and AES Geo Energy about their respective PPAs with NEK. While these particular requests were voluntary, both AES Maritza and AES Geo Energy have cooperated in good faith with the Commission, have provided the requested information and have met with the Commission in order to provide background and any further required information about the projects. The Commission has clearly specified that neither AES Maritza nor AES Geo Energy were the target of the investigation. We believe the Commission is partly concerned that long-term PPAs could pose a problem with respect to the liberalization of Bulgaria’s electricity markets but we believe that the projects and their respective PPAs did not tie up capacity but created capacity that would not otherwise exist. However, if the Commission determined that PPAs are anticompetitive, they could take actions up to and including termination of the AES Maritza PPA, which could have a material adverse impact on AES Maritza and our results of operations and financial condition.

Potential or Proposed Regulations. The AESB Act referred to above is currently being amended in order to better incorporate the EU principles set forth in Directive 2009/29/EC. Recent draft amendments to the AESB Act ensure predictability for off-take tariffs for wind project investments that have been undertaken in the last several years (including the AES-owned Saint Nikola Wind Farm) as well as create new development opportunities for solar power, including the new solar power projects in the Bulgaria pipeline of AES Solar.

Hungary

Structure of Electricity Market. The Hungarian market has one main interconnected system. The state-owned electricity wholesaler, MVM, is the dominant exporter, importer and wholesaler of electricity. MVM’s affiliated company, MAVIR, is the Hungarian transmission system operator. Currently, Hungary is dependent on energy imports (mainly from Russia) since domestic production only partially covers consumption. The wholesale market is legally liberalized, although it remains dominated by MVM owing to MVM’s access to and control over a significant portion of the Hungarian generating facilities. The spot market is relatively illiquid with trading dominated by over-the-counter or bilateral contracts. Relative to more western parts of Europe, the volumes traded are smaller and typically for shorter durations, although contracts with a duration that is greater than one year are available.

Principal regulators. Magyar Energia Hivatal (“MEH”) is the government entity responsible for regulation of the electricity industry in Hungary. The Ministry of National Development oversees the activities of the MEH.

Principal Regulations. The main regulations in Hungary are those being implemented under EU directives; the adoption of the Hungarian Electricity Act in 2007, which became effective January 1, 2008, was the final legislative step to implement a fully liberalized electricity market. By virtue of the Hungarian Electricity Act, all customers are eligible to choose their electricity supplier. In the competitive market, generators sell capacity to wholesale traders, distribution companies, other generators, electricity traders and eligible customers at an unregulated price.

Environmental Regulations. The main environmental permitting regulation is the Integrated Pollution Prevention Control (“IPPC”). The IPPC Directive is based on several principles, namely (i) an integrated approach to permitting, (ii) Best Available Techniques (“BAT”), (iii) flexibility and (iv) public participation. The integrated approach requires permits to take into account the whole environmental performance of the plant, including, emission to air, water and land, generation of waste, use of raw materials, energy efficiency, noise, prevention of accidents and restoration of the site upon closure. The purpose of the IPPC Directive is to ensure a high level of protection of the environment taken as a whole. The permit conditions including emission limit values must be based on BAT as defined in the IPPC IPPC Directive. To assist the licensing authorities and

 

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companies to determine BAT, the Commission organizes an exchange of information between experts from the EU Member States, industry and environmental organizations. This work is coordinated by the European IPPC Bureau of the Institute for Prospective Technology Studies at the EU Joint Research Centre in Seville, Spain. This results in the adoption and publication by the Commission of the BAT Reference Documents (the “BREFs”). The IPPC Directive contains elements of flexibility by allowing the licensing authorities, in determining permit conditions, to take into account the technical characteristics of the installation, its geographical location and the local environmental conditions. Finally, the Directive ensures that the public has a right to participate in the decision-making process, and to be informed of its consequences, by giving the public access to permit applications in order to provide their opinions, permits, results of the monitoring of releases and the European Pollutant Release and Transfer Register (“E-PRTR”). E-PRTR provides emission data reported by Member States accessible in a public register, which is intended to provide environmental information on major industrial activities. E-PRTR has replaced the previous EU-wide pollutant inventory, the so-called European Pollutant Emission Register.

Material Regulatory Actions. Shortly before its accession to the EU, the Hungarian government notified the Commission of arrangements concerning compensation to the state-owned electricity wholesaler MVM. The Commission decided to open a formal investigation in 2005 to determine whether any government subsidies were provided by MVM to its suppliers which were incompatible with the EU’s market. In June 2008, the Commission reached its decision that these PPAs, including AES Tisza’s PPA, contain elements of illegal state aid. The decision required MVM to terminate the PPAs within six months of the June 2008 decision, and to recover the alleged illegal state aid from the generators by April 2009. AES Tisza is challenging the Commission’s decision in the Court of First Instance of the European Communities. Referring to the Commission’s decision, Hungary adopted act number LXX of 2008 which terminates all long-term PPAs in Hungary, including AES Tisza’s PPA, as of December 31, 2008, and requires generators to repay the alleged illegal state aid that was allegedly received by the generators through the PPAs, and provides for the possibility to offset the generators stranded costs from the repayable state aid. The MEH issued its Resolution No. 342/2010 pursuant to which it stated AES Tisza did not receive illegal state aid.

At the end of 2006 and for all of 2007, the Hungarian government reintroduced administrative pricing for all electricity generators, overriding PPA pricing, including the pricing in AES Tisza’s PPA. In January 2007, AES Summit Generation Limited (“AES Summit”), a holding company associated with AES Tisza’s operations in Hungary, and AES Tisza notified the Hungarian government of a dispute concerning its acts and omissions related to AES’ substantial investments in Hungary in connection with the reintroduction of the administrative pricing for Hungarian electricity generators. In conjunction with this, AES Summit and AES Tisza have commenced International Centre for Settlement of Investment Disputes (“ICSID”) arbitration proceedings against Hungary under the Energy Charter Treaty in connection with Hungary’s reintroduction of the administrative pricing for Hungarian electricity generators. In the meantime, pursuant to the new Electricity Act in force from January 1, 2008, administrative pricing for electricity generators was subsequently abolished. The ICSID arbitration panel issued the final determination on September 23, 2010, pursuant to which AES’ claim was dismissed. AES challenged the panel’s decision and requested the annulment thereof.

In 2008, Hungary introduced a special tax to be levied on energy companies including companies such as AES Tisza. The rate of the special tax was 8% and, in 2010, was extended until 2013. Hungary also introduced a further tax on certain industries, including energy companies (the “Crisis Tax”). The rate of the Crisis Tax for energy companies is 1.05% of the net sales revenues.

Kazakhstan

Structure of Electricity Market. In Kazakhstan, the electricity sector is divided into wholesale and retail markets. The wholesale electricity market of Kazakhstan is based on bilateral contracts conducted through an over-the-counter market and KOREM’s centralized trading system. In the retail market, the power distribution and supply functions are unbundled and retail customers with consumption of one MW or more have a right to buy the electricity directly from power plants or retail supply companies.

 

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Principal Regulators. The government of Kazakhstan approves subordinate acts in the power sector (licensing requirement, technical regulations, market rules, tariff methodologies for natural monopolies, etc.) and determines the level of price caps for groups of power plants.

The Ministry of Industry and New Technologies (the “Ministry”) is the central executive body responsible for developing state policy in the power sector and conducting technical regulation. As a part of price cap regulation, the Ministry is responsible for determining groups of power companies for each price cap, annual adjustments of price caps and signing agreements on investment obligations with power plants.

The Agency for Regulation of Natural Monopolies (the “Regulator”) acts as a regulator of industries considered to be “natural monopolies” (transmission and distribution of oil, gas, electricity and heat, railroads, airports, etc.). In the power industry, the Regulator is responsible for the approval of tariffs for heat generation, distribution and supply, electricity transmission and distribution, as well as end-user tariffs for dominant companies in the retail power market. The Regulator grants different licenses in the power sector such as licenses for generation, distribution and retail activities.

The Agency for Protection of Competition (the “AZK”) monitors power market participants to determine entities with a dominant position and detect violations of antimonopoly legislation.

The Ministry of Environmental Protection (the “Environmental Ministry”) is responsible for environmental policy, grants emission permits and evaluates the environmental impact of new projects.

JSC KEGOC is a state-owned electricity transmission company, which also acts as the system operator with a central dispatch management function and as the operator of the balancing market.

Principal Regulations. The following major laws and regulations govern the electricity industry:

 

   

Law “On the Power Industry” (the “Kazakhstan Electricity law”);

 

   

Law “On Natural Monopolies and Regulated Markets”;

 

   

Law “On Competition”;

 

   

Law “On Supporting the Use of Renewable Energy Sources”;

 

   

Environmental Code;

 

   

Law “On Licensing”;

 

   

Resolution of the Government of the Republic of Kazakhstan “On Approval of the Price Caps”; and

 

   

The state program of power industry development in 2010-2014.

Continuous changes in the law and regulations result in contradictions between different laws and regulations. This in turn results in an uncertain regulatory environment in the power sector.

The key elements of price cap regulation of power plants are as follows: (i) the Ministry has determined the power plant grouping based on the plant type, equipment, fuel and distance from coal mines (thirteen groups of power plants were defined); (ii) the Ministry has proposed to the government the price cap for each group based on actual prices in 2008 and the level of investment required, and the government has approved price caps for each group of power plants for the seven-year period from 2009-2015; (iii) the Ministry may propose to the government additional annual adjustments to price caps to reflect inflation and investment requirements within any group or a power plant may apply for an individual investment tariff to the Ministry and the Regulator; (iv) a power plant determines its investment obligations at its own discretion and signs an agreement with the Ministry on investment obligations; and (v) the price cap and individual investment tariff regime do not constitute a price guarantee and power plants should sell to consumers at the competitive market price but not higher than their group price cap or an individual investment tariff. Only exports of power and sale of ten percent of generation

 

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through a centralized trading system are exempt from this restriction. Power trading activities are restricted and power plants are allowed to conduct trading activities to provide electricity supply to their consumers during emergency shutdowns.

The Regulator approves and regulates all tariffs for heat generation, transmission and supply, as well as electricity transmission and distribution tariffs on a cost-based methodology. Power trading companies, which the AZK considers dominant entities, must notify the Regulator of any proposed increase in their tariffs and the Regulator has the right to veto such proposed tariff increases. Furthermore, the Regulator has the right to request a decrease in the applicable tariffs.

The AZK determines the borders of electricity markets at its own discretion, which does not correspond with the provisions of the Kazakhstan Electricity Law, and designates entities with dominant market power. The AZK may consider the tariff of a power plant which is in compliance with price cap regulation to be an excessive monopolistic price of a dominant entity and impose sanctions, as happens from time to time to AES’ generating companies.

Environmental regulations. The Environmental Ministry is responsible for environmental policy and environmental regulations. The Environmental Ministry issues environmental permits, sets emission limits and organizes ecological control in the forms of state environmental impact assessments and independent ecological audits. The Environmental Ministry reviews permit applications for power plants and, after conducting the environmental impact assessment, grants environmental permits for industrial waste, air and water discharges for a period of not more than three years. In December 2011, Kazakhstan adopted amendments to the Ecological Code to introduce carbon regulation starting in 2013 to comply with the Kyoto Protocol, which was ratified by Kazakhstan. Carbon regulation will likely impose allocation of carbon quotas and a carbon trading system. In addition, a violation of environmental requirements may lead to criminal liability and fines.

Material Regulatory Actions. In December 2010, the Environmental Ministry refused to sign agreements on investment obligations with AES UK HPP and AES UK CHP for 2011 and has requested to amend the existing agreement on investment obligation from AES Shulbinsk HPP in 2011. The Environmental Ministry has demanded that AES power plants in Kazakhstan undertake an additional obligation to spend all profits in new investment projects. The financial police have started criminal investigations against AES employees on alleged violations of competition law for the use of price caps in the first part of 2009 and during 2011 without signed agreements on investment obligations.

In December 2011, the Environmental Ministry refused to sign agreements on investment obligations for 2012 with AES UK HPP, AES UK CHP and AES Shulbinsk HPP. In addition, the Environmental Ministry proposed to all Kazakhstan power plants and coal mines to consider freezing prices during the first quarter of 2012 due to the upcoming parliament elections. The use of 2012 price caps without signed agreements on investment obligations may lead to further sanctions by the AZK and other state authorities against our businesses.

In November 2011, AES sent notification to the Kazakhstan government regarding the early termination of the management agreement for the power distribution company EK Disco and its affiliate retail company Shygysenergotrade. Transfer of management rights to the Kazakhstan government should be completed within 180 days. AREM has refused to grant the necessary tariff increase to EK Disco and Shygysenergotrade for 2012 owing to the parliamentary election. Both of these companies are major customers of AES power plants, and the change of management control and AREM refusal on tariffs may have a negative effect on our financial results.

The AZK has designated all AES power plants in Kazakhstan as dominant entities in the eastern Kazakhstan and Pavlodar regions. Shygysenergotrade LLP has also been designated by the AZK as a dominant entity in the eastern Kazakhstan retail market. AES has challenged these designations but so far has been unsuccessful in having the designations overturned. The AZK is conducting other investigations into alleged violations by AES businesses in Kazakhstan of antimonopoly legislation such as excessive monopolistic prices and ungrounded refusal to supply

 

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power to certain customers. AES believes that the investigations per se and allegations made by the AZK in the course of investigations are without merits, and AES is vigorously challenging the unfounded actions of the AZK. However, if AES Kazakhstan does not prevail in these proceedings, there could be a material impact on these businesses and our results of operations in 2012. AES has started an arbitration case in the ISCID against Kazakhstan, where fines and sanctions imposed on AES businesses by AZK in previous years are challenged.

Potential or Proposed Regulations. The Ministry plans to introduce a capacity market starting in 2015 to support new investments in generating assets and the draft of the law is under review by the Kazakhstan parliament. The capacity market should replace price cap regulation. The details of the capacity market regulations will be determined by government subordinate acts and may have a material impact on our financial results.

The Ministry and the Regulator have drafted amendments to the Kazakhstan Electricity Law to increase sanctions for any failure to implement the investment program or comply with the price cap regulation. The absence of a signed agreement on investment obligations will limit a power plant’s right to apply tariffs up to the price cap, such that the electricity tariff of a power plant cannot not exceed its 2008 level. It is expected that this regulation will come into force in January 2012. As a result, we may be required to make significant capital investments and to incur other expenses in order to obtain the benefits of the price caps and avoid sanctions.

Turkey

Structure of Electricity Market. The wholesale generation and distribution market in Turkey is primarily a bilateral market dominated by state-owned entities. The state-owned Electricity Generation Company (“EUAS”) and its subsidiaries constitute approximately 24 GW of generation capacity and represent approximately 47% of the market. Private producers (with public offtake) account for another 18%, and auto producers and merchant power plants the remaining 35%. There is an hourly balancing spot market, with prices typically differing from hour to hour, which is growing and has a capacity of 150 Gigawatt hours (“GWh”) of daily trade on average. The automatic price mechanism, which is meant to halt the government subsidization, has been approved and implementation commenced in July 2008. With this mechanism, all major cost items (foreign exchange, gas price increases, and inflation, among others) are expected to be reflected in the tariff. As a result, midterm market wholesale prices are expected to converge to the current spot market prices. Distribution companies can procure 855% of their needs from TETAS and EUAS but can also source up to 15% from other sources. Additionally, eligible customers, using greater than 30 MWh annually, can contract with the private wholesale companies and private power plants. In 2007, Turkey introduced a “renewable feed-in tariff that sets a floor for renewable generation (solar, biomass, geothermal, wind and small-scale hydroelectricity) for the first ten years of operating. The floor is between $73/MWh to $133/MWh depending on the technology and decreed by EMRA each year. AES’ Turkey hydro assets fall under the renewable feed-in tariffs. The Turkish government has also announced plans to privatize all the state-owned generation assets, other than certain large hydroelectric plants.

Principal Regulators. The transmission network is owned and controlled by TEIAS, the State Transmission Company. TETAS, the Wholesale Trading Company, sets wholesale prices based on average procurement costs from EUAS, auto-producers and Build Operate/Build Operate Transfer/Transfer of Operating Rights producers. This wholesale price represents the buying price for 21 distribution companies under the current Transition Period Contracts (“TPC”) which are expected to expire by 2013. Under TEDAS, there were 20 regional distribution companies. In 2006, four of them were privatized and transferred to the new owners in 2008. Another five of them were privatized in 2009 and transferred to the new owners in 2010. In 2010, the remaining ones were tendered and three of them were transferred to new owners in 2011, while the remaining distribution companies are awaiting approval for handover. In 2010, the Turkish Privatization Administration finished the bidding process of all regional distribution companies. Retail electricity prices are calculated and proposed by the distribution companies and then approved by the electricity market regulatory authority, EMRA.

Principal Regulations. Turkish Electricity Market is governed by the following laws: Electricity Market Law—EML (2001), Renewable Energy Law—REL (2005), Energy Efficiency Law—EEL (2007), Nuclear Power Plant Law—NPPL (2007), and Geothermal Law—GL (2007).

 

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Environmental Regulations. Turkey is listed in Annex-I to the United Nations Framework Convention on Climate Change (“UNFCCC”) with special circumstances that place Turkey in a position that is different from other Annex-I Parties. On February 16, 2009, the Turkish President ratified the law concerning Turkey’s accession to the Kyoto Protocol. In parallel to the EU accession process, Turkey enacted Large Combustion Plants Directive in June 2010 which is similar to the EU legislation.

Ukraine

Structure of Electricity Market. The electricity sector in Ukraine is regulated by the National Energy Regulatory Commission (“NERC”). Electricity costs to end-users in Ukraine consist of three main components: (1) the wholesale market tariff is the price at which the distributor purchases energy on the wholesale market, (2) the distribution tariff covers the cost of transporting electricity over the distribution network, and (3) the supply tariff covers the cost of supplying electricity to an end-user. The total cost permitted by the regulator under the distribution and supply tariff each year is referred to as the DVA. The distribution and supply tariffs for all distribution companies in Ukraine are established by the NERC on an annual basis, at which time DVA and electricity distribution volumes in the tariff are adjusted. A change in the DVA methodology was effected at the end of 2007 with respect to the treatment of wages and salaries such that the adjustment for inflation was replaced by an allowance based on the average industrial wage in the country and normative quantity of personnel.

Principal Regulations. In 2006, NERC authorized two 25% increases in end-user tariffs for residential customers. From 2006 through 2011 there have been no further changes in residential end-user tariffs and the tariff covered approximately 30% of real energy costs. In 2011 there were two tariff increases for residential customers with the introduction of two tariff blocks based on consumption level, resulting in 28-30% of real energy cost coverage by residential customers. The wholesale electricity market price increased by 49% in 2008, by 8.5% in 2009, by 18% in 2010, and by 23% in 2011. In the course of 2010-2011, a simultaneous increase in wholesale market price and pressure on the nonresidential end-user tariff growth resulted in the debt to distribution companies by NERC on compensation of losses for supplying energy to residential customers at privileged tariffs.

A comprehensive review of the distribution tariff methodology addressing issues of revaluation of the rate base, operational expenses coverage on tariffs, the rate of return and introduction of regulatory incentives to increase the quality of service was initially expected to take place at the end of 2008. However, since late 2008 and then on an annual basis, NERC has been introducing minimal changes into the tariff methodology to be valid for just one year, including for 2011, setting the rate of return on initial investment at the level of 15% after tax, wages and salaries treatment remaining as per the mechanism introduced in 2007, and material operational expenses subject to indexation by inflation. A similar extension of provisions for 2012 is expected to be approved. Development and approval of a comprehensive methodology are expected to take place during 2012 to be introduced in 2013.

In 2010, the President of Ukraine announced the list of reforms for implementation up through 2014 in all sectors of the economy, including the electric industry. According to such reforms, there are plans to (i) develop new tariff methodology in 2011; (ii) increase tariffs for residential customers; (iii) commence elimination of cross subsidies; (iv) make changes to legislation to improve customers’ payment discipline; (v) privatize state-owned distribution companies and generation companies; and (vi) introduce a new market structure based on bilateral agreements and balancing market, etc. The declared plan of reforms is delayed in implementation.

In 2009, the Supreme Court of Ukraine took a preliminary position affecting distribution companies in the Ukraine, including AES Kievoblenergo and AES Rivneoblenergo, where under it required that certain network commercial losses of power that were previously treated as tax deductible could no longer be treated as such. This position, if maintained, may have a material effect on AES Kievoblenergo and AES Rivneoblenergo. The Company expects that the Supreme Court of Ukraine may clarify its position in the future, and the proceedings in respect to AES Kievoblenergo and AES Rivneoblenergo are not likely to be finally resolved for another several years.

 

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United Kingdom

Structure of Electricity Market. On March 21, 2007, the Electricity (Single Wholesale Market) (Northern Ireland) Order 2007 was enacted, which provided for the introduction and regulation of a single wholesale electricity market (the “SEM”) for Northern Ireland and the Republic of Ireland that began operation in November of 2007. Revenue from the SEM includes a regulated capacity and an energy payment based on the system marginal price. Bidding principles insist bids are cost-reflective and are based on short run marginal cost. Total annual capacity payments are calculated as the product of the annualized fixed cost of a best new entrant peaking plant multiplied by the capacity required to meet the security standard. This accumulated capacity is then distributed on the basis of plant availability throughout the year on a per trading period basis.

Certain generating units (Kilroot GTs 1 and 2 and Ballylumford units 4, CCGT units 10 & 20 and GTs 1 and 2) are contracted under long-term PPAs to NIE Energy Limited terminating on various dates. The CCGT units are subject to extension by NIEE between March 2012 and 2024. All of the PPAs can be cancelled under direction from NIAUR from November 1, 2010 with six months’ notice other than the Ballylumford 10 and 20 units which can be cancelled from April 1, 2012. All other units (Kilroot units K1 and K2 whose PPAs terminated in November 2010, GTs 3 and 4 and Ballylumford units 5 and 6) participate as merchant units in the SEM as described above.

The effect of this on the Northern Ireland units operated as merchant plants in the SEM depends largely on the relative costs of coal and gas. The relevant units receive capacity payments under the SEM.

For the units with PPAs in place, Kilroot and Ballylumford are neutral with respect to the cost of fuel as this is passed through to its PPA counterparty as an element of the payments made to the respective units based on their availability.

Principal Regulators. Kilroot and Ballylumford are located in Northern Ireland, which is part of the United Kingdom, and are subject to regulation by the Northern Ireland Authority for Utility Regulation (“NIAUR”).

Principal Regulations. The principal legislation is The Electricity (Northern Ireland) Order 1992 under which the Generation Licenses of Kilroot and Ballylumford are granted.

Environmental Regulations. The Kilroot and Ballylumford plants operate under permits granted under the Pollution Prevention Control Regulations (NI) 2003.

The Industrial Emissions Directive was approved by the European Parliament on July 7, 2010 and is expected to become law by 2014. This Directive sets stricter limits on the emissions of pollutants such as NOX, SO2 and particulate matter and requires further reductions in such emissions by January 2016. The combined package of the Industrial Emission Directive, National Emissions Ceiling Directive and Best Available Technique requirements forms a Regulatory Framework for all electricity generation from Large Combustion Plants for the period from 2016 onwards, principally comprising coal-fired, gas-fired, oil-fired and biomass-fired plants. The following steps may be required in respect of Kilroot: (i) fit selective catalytic reduction and comply with the new limits by 2023, at which time there may be another review; (ii) opt out and run under a limited life derogation for a maximum of 17,500 hours; and (iii) opt into a Transitional National Plan which shall apply from January 1, 2016 until June 30, 2020, after which point there will be an option to comply with Emission Limit Values or Closure or run for 1500 hours per year.

Currently, the Ballylumford units 4, 5 and 6 (the B Station) are scheduled to close by the end of 2015 under the Large Combustion Plant Directive; however, there is the possibility that these units may be adapted to be compliant under the Industrial Emissions Directive. The exact details will not be known until the Industrial Emissions Directive is implemented.

 

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With regard to the C Station at Ballylumford, gas turbines using light oils and middle distillates as liquid fuels are subject to an emission limit value for NOX of 90mg/Nm3. GT10 (part of the CCGT plant) is currently permitted to 120mg/m3 on distillate. This could mean that possible modifications are required to be able to continue to run distillate as a dual fuel.

There are transitionary arrangements within the Industrial Emissions Directive to allow plants to manage the introduction of the new limits; large combustion plants may have until July 2020 to meet the requirements. Such arrangements appear attractive to AES and would allow the units to operate without substantial capital investment on a restricted load factor until the end of 2020. After 2020, AES would be required to comply with the new emissions limits in order to continue operations.

The Environmental Liability Directive came into force in Northern Ireland on June 24, 2009 and is aimed at the prevention and remedying of environmental damage. An operator will be held financially liable if it carries out certain activities which cause environmental damage, or where there is an imminent threat of such damage, regardless of whether it intended to cause the damage or was negligent. This includes IPPC permitted installations. In practice there should be no change to AES’ operations as a result of the coming into force of the Environmental Liability Directive.

Material Regulatory Actions. NIAUR published two consultation papers in 2011 regarding the cancellation of Generating Unit Agreements (“GUAs”) in place between PPB and certain generators which could impact various long-term PPAs in Northern Ireland including those at Kilroot and Ballylumford The recommendation from these consultation papers was that NIAUR would not cancel any of the remaining GUAs but keep them under review.

Potential or Proposed Regulations. In November 2010, the Council of the EU approved a revised directive on industrial emissions so as to reduce emissions of pollutants that are harmful to the environment and associated with cancer, asthma and acid rain. The industrial emissions directive seeks to prevent and control air, water and soil pollution by industrial installations. It regulates emissions of a wide range of pollutants, including sulfur and nitrogen compounds, dust particles, asbestos and heavy metals. The directive is aimed at improving local air, water and soil quality, not at mitigating the global warming effects of some of these substances. The review integrates seven directives into a single legal framework and provides for a more harmonized and rigorous implementation of emissions limits associated with the best available technology, so-called BAT. Deviations from this standard are only permitted where local and technical characteristics would make compliance disproportionately costly. The recast also tightens emission limits for NOX, SO2 and dust from power plants and large combustion installations in oil refineries and the metal industry. New plants must apply the BAT beginning in 2012, four years earlier than initially proposed. Existing plants have to comply with this standard from 2016, though a transition period is foreseen. Until June 30, 2020, member states may define transitional plans with declining annual caps for NOX, SO2 or dust emissions. Where installations are already scheduled to close by the end of 2023 or operate less than 17,500 hours after 2016, they may not need to upgrade. Member States have two years to explain this Directive.

Middle East & Asia

China

In 2005, the National Development and Reform Commission (“NDRC”) released interim regulations governing on-grid tariffs, along with two other regulations governing transmission and retail tariffs. The On-Grid Tariff Measures specify different rules for the determination of on-grid tariffs before and after the implementation of competitive pricing. Before the implementation of competitive pricing, 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 power generators to cover reasonable costs and to obtain reasonable returns. Such costs were defined to be the average costs in the industry and reasonable returns

 

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will be calculated on the basis of the interest rate of China’s long-term Treasury bond plus certain percentage points. After the establishment of competitive regional power markets, the on-grid tariffs of electricity generation companies which participate in the competitive market shall principally consist of two components: the capacity charge, which is to be determined by the tariff regulatory authority, and the energy charge, which is to be determined by market competition. However, no implementation rules have been issued to introduce the competitive pricing which is still pending as of now. The Retail Tariff Measures aim to reform the various classes of tariff for end-users into three categories: residential electricity, electricity used in agricultural production and electricity used in industry, commerce or for other purposes. The tariff for each category is fixed per voltage class. The tariffs shall be determined with consideration to the fair sharing of the burden, the efficient adjustment of the demand for electricity and the public policy objectives.

In addition to the foregoing tariff-setting mechanism, China’s central government also issued a tariff adjustment policy allowing the on-grid tariffs to be pegged to the fuel price in the case of significant fluctuations in fuel price. Seventy percent of the increase in fuel costs may be passed through in the tariff. The tariffs of coal-fired facilities in China were increased in 2005, 2006, 2008, 2009 and 2011 pursuant to this policy to alleviate the escalation of fuel price; however, such adjustments were obtained from the regulatory authorities only after a time lag and fell short of compensating all businesses for coal price increases in recent years. There was no catch-up tariff adjustment in 2010 pursuant to the foregoing policy.

Pursuant to the “Renewable Energy Law of China,” which came into effect on January 1, 2006, and was amended on December 26, 2009, renewable resources such as wind, solar, biomass, geothermal and hydroelectric power enjoy complete and unrestricted generation and dispatch, and local grid interconnection is mandated to such plants. To implement the Renewable Energy Law, on August 2, 2007, various central government agencies jointly issued the “Temporary Measures for Dispatching Electricity Generated by Energy Conservation Projects”. Under this regulation, power plants are categorized into groups and assigned priority relative to other groups of power plants. The first group is renewable energy power plants, namely wind, hydroelectric, solar, biomass, tidal-wave, geothermal and landfill gas power plants that satisfy certain environmental standards. The second group is nuclear power plants. The third group is power plants using “modern coal” which includes cogeneration power plants, and power plants utilizing residual heat, residual gas, coal-gangue (or waste coal) and coal mine methane. The last three groups are natural gas, conventional coal and oil-fired power plants. As a result, power plants using renewable resources will enjoy priority dispatch over power plants using fossil fuels. The amendment to the Renewable Energy Law requires that the local grid companies (i) abide by the periodic targets developed by the government for the proportion of power to be generated by renewable energy sources as compared to the total electricity generation and (ii) to purchase all electricity generated by renewable resources. This is in line with the requirement that renewable energy power plants enjoy unrestricted generation and dispatch under the Renewable Energy Law, as well as the Chinese government’s policy objective to encourage comprehensive utilization of resources in an energy efficient and environmentally friendly manner.

In 2007, the Chinese government issued a number of rules and procedures that govern the shutdown of small coal or oil-fired power plants. The types of plants to be shut down include: (i) power plants with a capacity under 50 MW, (ii) power plants with a capacity of up to 100 MW which are more than 20 years old, (iii) power plants with a capacity of up to 200 MW whose equipment has reached the end of its useful life, and (iv) power plants that have coal consumption rates that are higher than either 10% above the applicable provincial average or 15% above the national average. The shutdown procedures have been set in place to ensure that certain smaller power plants are appropriately shut down and replaced by larger and more efficient power plants. The purpose of such rules and regulations is in accordance with China’s policy to achieve energy conservation and emissions reductions. China Power International Holdings Ltd., our joint venture partner in Wuhu IV, intended to construct a 2x600 MW coal-fired power plant. According to this policy, and for the ratification, Wuhu V needs to obtain the corresponding closing and shut-down capacity. After consultation among all shareholders of Wuhu IV, the shareholders, including AES, agreed to transfer their respective shares to the owner of Wuhu V and to shut down Wuhu IV. The consideration for the sale of our 25% share in Wuhu IV is RMB 50 million ($7.6 million). The deal achieved financial closing in March 2011. Also per such policy, AES sold our 71% interest in Aixi JV (51

 

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MW coal-fired with CFB boiler) to our local Chinese party at a price of RMB 5.5 million and such transaction financially closed in June 2011.

On July 20, 2009, NDRC issued the “Circular on Refining the Policy for On-Grid Pricing of Wind Power” (“NDRC Price 2009 No. 1906”), which introduces a benchmark system for on-grid tariffs for wind power replacing the existing public bidding and concession model for wind projects. The circular provides that on-grid tariffs for onshore wind power projects approved from August 1, 2009, onward are fixed using a centrally controlled price determination mechanism, while on-grid tariffs for offshore wind projects will be determined separately. Under the circular, China’s onshore area is divided into four different types of wind-power resource regions, and different prices are set for each of these regions ranging from 0.51 yuan/kWh (US cent 7.5/kWh) for wind power in regions with the best wind resources, such as Inner Mongolia, to 0.61 yuan/kWh (US cent 8.9/kWh) for regions with the worst wind resources. According to NDRC, the legislation’s intent is to standardize the wind power price regulation and promote healthy and sustainable development of the wind-power industry. Currently, we do not expect that this newly issued circular will have a material adverse impact on our wind power businesses in China.

India

Structure of Electricity Market. Pursuant to electricity reforms by the Government of India, including enactment of the Electricity Act of India (“EAI”), the electricity market in India is moving toward a multi-buyer, multi-seller system as opposed to the past structure which permitted a single buyer to purchase power from power generators. This legal and regulatory framework provides flexibility in granting electricity regulatory commissions freedom in determining tariffs as well as encouraging competition in the electricity market, albeit with regulatory intervention. Transmission, distribution and trade of electricity remain regulated activities which require licenses from an electricity regulatory commission, unless exempted. Through the new EAI, generation of electricity has been de-licensed to invite more private participation. The Central Government, through the Ministry of Power, is involved in the power sector planning, policy formulation and appointment of central regulators. State governments also have powers to appoint or remove members of the State Regulatory Commissions, in addition to formulation of policy guidelines applicable to state power sector entities. The state governments set up and notify the state load dispatch center, which controls the physical operation of the grid constituents. Under the EAI, the state governments are required to unbundle the State Electricity Boards into separate generation, distribution and transmission companies.

Principal Regulators. India’s power sector is regulated by a two-level regulatory system: at the national level, the Central Electricity Regulatory Commission (“CERC”); and at the state level, the State Electricity Regulatory Commissions (“SERC”) (together the “Regulatory Commissions”). CERC regulates tariffs of generating stations owned by the central government, or those involved in generating in more than one state, and regulating interstate transmission of electricity. SERC regulates intra-state transmission and supply of electricity within each state. While discharging functions under the EAI, regulatory commissions are guided by the National Electricity Policy, the Tariff Policy and the National Electricity Plan and directions on any policy involving public interest issued by the Central Government or state government from time to time. Regulatory Commissions are quasi-judicial authorities entrusted with various functions including determining tariffs, granting licensees and settling disputes between the generating companies and the licensees, and between licensees. An Appellate Tribunal has been set up for appeal against orders of Regulatory Commissions. The Appellate Tribunal has quasi-judicial powers to summon, enforce attendance, require discovery, receive evidence and review decisions. The orders of the Appellate Tribunal are executable as decrees of a civil court and can be challenged in the Supreme Court.

Principal Regulations. In 2003, the government of India enacted the EAI to establish a framework for a multi-seller/multi-buyer model for the electricity industry, introducing significant changes to India’s electricity sector. The EAI is a central unified legislation relating to generation, transmission, distribution, trading and use of electricity that replaced multiple legislations. Pursuant to the EAI, the government of India ratified the

 

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National Electricity Policy in 2005 and the National Tariff Policy in 2006. The policies established deadlines to implement different provisions of the EAI. However, the pace of actual implementation of the reform process is contingent on the respective state governments and SERCs, as electricity is a “concurrent” subject in India’s constitution which has both central and state jurisdictions. There is no license required to set up generation plants under the EAI (except hydroelectric power plants), and generators are allowed to sell to state distribution utilities, traders and open-access consumers. The access to consumers is subject to regulatory provisions on transmission corridor availability and payment of cross-subsidy surcharge.

The Central Government ratified the National Electricity Policy in 2005, which includes the following objectives: access to electricity for all households; availability of power demand to be met by 2012; energy and peaking shortages to be overcome and adequate spinning reserve to be available; supply of reliable and quality power of specified standards, in an efficient, manner and at reasonable rates; per capita availability of electricity to be increased to more than 1,000 units by 2012; financial turnaround and the commercial viability of electricity sector; and the protection of consumers’ interests. The “Policy for Setting up of Mega Power Projects” was ratified by the Ministry of Power in 1995 and has been revised from time to time. Conditions required to be fulfilled by a developer for the grant of Mega Power Project status include a thermal power plant with a capacity of 700 MW or more located in the States of Jammu & Kashmir, the northeastern states of India; a thermal power plant of a capacity of 1,000 MW or more located in States other than those specified above; a hydroelectricity power plant of a capacity of 350 MW or more located in the States of Jammu & Kashmir, the northeastern states of India; or a hydroelectricity power plant of a capacity of 500 MW or more located in states other than those specified above. Mega Power Projects would be required to secure long-term PPAs with distribution companies in accordance with the National Electricity Policy 2005 and the National Tariff Policy 2006, as amended from time to time. Fiscal concessions available to the Mega Power Projects include the import of capital equipment free of customs duty and export benefits are available to domestic bidders for projects under both public and private sectors after meeting certain requirements. Capital goods required for setting up any Mega Power Project qualify for the above fiscal benefits after it is certified that: (i) the power-purchasing states have granted to the Regulatory Commissions full powers to fix tariffs; (ii) the power-purchasing states undertake, in principle, to privatize distribution in all cities in that state which has a population of more than one million, within a period to be fixed by the Ministry of Power; and (iii) the income tax holiday regime as per Section 80-IA of the Income Tax Act, 1961 is also available.

The EAI specifies trading in electricity as a distinct and licensed activity. The license for electricity trading is required to be obtained from the relevant regulatory commission. In 2009, CERC issued regulations for the grant of trading licenses to regulate the interstate trading of electricity. Trading license regulations set out qualifications for the grant of the license including technical and professional qualifications and net worth requirements. Licensees are subject to conditions specifying, among other things, the extent of trading margin, maintenance of records and a requirement to pay a license fee, as specified by CERC. The State Regulatory Commissions have the right to fix a ceiling on trading margins in intrastate trading. Two power exchanges have received licenses from CERC and have started operations. The volume of power trading on the power exchanges is growing but is low as the bulk of power is still traded through long-term bilateral contracts.

Environmental Regulations. Compliance with relevant environmental laws is the responsibility of the occupier or operator of subject facilities. Principal regulations include the “Environment (Protection) Act, 1986” (“EPAct”), an umbrella law under which environmental protection laws are promulgated. The EPAct vests the Government of India with the power to take measures it deems necessary for protecting and improving the quality of the environment and preventing and controlling environmental pollution. This includes rules for the quality of the environment, standards for emission or discharge of environmental pollutants from various sources and inspection of any premises, plant, equipment, machinery, and materials likely to cause pollution. Penalties for violation of the EPAct include fines or imprisonment. “Environment Impact Assessment Notification S.O. 1533(E), 2006” issued under the EPAct and the Environment (Protection) Rules, 1986, mandate prior approval by the Ministry of Environment & Forests or State Environment Impact Assessment Authority for establishing a new project or expansion or modernization of existing projects. Projects that require preparation of an

 

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environment impact assessment report involve public consultation and hearings. Pursuant thereto, the appropriate authority makes an appraisal of the project after a final environment impact assessment report is submitted addressing the questions raised in the public consultation process. The environmental clearance process is comprehensive, involving assessment of pollution indices, impact on wildlife and biodiversity, and socio-cultural impact and impact on surface and ground water conditions. “The Water (Prevention and Control of Pollution) Cess Act, 1977” (the “Water Cess Act”) mandates levy and collection of a tax on water consumed by industries calculated on the basis of the amount of water consumed for any of the purposes specified under the Water Cess Act. “The Air (Prevention and Control of Pollution) Act, 1981” (the “Air Act”) requires an industrial plant to obtain consent of the State Pollution Control Board (“Board”). Similarly, “The Water (Prevention and Control of Pollution) Act, 1974” (the “Water Act”) provides provisions for making an application to the Board for establishing an industry which may cause effluent discharge into water bodies. The Board may impose conditions relating to pollution control equipment to be installed at the facilities. Industrial plants in any air pollution control area are not permitted to discharge emissions/air pollutants in excess of the standards set by the Board. Under the Air Act and the Water Act, the Central Pollution Control Board has powers to specify standards for quality of air, while State Boards have powers to inspect any control equipment, industrial plant or manufacturing process.

Material Regulatory Actions. The Electricity Regulatory Commission (“ERC”) is empowered to determine tariffs for supply of electricity by a generating company to a distribution licensee, transmission of electricity, wheeling of electricity and retail sale of electricity. In case of a shortage of supply of electricity, the ERC may fix the minimum and maximum tariff ceiling for sale or purchase of electricity for a period not exceeding one year to ensure reasonable prices of electricity. While determining tariffs, the ERC follows principles and methodologies specified by the CERC for determination of tariffs, including the principle that generation, transmission, distribution and supply of electricity should be conducted on commercial principles and takes into account factors which encourage competition, efficiency and economical use of resources.

The EAI provides that the ERC will adopt such tariffs determined through a transparent process of bidding in accordance with guidelines issued by the Central Government. The Central Government, through the Ministry of Power, has issued guidelines for competitive bidding and draft documentation (Standard PPAs) for competitively bid projects. Utilities have to obtain approval from regulatory commissions for the quantum of electricity to be procured competitively and for any deviation in the standard documents before initiating the bidding process. The determination of tariffs for a power project depends on the mode of participation in the project. Tariffs may be determined in two ways: (i) based on tariff principles prescribed by CERC, i.e., cost-plus basis consisting of a capacity charge, an energy charge, an unscheduled interchange charge and incentive payments; or (ii) a competitive bidding process where the tariff is purely market based.

The ERC is required to adopt a bid-based tariff, although the “Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by Distribution Licensees, 2005” (“Bidding Guidelines”) permit the bidding authority to accept or reject all price bids received. The Bidding Guidelines recommend bid evaluation on the basis of levelized tariff and include two types of bids: Case I bids, where the location, technology and fuel is not specified by the procurers, i.e., the generating company has the freedom to choose the site, fuel and technology for the power plant; and Case II bids, where the projects are location-specific and fuel-specific. Tariff rates for procurement of electricity by distribution licensees can be for long-term procurement of electricity for a period of seven years and above; or medium-term procurement for a period of up to seven years but exceeding one year. For long-term procurement under tariff bidding guidelines, a two-stage process is adopted for the Case-II bid process including a request for qualification (“RFQ”) and request for proposal (“RFP”) and a single stage process is allowed to be adopted for Case-I bid process combining the RFQ and RFP process. The Case-I bidding process is a “PPA auction” where the procurer seeks to source power competitively, irrespective of the technology or fuel type adopted by the supplier (traders and generators). The Case-II bidding process is a “project auction” where the state or federal government seeks to source a developer through competitive tariff bid by providing basic requirements like land, fuel, water and other permits. The procurer may adopt a single-stage tender process for medium-term procurement, combining the RFQ and RFP processes. Under this route, IPPs can bid at two parameters, i.e., the fixed or capacity charge or the variable or energy charge, which

 

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constitute the fuel cost for the electricity generated. Both the capacity and energy parameters can be bid with non-scalable components. The escalation factors are notified by CERC from time to time. Bidding guidelines include a two-step process—pre-qualification and final bid. Bidders are required to submit a technical and financial bid at the RFP stage. Power purchase and distribution licenses are increasing through the competitive bid route. The Tariff Policy requires all procurement of power after January 6, 2006 (except for PPAs approved or submitted for approval before January 6, 2006 or projects which have obtained financing prior to January 6, 2006) by distribution licensees to be through competitive bidding. However a subsequent notification by the Ministry of Power has extended this deadline up to January 6, 2011. Some state regulators have ratified the purchase of power under memorandums of understanding, on the ground that the tariff policy discussed above is merely indicative and not binding.

Philippines

Structure of Electricity Market. From a vertically integrated industry, the Philippines has unbundled its power sector into generation, transmission, distribution and supply. The enabling law for this restructuring is Republic Act No. 9136, otherwise known as the Electric Power Industry Reform Act of 2001 (“EPIRA”). The EPIRA primarily aims to increase private sector participation in the power sector and to privatize the Government’s generation and transmission assets. Generation and supply are open and competitive sectors, while transmission and distribution are regulated sectors. Sale of power is done primarily thorough medium-term contracts between generation companies and customers specifying the volume, price and conditions for the sale of energy and capacity. The Energy Regulatory Commission (“ERC”) approves the said contracts for supply of energy. Power is also traded in the Wholesale Electricity Spot Market (“WESM”) from which at least 10% of the distribution companies or electricity cooperatives power requirement must be sourced.

A market optimization model determines the price and dispatch by processing the bids from trading participants and the system condition from the system operator. The market operator then comes out with a schedule of both price and energy which maximizes economic gains for participants subject to certain constraints. The dispatch schedule is then coordinated with the system operator for implementation. The market is operating under a gross pool, net settlement system, whereby each generator submits energy offers regardless of their contracted energy. However, the generator should declare their contracted quantities, since the market will not include contracted energy in its settlement.

New contracts assigned by distribution companies for consumption after expiration are awarded to generation companies either through the lowest supply price offered in public bid processes or through a negotiated contract. The ERC then approves the said contract benchmarked against, among others, the prices of the best new entrant generation company.

AES Masinloc has secured a seven year Power Supply Agreement (“PSA”) contract with MERALCO, with a three-year option to extend, MERALCO is the largest distribution company in the Philippines. The contract with MERALCO requires approval by the ERC.

The existing supply contract with MERALCO, under the NPC Transition Supply Contract, was extended for another year and will cease by December 25, 2012. The extension will automatically terminate once the PSA is approved by the ERC or three months after commencement of the Retail Competition and Open Access expected by fourth quarter of 2012.

Except one, the other supply contracts with the Electric Cooperatives were renegotiated and extended for another ten years. The Contract for Supply of Electric Energy (“CSEE”) extensions was already filed with the ERC for approval.

Principal Regulators. The ERC, created under the EPIRA, is mandated to protect long-term consumer interest in terms of quality, reliability and reasonable pricing of sustainable supply of electricity. It is a quasi-judicial body that promulgates and enforces rules, regulations, guidelines and policies. The Department of

 

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Energy is mandated to prepare, integrate, coordinate, supervise and control all plans, programs, projects and activities of the government relative to energy exploration, development, utilization, distribution and conservation. The DOE endorses new or existing generators. The Department of Environment and Natural Resources administers the system for evaluating the environmental impact of new or existing generating plants.

Principal Regulations. The distinct electricity sector activities are regulated by the EPIRA. Sector activities are also governed by the corresponding technical regulations and standards, namely, the Philippine Grid Code, Philippine Distribution Code, Open Access Transmission Service Rules, WESM Rules, and Distribution System Open Access Rules (“DSOAR”).The keystones of the electricity regulation are: (i) performance based on revenue cap and non-discriminatory access to transmission lines; (ii) a contract-based supply and spot electricity trading for generation; (iii) performance based on maximum average price and non-discriminatory access for DUs and ECs under the performance base rate regime; and (iv) electricity supply by distribution companies in their respective franchise areas.

Section 31 of EPIRA establishes the Retail Competition and Open Access (“RC&OA”) under which Retail Electricity Suppliers, who are duly licensed by the ERC, may supply directly to Contestable Customers (end-users with an average demand of at least 1,000 kW) with DUs and ECs providing non-discriminatory wires services. ERC concluded that the pre-conditions for RC&OA had already been satisfied and declared December 26, 2011 as the commencement date under ERC Resolution No. 10 on June 6, 2011. MERALCO, Private Electric Power Operators Association and Philippine Rural Electric Cooperatives Association, Inc., petitioned the ERC to postpone the RC&OA implementation because systems required for RC&OA such as B2B and Accounting, Billing and Settlement will take a longer time to complete. As a result, ERC deferred the implementation of the RC&OA. The new target commencement date is the fourth quarter of 2012.

Environmental Regulations. The Renewable Energy Act of 2008 (“R.A. 9513”) was enacted in December 2008 to promote non-conventional renewable energy sources, such as solar, wind, small hydroelectric and biomass energies. The law requires electric power participants to initially source 10% of their supply from eligible renewable energy resources. The initial requirement of 10% is preliminary, as the National Renewable Energy Board (“NREB”) has not set the final figure. It is unknown at this time if the definition of electric power participant applies to entities that are power producers or to power consumers. If and once the regulations are implemented, our businesses in the Philippines could be adversely impacted by requirements to source a portion of their generation from renewable energy resources to supply its customers’ contracts, which could in turn affect our results of operations. Under Section 6 R.A. 9513, consumers are also given a green energy option which provides end-users the option to choose renewable energy sources as their sources of energy.

Water rights are given by the National Water Resources Board under the Department of Environment and Natural Resource for extraction and discharge of water used in the operation of the Masinloc Plant.

Material Regulatory Actions. Final approval of power contracts signed with MERALCO and the Electric Cooperatives is pending and expected by 2012.

Potential or Proposed Regulations. Section 72 of the EPIRA requires a mandated rate reduction from NPC rates. With the assignment of the Transition Supply Contracts to successor generating companies, such as AES Masinloc, NPC’s position is that the mandated rate reduction shall be for the account of the successor generating companies. AES Masinloc filed a petition with ERC to initiate rule making and clarify the MRR implementation in light of the ongoing privatization of NPC plants. In its decision, the ERC ruled in favor of AES Masinloc, saying that the EPIRA mandated rate reduction shall be implemented by the successor generating company subject to the execution of a written instrument between NPC and the new generator specifically containing the assumption by the latter of such obligation. The ERC ruled in favor of AES Masinloc since there was no such written instrument. NPC filed a petition for review with the Court asking for a reversal of the said ERC decision. The case is pending with the Court of Appeals. If AES Masinloc loses this matter on appeal, it may be subject to the rate reduction described above, which could have a material impact on its business and our results of operations.

 

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A similar mandated rate reduction case is pending with the ERC. MERALCO alleges that AES Masinloc failed to account for the rate reduction in MERALCO’s favor amounting to Php179,611,458.98 ($4.1 million). It is assumed that the ERC will wait for the decision of the first matter described in the preceding paragraph before ruling on the MERALCO case since the latter is particularly dependent on the outcome of the pending petition with the Court of Appeals.

Environmental and Land Use Regulations

Overview. The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air emissions, such as SO2, NOX, particulate matter, mercury and other hazardous air pollutants. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our United States or international subsidiaries, and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors, “Our businesses are subject to stringent environmental laws and regulations,” “Our businesses are subject to enforcement initiatives from environmental regulatory agencies,” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows” in this Form 10-K.

Many of the countries in which the Company does business also have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from electric power generation or distribution assets. In addition, international projects funded by the International Finance Corporation, the private sector lending arm of the World Bank, or many other international lenders are subject to World Bank environmental standards or similar standards, which tend to be more stringent than local country standards. The Company often has used advanced environmental technologies in order to minimize environmental impacts, including circulating fluidized bed (“CFB”) coal technologies, flue gas desulphurization technologies, selective catalytic reduction technologies and advanced gas turbines.

Environmental laws and regulations affecting electric power generation and distribution facilities are complex, change frequently and have become more stringent over time. The Company has incurred and will continue to incur capital costs and other expenditures to comply with these environmental laws and regulations. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Expenditures in this Form 10-K for more detail. The Company and its subsidiaries may be required to make significant capital or other expenditures to comply with these regulations. There can be no assurance that the businesses operated by the subsidiaries of the Company will be able to recover any of these compliance costs from their counterparties or customers such that the Company’s consolidated results of operations, financial condition and cash flows would not be materially 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, capital expenditures, interruptions or changes to our operations. Certain subsidiaries of the Company are subject to litigation or regulatory action relating to environmental permits or approvals. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action, including a Notice of Violation (“NOV”) issued by the United States Environmental Protection Agency against IPL concerning new source review and prevention of significant deterioration issues under the United States Clean Air Act.

Greenhouse Gas Laws, Protocols and Regulations. In 2011, the Company’s subsidiaries operated electric power generation businesses which had total approximate direct CO2 emissions of 74 million metric tonnes, approximately 37.5 million metric tonnes of which were emitted in the United States (both figures ownership

 

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adjusted). The Company uses CO2 emission estimation methodologies supported by the “The Greenhouse Gas Protocol” reporting standard on GHG emissions. For existing power generation plants, CO2 emissions are either obtained directly from plant continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission factors. The following is an overview of both the regulations and laws that currently apply to our businesses and those that may be imposed over the next few years. Such regulations and laws could have a material effect on the electric power generation and distribution businesses of the Company’s subsidiaries and on the Company’s consolidated results of operations, financial condition and cash flows.

International

On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires the industrialized countries that have ratified it to significantly reduce their GHG emissions, including CO2. The vast majority of developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements, including many of the countries in which the Company’s subsidiaries operate. Of the 27 countries in which the Company’s subsidiaries currently operate, all but one—the United States (including Puerto Rico)—have ratified the Kyoto Protocol. To date, compliance with the Kyoto Protocol and the European Union Emissions Trading System has not had a material effect on the Company’s consolidated results of operations, financial condition and cash flows. The first commitment period under the Kyoto Protocol is currently expected to expire at the end of 2012. In December 2011, the annual United Nations conference of the parties to the Kyoto Protocol (“COP 17”) was held in Durban, South Africa to focus on establishing a second commitment period under the Kyoto Protocol or an international agreement or framework to succeed the Kyoto Protocol. COP 17 did not result in any legally binding second commitment period or successor agreement to the Kyoto Protocol, but most of the original signatories to the Kyoto Protocol agreed to extend their GHG emissions reduction commitments under the Kyoto Protocol by at least five years and countries agreed to continue to work toward a successor international agreement on GHG emissions reductions by 2015. At present, the Company cannot predict whether compliance with any successor commitment period under the Kyoto Protocol or any successor agreements will have a material effect on the Company’s consolidated results of operations, financial condition and cash flows in future periods.

In July 2003, the European Community “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. During the first and second trading periods of EU ETS, which commenced in January 2005 and terminates at the end of 2012, Member States were required to implement EC-approved national allocation plans (“NAPs”). Under the NAPs, Member States were responsible for allocating limited CO2 allowances within their borders through 2012. Directive 2003/87/EC did not dictate how these allocations were to be made, and the NAPs that were submitted varied in their allocation methodologies. The current NAPs in each Member State will apply until the end of 2012.

Pursuant to “Directive 2009/29/EC amending European Directive 2003/87/EC so as to improve and extend the greenhouse gas emission allowance trading scheme of the Community,” (the “2009 Amending Directive”), the European Union has announced that it intends to keep the EU ETS in place through the third trading period, which ends in 2020, even if the Kyoto Protocol is not replaced by another agreement. NAPs were required during the first and second trading periods. However, for the third trading period, which begins in 2013, there will no longer be any national allocation plans. Instead, the allocations will be determined directly by the EU.

The Company’s subsidiaries operate seven electric power generation facilities within five member states which have adopted NAPs to implement Directive 2003/87/EC. During the first and second trading periods, achieving and maintaining compliance with the NAPs did not have a material impact on consolidated operations or results of the Company.

The risk and benefit associated with achieving compliance with applicable NAPs at several facilities of the Company’s subsidiaries are not the responsibility of the Company’s subsidiaries, as they are subject to

 

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contractual provisions that transfer the costs associated with compliance to contract counterparties. In connection with any potential dispute that might arise with contract counterparties over these provisions, there can be no assurance that the Company and/or the relevant subsidiary would prevail, or that the failure to prevail in any such dispute will not have a material effect on the Company and its financial condition or consolidated results of operations. Certain of the Company’s subsidiaries will bear some or all of the risk and benefit associated with compliance with applicable NAPs at certain facilities.

The 2009 Amending Directive was adopted by the EU in April 2009 as part of the EU’s “Climate Change Package,” which also included a Carbon Capture & Storage Directive and a revised Renewables Directive. The 2009 Amending Directive provides for the third trading period of the EU ETS, which will apply from the beginning of 2013 until 2020. The key characteristics of the third trading period relevant to the Company are as follows:

 

   

The EU is aiming to reduce EU-wide CO2 emissions by 21% from 2005 levels by 2020.

 

   

A single, EU-wide cap on annual CO2 allowances will be imposed by the European Commission, rather than Member States. This cap will decrease annually.

 

   

Significantly fewer free CO2 allowances will be allocated than during the first and second trading periods, with an increasing number being made available for purchase by auction (50% of all allowances will be auctioned in 2013, compared to 3% in the second trading period).

 

   

Free allocations will be set using a benchmark based on the most efficient installations for each type of product, with very limited allocations for electricity production. In 2013, each installation will receive free allowances equivalent to 80 percent of the benchmark, with the proportion decreasing each year, to 0% by 2027.

 

   

NAPs will be replaced by National Implementing Measures (“NIMs”), which set out the levels of free allocation of allowances to installations in accordance with harmonized EU rules. Member States are required to submit proposed NIMs to the EU, and they will be assessed and approved during 2012.

In addition to the 2009 Amending Directive for the EU ETS, the Renewables Directive was also adopted by the EU in April 2009, and will enter into force in each individual EU Member State upon the adoption by each country of implementing legislation or regulations. The key requirement of the Renewables Directive is a minimum target of 20 percent of all energy generation in the EU to be from renewable sources by 2020.

AES generation businesses in each Member State will be required to comply with the relevant measures taken to implement the directives, including each of the relevant NIMs.

Even though the 2009 Amending Directive means that the EU ETS will remain in place even if the Kyoto Protocol expires at the end of 2012 without any successor commitment period or agreement or other international commitment on GHG emissions reductions, there remains significant uncertainty with respect to the third trading period and the implementation of NIMs post-2012. Although many Member States have submitted draft NIMs to the EU for approval, these NIMs could undergo changes and there is no certainty as to their final form. At this time, the Company cannot determine whether achieving and maintaining compliance with the EU allocation plan for the third trading period, to which its subsidiaries are subject, will have a material impact on its consolidated operations or financial results.

Countries in Latin America, Asia and Africa in which subsidiaries of the Company operate may also choose to adopt regulations that directly or indirectly regulate GHG emissions from power plants. For a discussion of regulations in individual countries where our subsidiaries operate, see Item 1. Business—Regulatory Matters in this Form 10-K. Although the Company does not currently believe that the laws and regulations pertaining to GHG emissions that have been adopted to date in countries in Latin America, Asia and Africa in which subsidiaries of the Company operate will have a material impact on the Company, the Company cannot predict with any certainty if future laws and regulations in these countries regarding CO2 emissions will have a material effect on the Company’s consolidated financial condition or results of operations.

 

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United States—Federal Legislation and Regulation

Currently, in the United States there is no Federal legislation establishing mandatory GHG emissions reduction programs (including for CO2) affecting the electric power generation facilities of the Company’s subsidiaries. There are numerous state programs regulating GHG emissions from electric power generation facilities and there is a possibility that federal GHG legislation will be enacted within the next several years. Further, the United States Environmental Protection Agency (“EPA”) has adopted regulations pertaining to GHG emissions and has announced its intention to propose new regulations for electric generating units under Section 111 of the United States Clean Air Act (“CAA”).

Potential United States Federal GHG Legislation. Federal legislation passed the United States House of Representatives in 2009 that, if adopted, would have imposed a nationwide cap-and-trade program to reduce GHG emissions. This legislation was never signed into law, and is no longer under consideration. In the U.S. Senate, several different draft bills pertaining to GHG legislation have been considered, including comprehensive GHG legislation similar to the legislation that passed the U.S. House of Representatives and more limited legislation focusing only on the utility and electric generation industry. Although it is unlikely that any legislation pertaining to GHG emissions will be voted on and passed by the U.S. Senate and House of Representatives in 2012, it is uncertain if any such legislation will be voted on and passed by the U.S. Congress in subsequent years. If any such legislation is enacted into law, the impact could be material to the Company.

EPA GHG Regulation. The EPA made a finding that GHG emissions from mobile sources represent an “endangerment” to human health and the environment (the “Endangerment Finding”) following the Supreme Court’s decision in Massachusetts v. EPA, that the EPA has the authority under the CAA to regulate GHG emissions. The EPA then subsequently promulgated regulations governing GHG emissions from automobiles under the CAA (“Motor Vehicle Rule”). The effect of the EPA’s regulation of GHG emissions from mobile sources is that certain provisions of the CAA will also apply to GHG emissions from existing stationary sources, including many United States power plants. In particular, since January 2, 2011, owners or operators who plan construction of new stationary sources and/or modifications to existing stationary sources, which would result in increased GHG emissions, are required to obtain prevention of significant deterioration (“PSD”) permits prior to commencement of construction. In addition, major sources of GHG emissions may be required to amend, or obtain new, Title V air permits under the CAA to reflect any new applicable GHG emissions requirements for new construction or for modifications to existing facilities.

The EPA promulgated a final rule on June 3, 2010, (the “Tailoring Rule”) that sets thresholds for GHG emissions that would trigger PSD permitting requirements. The Tailoring Rule, which became effective in January of 2011, provides that sources already subject to PSD permitting requirements need to install Best Available Control Technology (“BACT”) for greenhouse gases if a proposed modification would result in the increase of more than 75,000 tons per year of GHG emissions. Also, under the Tailoring Rule, commencing in July of 2011, any new sources of GHG emissions that would emit over 100,000 tons per year of GHG emissions, in addition to any modification that would result in GHG emissions exceeding 75,000 tons per year, would require PSD review and be subject to related permitting requirements. The EPA anticipates that it will adjust downward the permitting thresholds of 100,000 tons and 75,000 tons for new sources and modifications, respectively, in future rulemaking actions. The Tailoring Rule substantially reduces the number of sources subject to PSD requirements for GHG emissions and the number of sources required to obtain Title V air permits, although new thermal power plants may still be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the 100,000 ton threshold noted above. The 75,000 ton threshold for increased GHG emissions from modifications to existing sources may reduce the likelihood that future modifications to plants owned by some of our United States subsidiaries would trigger PSD requirements, although some projects that would expand capacity or electric output are likely to exceed this threshold, and in any such cases the capital expenditures necessary to comply with the PSD requirements could be significant.

In December 2010, the EPA entered into a settlement agreement with several states and environmental groups to resolve a petition for review challenging the EPA’s new source performance standards (“NSPS”)

 

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rulemaking for electric utility steam generating units (“EUSGUs”) based on the NSPS’s failure to address GHG emissions. Under the settlement agreement, the EPA committed to propose GHG emissions standards for EUSGUs by July 26, 2011. The EPA subsequently announced that it was delaying the proposal further, without specifying a deadline for the proposal but has committed to finalize GHG NSPS for EUSGUs by May 26, 2012. The NSPS is expected to establish GHG emission standards for newly constructed and reconstructed EUSGUs. The NSPS also may establish guidelines regarding the best system for achieving further GHG emissions reductions from existing EUSGUs. Based on such guidelines, individual states will be required to develop regulations establishing GHG performance standards for existing EUSGUs within their state. It is impossible to estimate the impact and compliance cost associated with any future NSPS applicable to EUSGUs until such regulations are finalized. However, the compliance costs could have a material impact on our consolidated financial condition or results of operations.

A consortium of industry petitioners has challenged the Endangerment Finding, Tailoring Rule and the Motor Vehicle Rule in the United States Court of Appeals for the District of Columbia Circuit. These challenges have been consolidated, briefed and set for oral argument on February 28 and 29, 2012. We cannot predict the outcome of this litigation.

United States—State Legislation and Regulation

Regional Greenhouse Gas Initiative. The primary regulation of GHG emissions affecting the United States plants of the Company’s subsidiaries has previously been through the Regional Greenhouse Gas Initiative (“RGGI”). Under RGGI, ten Northeastern States have coordinated to establish rules that require reductions in CO2 emissions from power plant operations within those states through a cap-and-trade program. Maryland is now the only state currently participating in RGGI in which our subsidiaries have a relevant generating facility. Under RGGI, power plants must acquire one carbon allowance through auction or in the emission trading markets for each ton of CO2 emitted. We have estimated the costs to the Company of compliance with RGGI could be approximately $2.8 million for 2012, and this represents a significant reduction in estimated compliance costs from prior years largely due to the deconsolidation of subsidiaries that owned plants in Connecticut and New York and filed for bankruptcy in 2011. The initial three-year compliance period for RGGI expired at the end of 2011. Under the subsequent three-year compliance period (2012 through 2014), the cap on aggregate CO2 emissions per year for RGGI states is 165 million short tons of CO2, and the affected states are conducting a program wide review that could result in changes to the 2012 through 2014 compliance period, including a lower emissions cap. While these estimated compliance costs are not material to the Company, changes in the regulations or price of allowances under RGGI could have a material impact on our operations and financial performance.

The Company’s Warrior Run business is located in Maryland. In April 2006, the Maryland General Assembly passed the Maryland Healthy Air Act which, among other things, required the State of Maryland to join RGGI. The Maryland Department of Environment (“MDE”) adopted regulations that require 100% of the allowances the State receives to be auctioned except for several small allowance set-aside accounts. The MDE regulations include a safety valve to control the economic impact of the CO2 cap-and-trade program. If the auction closing price reaches $7, up to 50% of a year’s allowances will be reserved for purchase by electric power generation facilities located within Maryland at $7 per allowance, regardless of auction prices. Warrior Run continues to secure its allowance requirements through the RGGI allowance auction.

In 2011, of the approximately 37.5 million metric tonnes of CO2 emitted in the United States by the businesses operated by our subsidiaries (ownership adjusted), approximately 8.3 million metric tonnes were emitted in states participating in RGGI. Over the past three years, such emissions have averaged approximately 9.8 million metric tonnes. The reduction in aggregate emissions by subsidiaries operating in RGGI states from prior years is largely due to lower dispatch at AES Thames and Eastern Energy. While CO2 emissions from businesses operated by subsidiaries of the Company are calculated globally in metric tonnes, RGGI allowances are denominated in short tons. (1 metric tonne equals 2,200 pounds and 1 short ton equals 2,000 pounds.) For

 

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forecasting purposes, the Company has modeled the impact of CO2 compliance based on a three-year average of CO2 emissions for its businesses that are subject to RGGI and that may not be able to pass through compliance costs. The model includes a conversion from metric tonnes to short tons, as well as the impact of some market recovery by merchant plants and contractual and regulatory provisions. The model also utilizes a price of $1.89 per allowance under RGGI. The source of this allowance price estimate was the clearing price in the most recent RGGI allowance auction held in December 2011. Based on these assumptions, the Company estimates that the RGGI compliance costs could be approximately $2.8 million for 2012. Given the fact that the assumptions utilized in the model may prove to be incorrect, there is a risk that our actual compliance costs under RGGI will differ from our estimates and that our model could underestimate our costs of compliance.

California. The Company’s Southland business is located in California. On September 27, 2006, the Governor of California signed the Global Warming Solutions Act of 2006, also called Assembly Bill 32 (“A.B. 32”). A.B. 32 directs the California Air Resources Board (“CARB”) to promulgate regulations that will require the reduction of CO2 and other GHG emissions to 1990 levels by 2020. On October 20, 2011, CARB approved a set of regulations to implement a state-wide cap-and-trade program to regulate GHG emissions. The first compliance period is scheduled to begin on January 1, 2013, and initially covers emissions from electricity generating facilities, large industrial sources with annual emissions greater than 25,000 tons, and imported electricity. Emitters will be required to hold enough allowances or offsets to match their GHG emissions, and can comply by reducing their emissions or by purchasing tradable allowances from other emitters or at state-run auctions. Companies that reduce their emissions below the allowances they hold have the opportunity to sell unused allowances. Initially, retail utilities will be issued free allowances and merchant facilities will be required to bid for allowances at auctions. There is a floor price of $10 for all allowances purchased at auctions. The percentage of free allowances will decline in Phase II and will further decline when Phase III begins in 2018. The program will continue through 2020. Offset credits may be issued for certain verified reductions of GHG emissions or sequestration projects not required by these regulations. The offset credits may be used to satisfy up to eight percent of an entity’s compliance obligation or they may be sold. CARB will continue to refine certain elements of the cap-and-trade program through further rulemakings over the next year via CARB’s “15 day notice” procedure, whereby changes to adopted regulations are recommended by CARB staff and subject to a 15-day public comment period.

California is also a member of the Western Climate Initiative (“WCI”), an organization that includes California as well as four Canadian provinces (British Columbia, Manitoba, Ontario, and Quebec). The WCI has developed a separate program to reduce GHG emissions through a cap-and-trade program that also affects California. As a member of WCI, California has agreed to cut GHG emissions to 15% below 2005 levels by 2020. WCI, Inc., a non-profit corporation, was incorporated in November 2011 to provide administrative and technical services to support the implementation of state and provincial greenhouse gas emissions trading programs and in 2012 it intends to focus on harmonizing the cap-and-trade programs between California and Quebec, the only two WCI members to have adopted cap-and-trade programs to date. WCI, Inc. expects to have two allowance auctions held by the end of 2012. The Company believes that any compliance costs arising from A.B. 32 and the WCI cap-and-trade program for the thermal power plants of its subsidiaries operating in California will be borne by the power offtaker under the terms of existing tolling agreements with the offtaker and under the terms of the programs. However, after the expiration of such tolling agreements, if the Company’s subsidiaries were to sell power on a merchant basis then such compliance costs would likely be borne by the subsidiaries. Also, if following the expiration of such tolling agreements the Company’s subsidiaries entered into new, long-term power purchase agreements that did not provide for compliance costs to be borne by the offtakers then the compliance costs would likely be borne by the Company’s subsidiaries.

Midwestern Greenhouse Gas Reduction Accord (MGGRA). The Company owns the utility IPL, located in Indiana, and the utility DP&L, located in Ohio. On November 15, 2007, six Midwestern state governors and the premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord (“MGGRA”), committing the participating states and province to reduce GHG emissions through the implementation of a cap-and-trade program. Three states (including Indiana and Ohio) and the province of Ontario have signed as observers. In May

 

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of 2010, the MGGRA Advisory Group finalized a set of recommendations for the establishment of targets for emissions reductions in the region and for the design of a regional cap-and-trade program. These include a recommended reduction in GHG emissions of 20% below 2005 emission levels by 2025. The recommendations are from the advisory group only, and have not been endorsed or approved by individual governors, including the Governors of Indiana and Ohio. Though MGGRA has not been formally suspended, participating states are no longer pursuing it. If Indiana or Ohio were to implement the recommended reduction targets, the impact on the Company’s consolidated results of operations, financial condition, and cash flows could be material.

Hawaii. The Company owns a power generation facility in Hawaii. On June 30, 2007, the Governor of Hawaii signed Act 234 which sets a goal of reducing GHG emissions to at or below 1990 levels by January 1, 2020. Act 234 also established the Greenhouse Gas Emissions Reduction Task Force, which is tasked with developing measures to meet Hawaii’s GHG emissions reduction goal. The Task Force filed a report to the Hawaii Legislature on December 30, 2009, strongly supporting the Hawaii Clean Energy Initiative, which calls for additional renewable energy development, increased energy efficiency, and incorporates already-enacted renewable portfolio standards. The Task Force also evaluated other mechanisms and concluded that a state-level cap-and-trade program is inappropriate due to the small size of Hawaii’s economy.

At this time, other than the estimated impact of CO2 compliance noted above for certain of its businesses that are subject to RGGI, the Company has not estimated the costs of compliance with other potential United States federal, state or regional CO2 emissions reduction legislation or initiatives, such as A.B. 32, WCI, MGGRA and potential Hawaii regulations, due to the fact that most of these proposals are not being actively pursued or are in the early stages of development and any final regulations or laws, if adopted, could vary drastically from current proposals, or, in the case of A.B. 32, due to the fact that we anticipate such costs to be passed through to our offtakers under the terms of existing tolling agreements. Although complete specific implementation measures for any federal regulations, WCI, MGGRA and the Hawaiian regulations have yet to be finalized, if these GHG-related initiatives are finalized they may affect a number of the Company’s United States subsidiaries unless they are preempted by federal GHG legislation. Any federal, state or regional legislation or regulations adopted in the United States that would require the reduction of GHG emissions could have a material effect on the Company’s consolidated results of operations, financial condition and cash flows.

The possible impact of any future federal GHG legislation or regulations or any regional or state proposal will depend on various factors, including but not limited to:

 

   

the geographic scope of legislation and/or regulation (e.g., federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load-serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;

 

   

the level of reductions of CO2 being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated CO2 reduction (e.g., 10% reduction from 1990 CO2 emission levels, 20% reduction from 2000 CO2 emission levels, etc.);

 

   

the legislative and/or regulatory structure (e.g., a CO2 cap-and-trade program, a carbon tax, CO2 emission limits, etc.);

 

   

in any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;

 

   

the price of offsets and emission allowances in the secondary market, including any price floors or price caps on the costs of offsets and emission allowances;

 

   

the operation of and emissions from regulated units;

 

   

the permissibility of using offsets to meet reduction requirements and the requirements of such offsets (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes,

 

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any geographic limitations regarding the origin or location of creditable offset projects), as well as the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);

 

   

whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;

 

   

how the price of electricity is determined at the affected businesses, including whether the price includes any costs resulting from any new CO2 legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;

 

   

any impact on fuel demand and volatility that may affect the market clearing price for power;

 

   

the effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;

 

   

the availability and cost of carbon control technology;

 

   

the extent to which existing contractual arrangements transfer compliance costs to power offtakers or other contractual counterparties of our subsidiaries;

 

   

whether legislation regulating GHG emissions will preclude the EPA from regulating GHG emissions under the Clean Air Act or preempt private nuisance suits or other litigation by third parties; and

 

   

any opportunities to change the use of fuel at the generation facilities of our subsidiaries or opportunities to increase efficiency.

Other United States Air Emissions Regulations and Legislation. In the United States the CAA and various state laws and regulations regulate emissions of air pollutants, including SO2, NOX, particulate matter (“PM”), mercury and other hazardous air pollutants (“HAPs”). The applicable rules and the steps taken by the Company to comply with the rules are discussed in further detail below.

The EPA promulgated the “Clean Air Interstate Rule” (“CAIR”) on March 10, 2005, which required allowance surrender for SO2 and NOX emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR contemplated two implementation phases. The first phase was to begin in 2009 and 2010 for NOX and SO2, respectively. A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA.

In response to the D.C. Circuit’s opinion, on July 7, 2011, the EPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR requires significant reductions in SO2 and NOX emissions from covered sources, such as power plants, in many states in which subsidiaries of the Company operate. Once fully implemented in 2014, the rule requires additional SO2 emission reductions of 73% and additional NOX reductions of 54% from 2005 levels. The CSAPR will be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPA will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, at least through 2012, the EPA will issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time. The CSAPR was published in the Federal Register on August 8, 2011, and on October 6, 2011, the EPA proposed some technical revisions to the CSAPR, including allowing for additional allowances for certain states.

 

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Many states, utilities and other affected parties filed petitions for review, challenging the CSAPR before the U.S. Court of Appeals for the District of Columbia. A large subset of the Petitioners also sought a stay of the CSAPR. On December 30, 2011, the court granted a temporary stay of the CSAPR and directed the EPA to continue administering CAIR. The court set forth a schedule of briefings to allow for the case to be heard by April of 2012. We cannot predict the outcome of this litigation, including whether the stay will be lifted and whether the CSAPR will be ultimately implemented in its current form or a modified form. To comply with the CSAPR as currently proposed, additional pollution control technology may be required by some of our subsidiaries, and the cost of implementing any such technology could affect the financial condition or results of operations of these subsidiaries or the Company. Additionally, compliance with the CSAPR could require the purchase of newly issued allowances, the switch to higher priced, lower sulfur coal, and changes in the dispatch of our facilities or the retirement of existing generating units. While the capital costs, other expenditures or operational restrictions necessary to comply with the CSAPR cannot be specified at this time, and the ultimate outcome of litigation pertaining to the CSAPR is uncertain, the Company anticipates that the CSAPR may have a material impact on the Company’s business, financial condition and results of operations.

The EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and nickel species from coal and oil-fired power plants. In connection with such rule, the CAA requires the EPA to establish Maximum Achievable Control Technology (“MACT”). MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. Pursuant to Section 112 of the CAA, the EPA promulgated a final rule on December 16, 2011, called the Mercury Air Toxics Standards (“MATS” or the “Utility MACT”) establishing national emissions standards for hazardous air pollutants (“NESHAP”) from coal and oil-fired electric utility steam generating units. These emission standards reflect the EPA’s application of Utility MACT standards for each pollutant regulated under the rule. The rule requires all coal-fired power plants to comply with the applicable Utility MACT standards within three years, with the possibility of obtaining an additional year, if needed, to complete the installation of necessary controls. To comply with the rule, many coal-fired power plants may need to install additional control technology to control acid gases, mercury or particulate matter, or they may need to repower with an alternate fuel or retire operations. Most of the Company’s United States coal-fired plants operated by the Company’s subsidiaries have acid gas scrubbers or comparable control technologies, but there are other improvements to such control technologies that may be needed at some of the Company’s plants to assure compliance with the Utility MACT standards. Older coal-fired facilities that do not currently have a SO2 scrubber installed are particularly at risk. On July 15, 2011, Duke Energy, co-owner with DP&L at the Beckjord Unit 6 facility, a 414 MW power plant, filed their Long-term Forecast Report with the Public Utilities Commission of Ohio (“PUCO”). The report indicated that Duke Energy plans to cease production at the Beckjord Station, including the jointly-owned Unit 6, in December 2014. DP&L is considering options for its Hutchings Station, a six unit power plant with 365MW of total capacity, to comply with the Utility MACT standards, including the possibility of converting two or more of the units to natural gas or retiring some or all of the units. DP&L has not yet made a final decision. The combination of existing and expected environmental regulations, including the Utility MACT, make it likely that IPL will temporarily or permanently retire several of its existing, primarily coal-fired, smaller and older generating units within the next several years. These units are not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations, and collectively make up less than 15% of IPL’s net electricity generation over the past five years. IPL is continuing to evaluate options for replacing this generation. IPL is currently reviewing the impact of the new Utility MACT rule and estimates total additional expenditures for IPL related to this rule to be approximately $500 million to $900 million through approximately 2016. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that IPL would be successful in that regard. The EPA is encouraging state permitting authorities to allow for an additional year to comply with the rule. While the capital costs, other expenditures or operational restrictions necessary to comply with the rule cannot be specified at this time, the Company anticipates that the rule may have a material impact on the Company’s business, financial condition and results of operations.

 

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New Source Review

The new source review (“NSR”) requirements under the CAA impose certain requirements on major emission sources, such as electric generating stations, if changes are made to the sources that result in a significant increase in air emissions. Certain projects, including power plant modifications, are excluded from these NSR requirements, if they meet the routine maintenance, repair and replacement (“RMRR”) exclusion of the CAA. There is ongoing uncertainty, and significant litigation, regarding which projects fall within the RMRR exclusion. The EPA has pursued a coordinated compliance and enforcement strategy to address NSR compliance issues at the nation’s coal-fired power plants. The strategy has included both the filing of suits against power plant owners and the issuance of Notices of Violation (“NOVs”) to a number of power plant owners alleging NSR violations. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action, including a NOV issued by the EPA against IPL concerning NSR and prevention of significant deterioration issues under the United States Clean Air Act.

During the last decade, DP&L’s Stuart Station and Hutching Station have received NOVs from the EPA alleging that certain activities undertaken in the past are outside the scope of the RMRR exclusion. Additionally, generation units partially owned by DP&L but operated by other utilities have received such NOVs relating to equipment repairs or replacements alleged to be outside the RMRR exclusion. The NOVs issued to DP&L-operated plants have not been pursued through litigation by the EPA.

If NSR requirements were imposed on any of the power plants owned by subsidiaries of the Company, the results could have a material impact on the Company’s business, financial condition and results of operations. In connection with the imposition of any such NSR requirements on our U.S. utilities, DP&L and IPL, the utilities would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that they would be successful in that regard.

Regional Haze Rule

In July 1999, the EPA published the “Regional Haze Rule” to reduce haze and protect visibility in designated federal areas. On June 15, 2005, the 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 amendment to the Regional Haze Rule required states to consider the visibility impacts of the haze produced by an individual facility, in addition to other factors, when determining whether that facility must install potentially costly emissions controls. States were required to submit their regional haze state implementation plans (“SIPs”) to the EPA by December 2007, but only 13 states met this deadline. The EPA has yet to approve any state’s Regional Haze state implementation plan. The statute requires compliance within five years after the EPA approves the relevant SIP, although individual states may impose more stringent compliance schedules. On December 2, 2011, the EPA published a notice that it entered a consent decree with several environmental groups. The consent decree requires the EPA to review and take final action on regional haze requirements for more than 40 states and territories. The EPA had previously determined that any EGU that is subject to the CAIR rule is deemed to meet the BART requirement. On December 30, 2011, the EPA proposed regulatory language that would similarly establish that compliance with the CSAPR would constitute compliance with BART requirements. The EPA will take comments on this proposal until February 25, 2012.

Other International Air Emissions Regulations and Legislation. In Europe, the Company is, and will continue to be, required to reduce air emissions from our facilities to comply with applicable EUC 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, gas and oil 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 opted-in, like

 

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the Company’s Kilroot facility in the United Kingdom, must invest in abatement technology to achieve specific SO2 reductions. Kilroot installed a new flue gas desulphurization system in the second quarter of 2009 in order to satisfy SO2 reduction requirements. The Company’s other coal plants in Europe are either exempt from the Directive due to their size or have opted-in but will not require any additional abatement technology to comply with the LCPD, or, in the case of AES Ballylumford ‘B Station,’ have opted out of the LCPD and will have to retire from operations by 2015.

Over the next four years, the Company’s obligations under the LCPD with respect to our existing facilities will be replaced by obligations under Directive 2010/75/EU on industrial emissions (integrated pollution prevention and control) (the “IED”), which came into force on January 6, 2011 and has to be transposed into national legislation by Member States by January 7, 2013. Progress in implementation of the directive referred to above varies from Member State to Member State. The scope of the IED is wider than the LCPD. It aims to reduce emissions of pollutants that are alleged to be harmful to the environment and associated with cancer, asthma and acid rain, and it seeks to prevent and control air, water and soil pollution by industrial installations. It regulates emissions of a wide range of pollutants, including sulfur and nitrogen compounds, dust particles, asbestos and heavy metals.

The IED provides for a more harmonized and rigorous implementation of permit requirements for large industrial plants, seeking to optimize environmental performance by requiring adoption of the cleanest available technology, so-called Best Available Techniques (“BAT”). Guidance as to BATs applicable to various types of installations will be set out in BAT reference documents (“BREFs”), which the EU will publish based on information and emerging practices from across the EU. Regulators in all Member States will be required to take the BREFs into consideration when assessing permit requirements at each facility. Deviations from these standards will only be permitted where local and technical characteristics would make it disproportionately costly to comply.

In addition to general BAT requirements, the IED also imposes tighter, prescribed minimum emission limits for NOX, SO2 and dust from power plants. Some of these limits are significantly lower than under the LCPD. Existing power plants have to comply with these standards from January 1, 2016 subject to the provisions of “Transitional National Plans,” which Member States may adopt to allow for existing plants to emit above the prescribed limits, in accordance with declining annual caps on NOX, SO2 and/or dust emissions. The annual caps for NOX, SO2 and/or dust emissions must align with the prescribed limits by June 30, 2020. These transitional arrangements are only available to plants which:

 

   

received their first permit (or submitted a permit application) before November 27, 2002; and

 

   

started operating before November 27, 2003.

Where installations are already scheduled to close by the end of 2023 or operate less than 17,500 hours after 2016, they may be permitted to operate without an upgrade, provided that they are not already exempt, pursuant to a “lifetime derogation plan,” and must be agreed to by 2016 by the relevant regulator. AES generation businesses in each Member State will be required to comply with the relevant measures taken to implement the directives. At this time, the Company cannot yet determine the costs associated with the implementation of the IED in Member States that regulate the Company’s subsidiaries, but it could have a material impact on the Company’s consolidated operations or results.

On January 18, 2011, the President of Chile approved a new air emissions regulation submitted to him by the national environmental regulatory agency (“CONAMA”). The new regulation establishes limits on emissions of NOX, SO2, metals and particulate matter for both existing and new thermal power plants, with more stringent limitations on new facilities. The regulation became effective on June 23, 2011. The regulation will require AES Gener, the Company’s Chilean subsidiary, to install emissions reduction equipment at its existing thermal plants. For further information see Item 1.Business—Regulatory Matters—Chile—Environmental Regulations in this Form 10-K.

 

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Water Discharges. The Company’s facilities are subject to a variety of rules governing water discharges. In particular, the Company’s U.S. facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “Best Technology Available” (“BTA”) for cooling water intake structures. The EPA published a proposed rule establishing requirements under 316(b) regulations on April 20, 2011. The proposal, based on Section 316(b) of the U.S. Clean Water Act, establishes BTA requirements regarding impingement standards with respect to aquatic organisms for all facilities that withdraw above 2 million gallons per day of water from certain bodies of water and utilize at least 25% of the withdrawn water for cooling purposes. To meet these BTA requirements, as currently proposed, cooling water intake structures associated with once through cooling processes will need modifications of existing traveling screens that protect aquatic organisms and will need to add a fish return and handling system for each cooling system. Existing closed cycle cooling facilities may require upgrades to water intake structure systems. The proposal would also require comprehensive site-specific studies during the permitting process and may require closed-cycle cooling systems in order to meet BTA entrainment standards.

The public comment period for this proposed rule has expired, and the EPA will consider the public comments with a view to issuing a final rule by July of 2012. Until such regulations are final, the EPA has instructed state regulatory agencies to use their best professional judgment in determining how to evaluate what constitutes “best technology available” for protecting fish and other aquatic organisms from cooling water intake structures. Certain states in which the Company operates power generation facilities have been delegated authority and are moving forward to issue National Pollutant Discharge Elimination System (“NPDES”) permits with best technology available determinations in the absence of any final rule from the EPA. On September 27, 2010, the California Office of Administrative Law approved a policy adopted by the California State Water Resources Control Board with respect to power plant cooling water intake structures that withdraw from coastal and estuarine waters. This policy became effective on October 1, 2010, and establishes technology-based standards to implement Section 316(b) of the U.S. Clean Water Act in NPDES permits that withdraw from coastal and estuarine waters in California. At this time, it is contemplated that the Company’s Redondo Beach, Huntington Beach and Alamitos power plants in California (collectively, “AES Southland”) will need to have in place best technology available by December 31, 2020, or repower the facilities. On April 1, 2011, AES Southland filed an Implementation Plan with the State Water Resources Control Board that indicated its intent to repower the facilities in a phased approach, with the final units being in compliance by 2024. It is anticipated that the State Water Resources Board will respond to the request by April 2012. Power plants will be required to comply with the more stringent of state or federal requirements. At present, the Company cannot predict the final requirements under the EPA Section 316(b) regulation, but the Company anticipates compliance costs could have a material impact on our consolidated financial condition or results of operations.

DP&L is in ongoing negotiations with the EPA and Ohio EPA regarding a National Pollutant Discharge Elimination System permit (the Permit) for J.M. Stuart Station. The primary issue involves the thermal discharges from the Station including the applicability of water quality standards measured either at the point of discharge into a canal that is downstream of Little Three Mile Creek or measured at the point at which the canal discharges into the Ohio River. The EPA is taking the position that the canal is a part of Little Three Mile Creek and that water quality standards should be complied with at the point of discharge into the canal. Two public hearings have been held, one by the EPA in 2011 as part of their review process for draft permits prepared by the Ohio EPA, and one by Ohio EPA in February 2012. The timing of an issuance of a final Permit is uncertain but could occur within 2012 and could impose a future deadline for compliance and compliance requirements could have a material financial effect on DP&L in the future. DP&L is attempting to resolve this issue with both the EPA and Ohio EPA.

Waste Management. In the course of operations, the Company’s facilities generate solid and liquid waste materials requiring eventual disposal or processing. With the exception of coal combustion byproducts (“CCB”), the wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCB, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of

 

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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 CCB, 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. The Company endeavors to ensure that all of its solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. On June 21, 2010, the EPA published in the Federal Register a proposed rule to regulate CCB under the Resource Conservation and Recovery Act (“RCRA”). The proposed rule provides two possible options for CCB regulation, and both options contemplate heightened structural integrity requirements for surface impoundments of CCB. The first option contemplates regulation of CCB as a hazardous waste subject to regulation under Subtitle C of the RCRA. Under this option, existing surface impoundments containing CCB would be required to be retrofitted with composite liners and these impoundments would likely be phased out over several years. State and/or federal permit programs would be developed for storage, transport and disposal of CCB. States could bring enforcement actions for non-compliance with permitting requirements, and the EPA would have oversight responsibilities as well as the authority to bring lawsuits for non-compliance. The second option contemplates regulation of CCB under Subtitle D of the RCRA. Under this option, the EPA would create national criteria applicable to CCB landfills and surface impoundments. Existing impoundments would also be required to be retrofitted with composite liners and would likely be phased out over several years. This option would not contain federal or state permitting requirements. The primary enforcement mechanism under regulation pursuant to Subtitle D would be private lawsuits.

Although the public comment period for this proposed regulation has expired, the EPA issued a Notice of Data Availability (“NODA”) on October 12, 2011, which allowed the public to submit additional information until November 14, 2011, which the EPA is considering prior to promulgating a final rule. The EPA is also conducting a coal ash reuse risk analysis that the EPA has stated it will complete before issuing a final rule in late 2012. The EPA is likely to retain its five-year deadline for meeting the final rule’s surface impoundment requirements. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are finalized, there can be no assurance that the Company’s businesses, financial condition or results of operations would not be materially and adversely affected by such regulations.

Senate Bill 251

In May 2011, Senate Bill 251 became a law in the State of Indiana. Senate Bill 251 is a comprehensive bill which, among other things, provides Indiana utilities, including IPL, with a means for recovering 80% of costs incurred to comply with federal mandates through a periodic retail rate adjustment mechanism. This includes costs to comply with regulations from the EPA, FERC, NERC, Department of Energy, etc., including capital intensive requirements and/or proposals described herein, such as cooling water intake regulations, waste management and coal combustion byproducts, wastewater effluent, MISO transmission expansion costs and polychlorinated biphenyls. It does not change existing legislation that allows for 100% recovery of clean coal technology designed to reduce air pollutants (“Indiana Senate Bill 29”).

Some of the most important features of Senate Bill 251 to IPL are as follows. Any energy utility in Indiana seeking to recover federally mandated costs incurred in connection with a compliance project shall apply to the Indiana Utility Regulatory Commission (“IURC”) for a certificate of public convenience and necessity (“CPCN”) for the compliance project. It sets forth certain factors that the IURC must consider in determining whether to grant a CPCN. It further specifies that if the IURC approves a proposed compliance project and the projected federally mandated costs associated with the project, the following apply: (i) 80% of the approved costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism, (ii) 20% of the approved costs shall be deferred and recovered by the energy utility as part of the next general rate case filed by the energy utility with the IURC, and (iii) actual costs exceeding the projected federally mandated costs of the approved compliance project by more than 25% shall require specific justification and approval before being authorized in the energy utility’s next general rate case. Senate Bill 251 also requires the IURC to adopt rules to establish a voluntary clean energy portfolio standard program. Such program will provide incentives to participating

 

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electricity suppliers to obtain specified percentages of electricity from clean energy sources in accordance with clean portfolio standard goals, including requiring at least 50% of the clean energy to originate from Indiana suppliers. The goals can also be met by purchasing clean energy credits.

CERCLA. The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA” aka “Superfund”) may be the source of claims against certain of the Company’s U.S. subsidiaries from time to time. There is ongoing litigation at a site known as the South Dayton Landfill where a group of companies already recognized as Potentially Responsible Parties (“PRP”) have sued DP&L and other unrelated entities seeking a contribution towards the costs of assessment and remediation. DP&L is actively opposing such claims. In 2003, DP&L received notice that the EPA considers DP&L to be a PRP at the Tremont City landfill Superfund site. No actions have taken place since 2003 regarding the Tremont City landfill. The Company is unable to determine whether there will be any liability, or the size of any liability that may ultimately be assessed against DP&L at these two sites, but any such liability could be material to DP&L.

 

ITEM 1A. RISK FACTORS

You should consider carefully the following risks, along with the other information contained in or incorporated by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. If any of the following events actually occur, our business, financial results and financial condition could be materially adversely affected.

Risks Associated with our Disclosure Controls and Internal Control over Financial Reporting

We completed the remediation of our material weaknesses in internal control over financial reporting in 2008. However, our disclosure controls and procedures may not be effective in future periods if our judgments prove incorrect or new material weaknesses are identified.

For each of the fiscal quarters between December 31, 2004 and September 30, 2008, our management reported material weaknesses in our internal control over financial reporting. A material weakness is a deficiency (within the meaning of the Public Company Accounting Oversight Board (“PCAOB”) Auditing Standard No. 5), 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 reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. As a result of these material weaknesses, our management concluded that for each of the fiscal quarters from December 31, 2004 through September 30, 2008, we did not maintain effective internal control over financial reporting and concluded that our disclosure controls and procedures were not effective to provide reasonable assurance that financial information that we are required to disclose in our reports under the Exchange Act was recorded, processed, summarized and reported accurately.

To address these material weaknesses in our internal control over financial reporting, each time we prepared our annual and quarterly reports, we performed additional analyses and other post-closing procedures. 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. Nevertheless, even with these additional procedures, the material weaknesses in our internal control over financial reporting caused us to have errors in our financial statements and from 2003 to 2008 we had to restate our annual financial statements six times to correct these errors.

Since December 31, 2008, our management has reported that all of our previously identified material weaknesses have been remediated and that our internal control over financial reporting and our disclosure controls have been effective. For a discussion of our internal control over financial reporting and our disclosure controls, see Item 9A.—Controls and Procedures in this Form 10-K. In making its assessment about the

 

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effectiveness of our internal control over financial reporting and our disclosure controls and procedures, management had to make certain judgments and it is possible that any number of their judgments could prove to be incorrect and that our remediation efforts did not fully and completely cure the previously identified material weaknesses. There is also the possibility that there are other material weaknesses in our internal control that are unknown to us or that new material weaknesses may develop in the future. The existence of any material weakness in our internal control over financial reporting would subject us to certain risks, including the following:

 

   

litigation or an expansion of the SEC’s informal inquiry into our restatements or the commencement of formal proceedings 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;

 

   

inability to file timely financial statements with the SEC, which would:

 

   

prevent us from offering and selling our securities pursuant to our shelf registration statement on Form S-3, which in turn would impair our ability to access the capital markets through the public sale of registered securities in a timely manner, and/or

 

   

depending on the length of such delay, result in covenant defaults under our senior secured credit facility and the indenture governing certain of our outstanding debt securities.

 

   

negative publicity;

 

   

ratings downgrades;

 

   

inability to raise capital in the public markets and/or private markets when desired or necessary; or

 

   

the loss or impairment of investor confidence in the Company.

Furthermore, 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, changes in accounting practice or policy, or that the degree of compliance with the revised policies or procedures deteriorates over time. 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.

Our ability to timely file our financial statements and/or the effectiveness of our internal control over financial reporting may be adversely impacted in future periods due to the efforts required to adopt new accounting standards issued by the FASB as a result of the convergence of accounting standards project between the FASB and IASB.

The U.S. Financial Accounting Standards Board (the “FASB”), which establishes accounting principles generally accepted in the United States (“GAAP”) guidelines that companies follow in the United States, and the International Accounting Standards Board (“IASB”), which is an international accounting standards setter outside of the United States, are presently engaged in a project to converge several accounting standards. The convergence project may result in the issuance of several new accounting standards in the future that revise existing GAAP accounting standards and which the Company may be required to adopt under GAAP.

Based on the present timeline released by the FASB, several pronouncements could be issued in final form starting in 2012. Although the release of final pronouncements is not assured and the proposed adoption dates of these standards have not been set, each new standard that the Company must comply with may require significant effort to adopt. For each new standard, the Company will be required to evaluate the impact of any accounting changes necessitated by a new standard which will include, but not be limited to, an evaluation of a new standard’s impact on its financial statements and contractual arrangements; planning for and implementation of

 

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any changes to accounting systems; processes and procedures to ensure the Company properly complies with a new standard; and training personnel. To the extent that multiple standards are effective as of one date or in close proximity to one another, the Company may require considerable resources to achieve compliance with these new standards. An inability to complete these efforts prior to their effective date could have an adverse effect on our ability to timely file our financial statements with the SEC and/or the effectiveness of our internal controls over financial reporting.

Risks Related to our High Level of Indebtedness

We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations.

As of December 31, 2011, we had approximately $22.6 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings under The AES Corporation’s senior secured credit facility and certain other indebtedness are secured by certain of our assets, including the pledge of capital stock of many of The AES Corporation’s directly held subsidiaries. Most of the debt of The AES Corporation’s subsidiaries is secured by substantially all of the assets of those subsidiaries. Since we have such a high level of debt, a substantial portion of cash flow from operations must be used to make payments on this debt. Furthermore, since a significant percentage of our assets are used to secure this debt, this reduces the amount of collateral that is available for future secured debt or credit support and reduces our flexibility in dealing with these secured assets. This high level of indebtedness and related security could have other important consequences to us and our investors, including:

 

   

making it more difficult to satisfy debt service and other obligations at the holding company and/or individual subsidiaries;

 

   

increasing the likelihood of a downgrade of our debt, which could cause future debt costs and/or payments to increase under our debt and related hedging instruments and consume an even greater portion of cash flow;

 

   

increasing our vulnerability to general adverse industry conditions and economic conditions, including but not limited to adverse changes in foreign exchange rates and commodity prices;

 

   

reducing the availability of cash flow to fund other corporate purposes and grow our business;

 

   

limiting our flexibility in planning for, or reacting to, changes in our business and the industry;

 

   

placing us at a competitive disadvantage to our competitors that are not as highly leveraged; and

 

   

limiting, along with the financial and other restrictive covenants relating to such indebtedness, among other things, our ability to borrow additional funds as needed or take advantage of business opportunities as they arise, pay cash dividends or repurchase common stock.

The agreements governing our indebtedness, including the indebtedness of our subsidiaries, limit, but do not prohibit the incurrence of 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 flows 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, raise equity or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. See Note 11—Debt included in Item 8. of this Form 10-K for a schedule of our debt maturities.

The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its 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 The AES Corporation’s revenue is generated through its subsidiaries. Accordingly, almost all of The AES

 

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Corporation’s cash flow is generated by the operating activities of its subsidiaries. Therefore, The AES Corporation’s ability to make payments on its indebtedness and to fund its other obligations is dependent not only on the ability of its subsidiaries to generate cash, but also on the ability of the subsidiaries to distribute cash to it in the form of dividends, fees, interest, loans or otherwise.

However, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation. Most of the 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 The AES Corporation. In addition, the payment of dividends or the making of loans, advances or other payments to The AES Corporation may be subject to other contractual, legal or regulatory restrictions. Business performance and local accounting and tax rules may limit the amount of retained earnings that may be distributed to us as a dividend. Subsidiaries in foreign countries may also be prevented from distributing funds to The AES Corporation as a result of foreign governments restricting the repatriation of funds or the conversion of currencies. Any right that The AES Corporation has to receive any assets of any of its subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of The AES Corporation’s 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).

The AES Corporation could receive less funds than it expects as a result of the current challenges facing the global and local economies, which could impact the performance of our businesses and their ability to distribute cash to The AES Corporation. For further discussion of the macroeconomic environment and its impact on our business, see Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Global Economic Conditions.

The AES Corporation’s subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of The AES Corporation’s indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other payments. While some of The AES Corporation’s subsidiaries guarantee the Parent’s indebtedness under the Parent’s senior secured credit facility, none of its subsidiaries guarantee, or are otherwise obligated with respect to, its outstanding public debt securities.

Even though The AES Corporation is a holding company, existing and potential future defaults by subsidiaries or affiliates could adversely affect The AES Corporation.

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.

As of December 31, 2011, we had approximately $22.6 billion of outstanding indebtedness on a consolidated basis, of which approximately $6.5 billion was recourse debt of The AES Corporation and approximately $16.1 billion was non-recourse debt. In addition, we have outstanding guarantees, letters of credit, and other credit support commitments which are further described in this Form 10-K in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and LiquidityParent Company Liquidity.

 

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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 $1.3 billion at December 31, 2011. 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 there under can still have important consequences for The AES Corporation, including, without limitation:

 

   

reducing The AES Corporation’s receipt of subsidiary dividends, fees, interest payments, loans and other sources of cash since the project subsidiary will typically be prohibited from distributing cash to The AES Corporation during the pendency 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;

 

   

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

 

   

the loss or impairment of investor confidence in the Company; or

 

   

foreclosure on the assets that are pledged under the nonrecourse loans, therefore eliminating any and all potential future benefits derived from those assets.

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 facility or other debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of future mix of distributions, 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 applicable definition of materiality 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 facility. The risk of such defaults may have increased as a result of the deteriorating global economy. For further discussion of these conditions, see Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Global Economic Conditions of this Form 10-K.

Risks Associated with our Ability to Raise Needed Capital

The AES Corporation has significant cash requirements and limited sources of liquidity.

The AES Corporation requires cash primarily to fund:

 

   

principal repayments of debt;

 

   

interest and preferred dividends;

 

   

acquisitions;

 

   

construction and other project commitments;

 

   

other equity commitments, including business development investments;

 

   

equity repurchases and/or cash dividends on our common stock that we may declare in the future;

 

   

taxes; and

 

   

Parent Company overhead costs.

 

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The AES Corporation’s principal sources of liquidity are:

 

   

dividends and other 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 The AES Corporation’s 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 of this 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, our ability to sell assets, and the ability of our subsidiaries to pay dividends. Any number of assumptions could prove to be incorrect and therefore there can be no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than expected. For example, in recent years, certain financial institutions have gone bankrupt. In the event that a bank who is party to our senior secured credit facility or other facilities goes bankrupt or is otherwise unable to fund its commitments, we would need to replace that bank in our syndicate or risk a reduction in the size of the facility, which would reduce our liquidity. In addition, our cash flow may not be sufficient to repay at maturity the entire principal outstanding under our credit facilities and our debt securities and we may have to refinance such obligations. There can be no assurance that we will be successful in obtaining such refinancing on terms acceptable to us or at all and any of these events could have a material effect on us.

Our ability to grow our business could be materially adversely affected if we were unable to raise capital on favorable terms.

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. 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 and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing as well as companies in our industry or similar financial circumstances; and

 

   

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

Should future access to capital not be available to us, we may have to sell assets or decide not to build new plants or expand or improve existing facilities, either of which would affect our future growth, results of operations or financial condition.

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

If any of the credit ratings of The AES Corporation or its subsidiaries were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs would increase. Furthermore, depending on The AES Corporation’s credit ratings and the trading prices of its equity and debt securities,

 

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counterparties 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 and/or collateral, to backstop or replace any credit support by The AES Corporation. There can be no assurance that such counterparties will accept such guarantees or that AES could arrange such further assurances 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.

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

Part of our strategy is to grow our business by developing Generation and Utility businesses in less developed economies where the return on our investment may be greater than projects in more developed economies. Commercial lending institutions sometimes refuse to provide non-recourse project financing in certain less developed economies, and in these situations we have sought and will continue to seek 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, the lending institutions may also require governmental guarantees of certain project and sovereign related risks. There can be no assurance, however, that project financing from the international financial agencies or that governmental guarantees will be available when needed, and if they are not, we may have to abandon the project or invest more of our own funds which may not be in line with our investment objectives and would leave less funds for other projects. These risks have increased as a result of the recent credit crisis and the deteriorating global economy. For further discussion of these global economic conditions and their potential impact on the Company, see Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Global Economic Conditions.

External Risks Associated with Revenue and Earnings Volatility

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

Some of our businesses sell electricity in the wholesale spot markets in cases where they operate wholly or partially without long-term power sales agreements. Our Generation and Utility businesses may 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, or oil may impact the open market wholesale price of electricity.

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

 

   

plant availability in the markets generally;

 

   

availability and effectiveness of transmission facilities owned and operated by third parties;

 

   

competition;

 

   

demand for energy commodities;

 

   

electricity usage;

 

   

seasonality;

 

   

interest rate and foreign exchange rate fluctuation;

 

   

availability and price of emission credits;

 

   

input prices;

 

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hydrology and other weather conditions;

 

   

illiquid markets;

 

   

transmission or transportation constraints or inefficiencies;

 

   

availability of competitively priced renewables sources;

 

   

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

 

   

generating unit performance;

 

   

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

 

   

energy, market and environmental regulation, legislation and policies;

 

   

geopolitical concerns affecting global supply of oil and natural gas; and

 

   

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

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

Our exposure to currency exchange rate fluctuations results primarily from the translation exposure associated with the preparation of the Consolidated Financial Statements, as well as from transaction exposure associated with transactions in currencies other than an entity’s functional currency. While the 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 appropriate exchange rates. As a result, fluctuations in the exchange rate of the U.S. Dollar relative to the local currencies where 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 receipts and expenditures are not denominated in the subsidiary’s functional currency.

We also experience foreign transaction exposure to the extent monetary assets and liabilities, including debt, are in a different currency than the subsidiary’s functional 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 affected by fluctuations in the value of a number of currencies, primarily the Euro, Brazilian real, Argentine peso, Chilean peso, Colombian peso and Philippine peso.

We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.

We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity, fuel requirements and other commodities to lower our financial exposure related to commodity price fluctuations. 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. We also enter into contracts which help us hedge our interest rate exposure on variable rate debt. However, we may not cover the entire exposure of our assets or positions to market price or interest rate volatility, and the coverage will vary over time. Furthermore, the risk management practices we have in place may not always perform as planned. In particular, if prices of commodities or interest rates significantly deviate from historical prices or interest rates or if the price or interest rate volatility or distribution of these changes deviates from historical norms, our risk management practices may not protect us from significant losses. As a result, fluctuating commodity prices or interest rates may negatively impact our financial results to the extent we have unhedged or inadequately hedged positions. In addition, certain types of economic hedging activities may not qualify for hedge accounting under GAAP, resulting in increased volatility in our net income. The Company may also suffer losses associated with “basis risk” which is the assumed relative correlation of performance between the intended hedge instrument and

 

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the targeted underlying exposure. Furthermore, there is a risk that the current counterparties to these arrangements may fail or are unable to perform their obligations under these arrangements.

In the past few years, we have faced substantial challenges in North America as a result of high coal prices relative to natural gas, which has affected the results of certain of our coal plants in the region, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place but purchase fuel at market prices or under short term contracts. For our businesses with PPA pricing that does not perfectly pass through our fuel costs, the businesses attempt to manage the exposure through flexible fuel purchasing and timing of entry and terms of our fuel supply agreements; however, these risk management efforts may not be successful and the resulting commodity exposure could have a material impact on these businesses and/or our results of operations. In recent years, our coal-fired plants in New York and our petroleum coke-fired plant in Texas have been affected by market conditions, including the commodity price risks noted above. As a result of these and other challenges, AES Thames, our 208 MW coal-fired generation business in Connecticut, filed for bankruptcy protection in January 2011 and is in the process of liquidation and AES Eastern Energy filed for bankruptcy protection in December 2011.

In our North America Utility Businesses, DPL and IPL, there may be a portion of their generating facilities output that is sold into the merchant markets and subject to variability in dark spreads. The level of generation subject to dark spread exposure is dependent upon retail demand obligations and hedge levels in place, which, as noted above, can adversely impact the performance of these businesses and our results of operations.

Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.

We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of our facilities. If these suppliers cannot perform, we would seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price, which could be lower than contracted prices and would expose these businesses to considerable price volatility.

At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility’s output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. We have also hedged a portion of our exposure to power price fluctuations through forward fixed price power sales. Counterparties to these agreements may breach or may be unable to perform their obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement PPAs, these businesses may have to sell power at market prices.

The failure of any supplier or customer to fulfill its contractual obligations to The AES Corporation or our subsidiaries could have a material adverse effect on our financial results. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.

The market pricing of our common stock has been volatile and may continue to be volatile in future periods.

The market price for our common stock has been volatile in the past, and the price of our common stock could fluctuate substantially in the future. Stock price movements on a quarter by quarter basis for the past two years are set forth in Item 5.—Market—Market Information of this Form 10-K. Factors that could affect the price of our common stock in the future include general conditions in our industry, in the power markets in which we participate and in the world, including environmental and economic developments, over which we have no control, as well as developments specific to us, including, risks that could result in revenue and earnings

 

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volatility as well as other risk factors described in this Item 1A.—Risk Factors and those matters described in Item 7.—Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Risks Associated with our Operations

We do a significant amount of business outside the United States, including in developing countries, which presents significant risks.

A significant amount of our revenue is 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;

 

   

threatened or consummated expropriation or nationalization of our assets by foreign governments;

 

   

difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with GAAP expertise;

 

   

unwillingness of governments, government agencies, similar organizations or other counterparties to honor their contracts;

 

   

unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;

 

   

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

 

   

adverse changes in government tax policy;

 

   

difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and

 

   

potentially adverse tax consequences of operating in multiple jurisdictions.

Any of these factors, by itself or in combination with others, could materially and adversely affect our business, results of operations and financial condition. For example, partly in response to challenging business and political conditions in Kazakhstan, in 2008, we sold certain businesses in that country. As another example, in the second quarter of 2007, we sold our stake in EDC to Petróleos de Venezuela, S.A., the state-owned energy company in Venezuela after Venezuelan President Hugo Chávez threatened to expropriate the electricity business in Venezuela. In connection with the sale, we recognized an impairment charge of approximately $680 million. In addition, our Latin American operations experience volatility in revenues and gross margin which have caused

 

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and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability and currency devaluations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.

The operation of power generation and distribution facilities involves significant risks that could adversely affect our financial results. We and/or our subsidiaries may not have adequate insurance coverage for liabilities.

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, failure of transmission systems, 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.

Our businesses require reliable transportation sources (including related infrastructure such as roads, ports and rail), power sources and water sources to access and conduct operations. The availability and cost of this infrastructure affects capital and operating costs and levels of production and sales. Limitations, or interruptions in transportation including as a result of third parties intentionally or unintentionally disrupting the facilities of our subsidiaries, could impede their ability to produce electricity. This could have a material adverse effect on our businesses’ results of operations, financial condition and prospects.

In addition, a portion of our generation facilities were constructed many years ago. Older generating equipment may require significant capital expenditures for maintenance. The equipment at our plants, whether old or new, is also likely to require periodic upgrading, improvement or repair, and replacement equipment or parts may be difficult to obtain in circumstances where we rely on a single supplier or a small number of suppliers. The inability to obtain replacement equipment or parts may impact the ability of our plants to perform and could therefore have a material impact on our business and results of operations. 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 a power purchase or other agreement or incurrence of a liability for liquidated damages and/or other penalties.

As a result of the above risks and other potential hazards associated with the power generation and distribution industries, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error or certain external events. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate the possibility of the occurrence and impact of these risks.

The hazards described above can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of

 

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operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is customary, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A claim for which we are not fully insured or insured at all could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

Our businesses’ insurance does not cover every potential risk associated with its operations. Adequate coverage at reasonable rates is not always obtainable. In addition, insurance may not fully cover the liability or the consequences of any business interruptions such as equipment failure or labor dispute. The occurrence of a significant adverse event not fully or partially covered by insurance could have a material adverse effect on the Company’s business, results or operations, financial condition and prospects.

Any of the above risks could have a material adverse effect on our business and results of operations.

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

Our operating success and ability to carry out growth initiatives depends in part on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity, including people in our foreign businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements. In particular, we routinely are required to assess the financial and tax impacts of complicated business transactions which occur on a worldwide basis. These assessments are dependent on hiring personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with United States reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse effect on our financial and tax reporting.

We have contractual obligations to certain customers to provide full requirements service, which makes it difficult to predict and plan for load requirements and may result in increased operating costs to certain of our businesses.

We have contractual obligations to certain customers to supply power to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of power that our power generation and distribution facilities must be prepared to supply to customers may increase our operating costs. A significant under- or over-estimation of load requirements could result in our facilities not having enough or having too much power to cover their obligations, in which case we would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating costs.

We may not be able to enter into long-term contracts, which reduce volatility in our results of operations. Even when we successfully enter into long-term contracts, our generation businesses are often dependent on one or a limited number of customers and a limited number of fuel suppliers.

Many of our generation plants conduct business under long-term contracts. In these instances, we rely on power sales contracts with one or a limited number of customers for the majority of, and in some cases all of, the relevant plant’s output and revenues over the term of the power sales contract. The remaining terms of the power sales contracts range from 1 to 25 years. In many cases, we also limit our exposure to fluctuations in fuel prices by entering into long-term contracts for fuel with a limited number of suppliers. In these instances, the cash flows and results of operations are dependent on the continued ability of customers and suppliers to meet their obligations under the relevant power sales contract or fuel supply contract, respectively. Some of our long-term power sales

 

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agreements are at prices above current spot market prices and some of our long-term fuel supply contracts are at prices below current market prices. The loss of significant power sales contracts or fuel supply contracts, or the failure by any of the parties to such contracts that prevents us from fulfilling our obligations there under, could have a material adverse impact on our business, results of operations and financial condition. In addition, depending on market conditions and regulatory regimes, it may be difficult for us to secure long-term contracts, either where our current contracts are expiring or for new development projects. The inability to enter into long-term contracts could require many of our businesses to purchase inputs at market prices and sell electricity into spot markets, which may not be favorable. For example, during the past several years, various governmental authorities in Europe have terminated or declined to fulfill their obligations under long-term contracts with our subsidiaries. In 2008, as part of the accession to the European Union, the Hungarian government terminated all long-term PPAs, including AES Tisza’s PPA, as of December 31, 2008. Partly as a result of the termination, AES Tisza’s results of operations declined and we were required to record an $85 million asset impairment charge for AES Tisza in the third quarter of 2010 and another impairment charge of $52 million in 2011. Pursuant to the terms of its PPA, Kilroot in Northern Ireland received notice from the Utility Regulator directing Kilroot and NIE Energy to terminate the Generating Unit Agreements for the two coal fired units effective November 1, 2010 and, as a result, the performance (and contributions to income and cash flow) from Kilroot will decline in the future when compared to prior years. Furthermore, these businesses (and any other businesses whose long-term contracts may be challenged) may have to sell electricity into the spot markets. In addition, in connection with Bulgaria’s ascension into the EU, the EC has opened an investigation into alleged anticompetitive behavior in the Bulgarian electricity market, which could have a material impact on our results of operations. Further information on the EC investigation is set forth in Item 1. Business— Regulatory Matters—Bulgaria in this Form 10-K. Because of the volatile nature of inputs and power prices, the inability to secure long-term contracts could generate increased volatility in our earnings and cash flows and could generate substantial losses (or result in a write-down of assets), which could have a material impact on our business and results of operations.

We have sought to reduce counterparty credit risk under our long-term contracts in part by entering into power sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from certain sovereign governments of the customer’s obligations. However, many of our customers do not have, or have failed to maintain, an investment-grade credit rating, and our Generation business cannot 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, there can be no assurance that our efforts to mitigate this risk will be successful. These risks have increased as a result of the deteriorating and volatile global economy. For further discussion of these global economic conditions and their potential impact on the Company, see Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Global Economic Conditions in this Form 10-K.

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) 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 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. These competitive factors could have a material adverse effect on us.

 

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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 twenty-six defined benefit plans, four are at United States 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. The Company periodically evaluates the value of the pension plan assets to ensure that they will be sufficient to fund the respective pension obligations. The Company’s exposure to market volatility is mitigated to some extent due to the fact that the asset allocations in our largest plans are more heavily weighted to investments in fixed income securities that have not been as severely impacted by the global recession. Future downturns in the debt and/or equity markets, or the inaccuracy of any of our significant assumptions underlying the estimates of our subsidiaries’ pension plan obligations, could result in an increase in pension expense and future funding requirements, which may be material. Our subsidiaries who participate in these plans are responsible for satisfying the funding requirements required by law in their respective jurisdiction for any shortfall of pension plan assets compared to pension obligations under the pension plan. This may necessitate additional cash contributions to the pension plans that could adversely affect the Parent Company and our subsidiaries’ liquidity.

For additional information regarding the funding position of the Company’s pension plans, see Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical AccountingEstimatesPension and Postretirement Obligations and Note 14 to our Consolidated Financial Statements included in this Form 10-K.

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, commissioning delays, or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. Timing of equipment purchases can also pose financial risks to the Company. As part of our development process, we attempt to make purchases of equipment and/or materials as needed. However, from time to time, there may be excess demand for certain types of equipment with substantial delays between the time we place orders and receive delivery. In those instances, to avoid construction delays and costs associated with the inability to own and place such equipment and/or materials into service when needed in the construction process, we may place orders well in advance of deployment. In some cases, we may order such equipment and/or materials without yet having a specific project where the equipment and/or materials will be deployed, in anticipation that equipment and materials will be needed at the time of delivery. However, there is a risk that at the time of delivery, we are required to accept delivery and pay for such equipment and/or materials, even though no project has materialized where these items will be used. This can result in our having to incur material equipment and/or material costs, with no deployment plan at delivery. Financing risk has also increased as a result of the deterioration of the global economy and the crisis in the financial markets and, as a result, we may forgo certain development opportunities. We believe that capitalized costs for projects under development are recoverable; however, there can be no assurance 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 and write off the costs incurred in connection with such project. 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.

 

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In some of our joint venture projects and businesses, we have granted protective rights to minority holders or we own less than a majority of the equity in the project or business and do not manage or otherwise control the project or business, which entails certain risks.

We have invested in some joint ventures where we own less than a majority of the voting equity in the venture. Very often, one of our subsidiaries seeks to exert a degree of influence with respect to the management and operation of projects or businesses in which we have less than a majority of the ownership interests by operating the project or business pursuant to a management contract, negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, we do not always have this type of control over the project or business in every instance and we may be dependent on our co-venturers to operate such projects or businesses. Our co-venturers may not have the level of experience, technical expertise, human resources, management and other attributes necessary to operate these projects or businesses optimally. The approval of co-venturers also may be required for us to receive distributions of funds from projects or to transfer our interest in projects or businesses.

In some joint venture agreements where we do have majority control of the voting securities, we have entered into shareholder agreements granting protective minority rights to the other shareholders. For example, Companhia Brasiliana de Energia (“Brasiliana”) is a holding company in which we have a controlling equity interest and through which we own three of our four Brazilian businesses: Eletropaulo, Tietê and Uruguaiana. We entered into a shareholders’ agreement with an affiliate of the Brazilian National Development Bank (“BNDES”) which owns more than 49 % of the voting equity of Brasiliana. Among other things, the shareholders’ agreement requires the consent of both parties before taking certain corporate actions, grants both parties rights of first refusal in connection with the sale of interests in Brasiliana and grants certain drag-along rights to BNDES. In May 2007, BNDES notified us that it intends to sell all of its interest in Brasiliana pursuant to a public auction (the “Brasiliana Sale”). BNDES also informed us that if we fail to exercise our right of first refusal to purchase all of its interest in Brasiliana, then BNDES intends to exercise its drag-along rights under the shareholders’ agreement and cause us to sell all of our interests in Brasiliana in the Brasiliana Sale as well. BNDES has since suspended the auction; however, BNDES may determine to recommence a sale process in the future. In that event, after the auction, if a third party offer has been received in the Brasiliana Sale, we will have 30 days to exercise our right of first refusal to purchase all of BNDES’s interest in Brasiliana on the same terms as the third-party offer. If we do not exercise this right and BNDES proceeds to exercise its drag-along rights, then we may be forced to sell all of our interest in Brasiliana. Due to the uncertainty in the sale price at this point in time, we are uncertain whether we will exercise our right of first refusal should BNDES receive a valid third-party offer in the Brasiliana Sale and, if we do, whether we would do it alone or with joint venture partners. Even if we desire to exercise our right of first refusal, we cannot assure that we will have the cash on hand or that debt or equity financing will be available at acceptable terms in order to purchase BNDES’s interest in Brasiliana. If we do not exercise our right of first refusal, we cannot be assured that we will not have to record a loss if the sale price is below the book value of our investment in Brasiliana.

Our renewable energy projects and other initiatives face considerable uncertainties including, development, operational and regulatory challenges.

Wind Generation, AES Solar, our greenhouse gas emissions reductions projects (“GHG Emissions Reduction Projects”), and our investments in projects such as energy storage are subject to substantial risks. Projects of this nature have been developed through advancement in technologies which may not be proven or whose commercial application is limited, and which are unrelated to our core business. Some of these business lines are dependent upon favorable regulatory incentives to support continued investment, and there is significant uncertainty about the extent to which such favorable regulatory incentives will be available in the future. For example, several European countries have recently faced a debt crisis, which has or may result in government austerity measures, including, repeal or reduction of certain subsidies. If additional subsidies or other incentives are repealed or reduced, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, this could materially impact our renewable businesses, results of operations and financial condition, and impact the ability of the affected businesses to continue or grow

 

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their operations. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries, which could also have a material impact on our results of operations.

Furthermore, production levels for our wind, solar, and GHG Emissions Reduction Projects may be dependent upon adequate wind, sunlight, or biogas production which can vary significantly from period to period, resulting in volatility in production levels and profitability. For example, for our wind projects, wind resource estimates are based on historical experience when available and on wind resource studies conducted by an independent engineer, and are not expected to reflect actual wind energy production in any given year. With regard to GHG Emissions Reduction Projects, there is particular uncertainty about whether agreements providing incentives for reductions in greenhouse gas emissions, such as the Kyoto Protocol, will continue and whether countries around the world will enact or maintain legislation that provides incentives for reductions in greenhouse gas emissions, without which such projects may not be economical or financing for such projects may become unavailable.

As a result, renewable energy projects face considerable risk relative to our core business, including the risk that favorable regulatory regimes expire or are adversely modified. In addition, because certain of these projects depend on technology outside of our expertise in Generation and Utility businesses, there are risks associated with our ability to develop and manage such projects profitably. Furthermore, at the development or acquisition stage, because of the nascent nature of these industries or the limited experience with the relevant technologies, our ability to predict actual performance results may be hindered and the projects may not perform as predicted. There are also risks associated with the fact that some of these projects exist in new or emerging markets, where long-term fixed price contracts for the major cost and revenue components may be unavailable, which in turn may result in these projects having relatively high levels of volatility.

These projects can be capital-intensive and generally are designed with a view to obtaining third party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to develop these projects or obtain third party financing for these projects. These risks may be exacerbated by the current global economic crisis, including our management’s increased focus on liquidity, which may also result in slower growth in the number of projects we can pursue. The economic downturn could also impact the value of our assets in these countries and our ability to develop these projects. If the value of these assets decline, this could result in a material impairment or a series of impairments which are material in the aggregate, which would adversely affect our financial statements.

Impairment of goodwill or long-lived assets would negatively impact our consolidated results of operations and net worth.

Goodwill represents the future economic benefits arising from assets acquired in a business combination (acquisition) that are not individually identified and separately recognized. Goodwill is not amortized, but is evaluated for impairment at least annually, or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions, or our operating or regulatory environment; increased competitive environment; increase in fuel costs, particularly when we are unable to pass through the impact to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; divestiture of a significant component of our business; or adverse actions or assessments by a regulator. Additionally, goodwill may be impaired if our acquisitions do not perform as expected. See further discussion in “Our Acquisitions May Not Perform as Expected.” These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. As of December 31, 2011, we had $3.7 billion of goodwill, which represented approximately 8% of our total assets. If current global economic conditions deteriorate, as further described in Item 7.—Management’s

 

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Discussion and Analysis of Financial Condition and Results of Operations—Global Economic Conditions, it could increase the risk that we will have to recognize and record goodwill impairment charges.

Long-lived assets are initially recorded at fair value and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present whereas goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above.

Certain of our businesses are sensitive to variations in weather.

Our businesses are affected by variations in general weather conditions and unusually severe weather. Our businesses forecast electric sales on the basis of normal weather, which represents a long-term historical average. While we also consider possible variations in normal weather patterns and potential impacts on our facilities and our businesses, there can be no assurance that such planning can prevent these impacts, which can adversely affect our business. Generally, demand for electricity peaks in winter and summer. Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less demand for electricity than forecasted. Significant variations from normal weather where our businesses are located could have a material impact on our results of operations.

In addition, we are dependent upon hydrological conditions prevailing from time to time in the broad geographic regions in which our hydroelectric generation facilities are located. If hydrological conditions result in droughts or other conditions that negatively affect our hydroelectric generation business, our results of operations could be materially adversely affected. In the past, our businesses in Latin America have been negatively impacted by lower than normal rainfall. Similarly, our wind businesses are dependent on adequate wind conditions while the solar projects at AES Solar are dependent on sufficient sunlight. In each case, inadequate wind or sunlight could have a material adverse impact on these businesses.

Information security breaches could harm our business.

A security breach of our information systems could impact the reliability of our generation fleets and/or the reliability of our transmission and distribution systems. A security breach that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our transmission and distribution assets, access customer information and limit our communications with third parties. Our security measures may not prevent such security breaches. Any loss of confidential or proprietary data through a breach could impair our reputation, expose us to legal claims and materially adversely affect our business and results of operations.

Our acquisitions may not perform as expected.

Historically, acquisitions have been a significant part of our growth strategy. We may continue to grow our business through acquisitions. Although acquired businesses may have significant operating histories, 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 have been government owned and some may be operated as part of a larger integrated utility prior to their acquisition. If we were to acquire any of these types of businesses, there can be no assurance that:

 

   

we will be successful in transitioning them to private ownership;

 

   

such businesses will perform as expected;

 

   

integration or other one-time costs will not be greater than expected;

 

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we will not incur unforeseen obligations or liabilities;

 

   

such businesses 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 capital to acquire them.

In November 2011, we acquired DPL Inc., owner of DP&L. Risks associated with the acquisition of DPL are further discussed below.

We may fail to realize the anticipated benefits and cost savings of the acquisition, which could adversely affect the value of the Company’s common stock or result in goodwill impairment.

The success of our recent acquisition of DPL will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating DPL into our portfolio of businesses. Our ability to realize these anticipated benefits and cost savings is subject to certain risks including:

 

   

the Company’s ability to successfully combine the businesses of the Company and DPL into its portfolio;

 

   

whether DPL will perform as expected, including DPL’s ability to achieve a successful outcome on its ESP or MRO proceeding and to manage customers’ ability to select alternative electric generation providers (in each case, as described below);

 

   

the possibility that the Company paid more than the value it will derive from the acquisition, which may lead to future impairments;

 

   

the reduction of the Company’s cash available for operations and other uses, the increase in amortization expense related to identifiable assets acquired and the incurrence of indebtedness to finance the acquisition; and

 

   

the assumption of certain known and unknown liabilities of DPL.

If the Company is not able to successfully integrate DPL into its portfolio of businesses within the previously anticipated time frame, or at all, the anticipated benefits and cost savings of the transaction may not be realized fully or at all or may take longer to realize than expected, or DPL may not perform as expected. In addition, DPL may fail to perform as expected for reasons unrelated to the transaction.

Many of the risks facing DPL are similar to the risks facing our other regulated utility businesses, including with respect to rate regulation, which is moving towards a market-based pricing mechanism (under the laws of Ohio), increased costs due to energy efficiency requirements and other environmental and health and safety regulations, volatility of fuels costs, increased benefit plan costs and exposure to environmental liabilities. In addition, under Ohio law, DPL will be required to provide a standard service officer (“SSO”) through either an Electric Service Plan or Market Rate Offer which will be effective by January 1, 2013, the terms of which could have a material impact on our results of operations. Further information regarding these requirements is disclosed in Item 1. Business—Regulatory Matters—United States.

DPL also faces unique risks, including increased competition as a result of Ohio legislation that permits its customers to select alternative electric generation service providers. Under this legislation, customers can elect to buy transmission and generation service from a PUCO-certified Competitive Retail Electric Service Provider (“CRES Provider”) offering services to customers in DP&L’s service territory. Increased competition by unaffiliated CRES Providers in DP&L’s service territory for retail generation service could result in the loss of existing customers and reduced revenues and increased costs to retain or attract customers. The following are a few of the factors that could result in increased switching by customers to PUCO-certified CRES Providers in the future:

 

   

Low wholesale price levels may lead to existing CRES Providers becoming more active in our service territory, and additional CRES providers entering our territory.

 

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We could also experience customer switching through governmental aggregation, where a municipality may contract with a CRES Provider to provide generation service to the customers located within the municipal boundaries. Greater than expected customers switching would decrease DPL’s margins and increase its costs thereby causing its financial performance to be worse than the Company projected. Failure by DPL to perform as expected for any reason could adversely affect the Company’s business, financial results, including goodwill impairment, and stock price.

The Company and DPL have operated and will continue to operate, independently. It is possible that the ongoing integration process could result in the loss of key DPL employees, the disruption of DPL’s ongoing businesses, unexpected integration issues, higher than expected integration costs or an overall integration process that takes longer than originally anticipated.

In addition, at times, the attention of certain members of the Company’s and DPL’s management and resources may be focused on the ongoing integration of the businesses of the two companies and diverted from day-to-day business operations, which may disrupt each of the companies’ ongoing businesses and the business of the combined company.

The Company has incurred and will incur significant transaction and acquisition-related costs in connection with the recent DPL acquisition.

The Company has incurred and expects to incur a number of non-recurring costs associated with combining the operations of the two companies. The substantial majority of non-recurring expenses resulting from the transaction will be comprised of transaction costs related to the acquisition, facilities and systems consolidation costs and employment-related costs. The Company has incurred and will also incur transaction fees and costs related to formulating and implementing integration plans. The Company continues to assess the magnitude of these costs and additional unanticipated costs may be incurred in the ongoing integration of the two companies’ businesses. Although the Company expects that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow the Company to offset incremental transaction and acquisition-related costs over time, this net benefit may not be achieved in the near term, or at all.

The DPL acquisition may not be accretive, and may be dilutive, to the Company’s earnings per share and credit position, which may negatively affect the market price of the Company’s common stock.

Future events and conditions, including adverse changes in market conditions, additional transaction and integration related costs and other factors such as the failure to realize all of the benefits anticipated in the acquisition, could decrease or delay the accretion that is currently expected or could result in earnings dilution. In addition, in connection with the acquisition, we recorded $2.5 billion in provisional goodwill. If we do not take actions that successfully mitigate and reduce the impacts of adverse changes in market conditions and if we do not realize the anticipated benefits of the transaction, it is possible that we may have to impair all or a portion of the goodwill, which could have a material impact in the periods in which the impairment occurs. Any dilution of, or decrease or delay of any currently expected accretion to, the Company’s earnings per share or cash flow could cause the price of the Company’s common stock to decline and adversely affect its credit position. If incremental cash flow and dividends from operating subsidiaries of DPL are not sufficient to service the $3.3 billion of debt we incurred to fund the acquisition, the transaction could be credit dilutive to DPL and The AES Corporation, which may decrease the Company’s financial flexibility and increase its borrowing costs, which could adversely affect the Company’s business, financial results and stock price.

 

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Risks associated with Governmental Regulation and Laws

Our operations 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.

Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any 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 publicly announced projections or analysts’ expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our 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 to be included in the rates we charge our customers, including but not limited to costs incurred to upgrade our power plants to comply with more stringent environmental regulations;

 

   

changes in the determination of what is an appropriate rate of return on invested capital or a determination that a utility’s operating income or the rates it charges customers is too high, resulting in a reduction of rates or consumer rebates;

 

   

changes in the definition or determination of controllable or non-controllable costs;

 

   

adverse changes in tax law;

 

   

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

 

   

changes in the timing of tariff increases;

 

   

other changes in the regulatory determinations under the relevant concessions; or

 

   

other changes related to licensing or permitting which affect our ability to conduct business.

Any of the above events may result in lower margins for the affected businesses, which can adversely affect our business.

In many countries where we conduct business, the regulatory environment is constantly changing or the regulations can be difficult to interpret. As a result, there is risk that we may not properly interpret certain regulations and may not understand the impact of certain regulations on our business. For example, in October 2006, ANEEL, which regulates our utility operations at Sul and Eletropaulo in Brazil, issued Normative Resolution 234 requiring that utilities begin amortizing a liability called “Special Obligations” beginning with their second tariff reset cycle in 2007 or a later year as an offset to depreciation expense. As of May 23, 2007, the date of the filing of our 2006 Form 10-K, no industry positions or any other consensus had been reached regarding how ANEEL guidance should be applied at that date and accordingly, no adjustments to the financial statements were made relating to Special Obligations in Brazil. Subsequent to May 23, 2007, industry discussions occurred and other Brazilian companies filed Forms 20-F with the SEC reflecting the impact of Resolution 234 in their December 31, 2006 financial statements differently from how the Company accounted for Resolution 234. In the absence of any significant regulatory developments between May 23, 2007 and the date of these other filings, the Company determined that Resolution 234 required us to record an adjustment to our Special Obligations liability as of December 31, 2006. In part, the decision to record the adjustment led to the restatement of our financial statements in the third quarter of 2007. If we face additional challenges interpreting regulations or changes in regulations, it could have a material adverse impact on our business.

On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). While the bulk of regulations contained in the Dodd-Frank Act regulate financial institutions and their products, there are several provisions related to corporate governance, executive

 

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compensation, disclosure and other matters which relate to public companies generally. The types of provisions described above are currently not expected to have a material impact on the Company or its results of operations. Furthermore, while the Dodd-Frank Act substantially expands the regulation regarding the trading, clearing and reporting of derivative transactions, the Dodd-Frank Act provides for commercial end-user exemptions which may apply to our derivative transactions, though this is not certain since the Act directs the SEC, CFTC and listed companies to enact rules that will clarify the Dodd-Frank Act, and such rulemaking could impact the availability of the commercial end-user exemption. Even if the exemption is available, the Dodd-Frank Act could still have a material adverse impact on the Company, as the regulation of derivatives (which includes capital and margin requirements for non-exempt companies), could limit the availability of derivative transactions that we use to reduce interest rate, commodity and currency risks, which would increase our exposure to these risks. Even if derivative transactions remain available, the costs to enter into these transactions may increase, which could adversely affect the operating results of certain projects; cause us to default on certain types of contracts where we are contractually obligated to hedge certain risks, such as project financing agreements; prevent us from developing new projects where interest rate hedging is required; cause the Company to abandon certain of its hedging strategies and transactions, thereby increasing our exposure to interest rate, commodity and currency risk; and/or consume substantial liquidity by forcing the Company to post cash and/or other permitted collateral in support of these derivatives. Any of these outcomes could have a material adverse effect on the Company.

On June 12, 2009 AES Kelanitissa received a letter and an invoice from the Director General, Public Utilities Commission of Sri Lanka (“PUC”) seeking payment of an Annual Regulatory Fee and pursuant to PUC assurances on an application for renewal of the AES Kelanitissa generation license. The application is pursuant to an April 2009 revision of the Sri Lanka Electricity Act (“Electricity Act”), which came into force in April 2009, notwithstanding that in March 29, 2001, AES Kelanitissa had been granted, and pre-paid fees for, a 21 year generation license with effect from September 25, 2000 under the Electricity Act, 1950. AES Kelanitissa submitted an application to be licensed under the revised legislation and, on August 26, 2009, PUC published its intention to issue a generation license under the revised legislation to AES Kelanitissa and other Independent Power Producers (“IPPs”) in Sri Lanka. This was consistent with assurances received from relevant authorities that the revised legislation was to be amended to grandfather IPPs with existing generation licenses. In a letter dated June 21, 2010 from the PUC, AES Kelanitissa was informed that under the new regulations, as amended in 2009, AES Kelanitissa (Pvt) Ltd no longer fulfilled the eligibility criteria to apply for a generation license. The “eligibility criteria” to which the letter refers is a provision requiring an element of state ownership. Representatives of AES Kelanitissa have been informed that an amendment to the Electricity Act to grandfather existing IPPs remains in the legislative pipeline, although it is not possible to predict with certainty when or whether such an amendment will be passed. In addition, AES Kelanitissa believes that under Sri Lankan law, it may continue operations under the 21 year license issued in 2001. No step has been taken to date to prohibit AES Kelanitissa from generating power and conducting its operations. However, in the event that it is determined that AES Kelanitissa may not operate under its current license or the revised legislation is not amended (and PUC maintains that AES Kelanitissa is ineligible for a generation license or extension of the Generating License), AES Kelanitissa may not be able to continue operations on grounds that it has no license under the revised legislation. In that event, AES Kelanitissa and/or the Company could face a number of adverse consequences, including potential litigation with counterparties mitigating a write down in the value of the assets of the business, continued default status under its debt documents and/or other consequences which could have a material impact on the Company or its results of operations.

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”), the Federal Power Act, and the EPAct 2005. 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 QFs if certain market conditions are met. Pursuant to this authority, the FERC has instituted a rebuttable presumption that utilities located within the

 

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control areas of the Midwest Transmission System Operator, Inc., PJM (“Pennsylvania, New Jersey and Maryland”) Interconnection, L.L.C., ISO New England, Inc., the New York Independent System Operator (“NYISO”) and the Electric Reliability Council of Texas, Inc. are not required to purchase or sell power from or to QFs above a certain size. 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 1935 and enacted PUHCA 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 removed barriers to mergers and other potential combinations which could result in 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 United States generation market.

In accordance with Congressional mandates in the EPAct 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 RTOs and ISOs 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 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 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.

Our businesses are subject to stringent environmental laws and regulations.

Our activities are subject to stringent environmental laws and regulations by many federal, regional, state and local authorities, international treaties and foreign governmental authorities. These laws and regulations generally concern emissions into the air, effluents into the water, use of water, wetlands preservation, remediation of contamination, waste disposal, endangered species and noise regulation, among others. Failure to comply with such laws and regulations or to obtain or comply with 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 emissions and water discharges. See the various descriptions of these laws and regulations contained in Item 1.—Business—Regulatory Matters of this Form 10-K. 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 incurred and will continue to incur significant capital and other expenditures to comply with these and other environmental laws and regulations. Changes in, or new, environmental restrictions may force the Company to incur significant expenses or expenses that may 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, including recorded asset values 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.

 

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Our businesses are subject to enforcement initiatives from environmental regulatory agencies.

The EPA has pursued an enforcement initiative against coal-fired generating plants alleging wide-spread violations of the new source review and prevention of significant deterioration provisions of the CAA. The EPA has brought suit against a number of companies and has obtained settlements with approximately 23 companies over such allegations. The allegations typically involve claims that a company made major modifications to a coal-fired generating unit without proper permit approval and without installing best available control technology. The principal, but not exclusive, focus of this EPA enforcement initiative is emissions of SO2 and NOX. In connection with this enforcement initiative, the EPA has imposed fines and required companies to install improved pollution control technologies to reduce emissions of SO2 and NOX. One of our U.S. utility businesses, IPL, is currently the subject of such EPA enforcement action. See Item 3.—Legal Proceedings of this Form 10-K for more detail with respect to these EPA enforcement actions. There can be no assurance that foreign environmental regulatory agencies in countries in which our subsidiaries operate will not pursue similar enforcement initiatives under relevant laws and regulations.

Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.

As discussed in Item 1.—Business—Regulatory Matters—Environmental and Land Use Regulations, at the international, federal and various regional and state levels, rules are in effect or policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. In 2011, the Company’s subsidiaries operated businesses which had total CO2 emissions of approximately 74 million metric tonnes, approximately 37.5 million of which were emitted by businesses located in the United States (both figures ownership adjusted). The Company uses CO2 emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. For existing power generation plants, CO2 emissions are either obtained directly from plant continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission factors. The estimated annual CO2 emissions from fossil fuel electric power generation facilities of the Company’s subsidiaries that are in construction or development and have received the necessary air permits for commercial operations are approximately 15.5 million metric tonnes (ownership adjusted). This overall estimate is based on a number of projections and assumptions which may prove to be incorrect, such as the forecasted dispatch, anticipated plant efficiency, fuel type, CO2 emissions rates and our subsidiaries’ achieving completion of such construction and development projects. However, it is certain that the projects under construction or development when completed will increase emissions of our portfolio and therefore could increase the risks associated with emissions described below. Because there is significant uncertainty regarding these estimates, actual emissions from these projects under construction or development may vary substantially from these estimates.

The non-utility, generation subsidiaries of the Company often seek to pass on any costs arising from CO2 emissions to contract counterparties, but there can be no assurance that such subsidiaries of the Company will effectively pass such costs onto the contract counterparties or that the cost and burden associated with any dispute over which party bears such costs would not be burdensome and costly to the relevant subsidiaries of the Company. The utility subsidiaries of the Company may seek to pass on any costs arising from CO2 emissions to customers, but there can be no assurance that such subsidiaries of the Company will effectively pass such costs to the customers, or that they will be able to fully or timely recover such costs.

Foreign, federal, state or regional regulation of GHG emissions could have a material adverse impact on the Company’s financial performance. The actual impact on the Company’s financial performance and the financial performance of the Company’s subsidiaries will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, the cost of emissions reduction equipment and the price and availability of offsets, the extent to which market based