ITEM 1. BUSINESS
Overview
We are a global power company. We own a portfolio of electricity generation and distribution businesses on five continents in 28 countries, with total capacity of approximately 40,500 Megawatts (“MW”) and distribution networks serving over 12 million people as of December 31, 2010. In addition, we have more than 2,000 MW under construction in six countries. Our global workforce of approximately 29,000 people helps provide electricity to people in diverse markets ranging from urban centers in the United States to remote villages in India. We were incorporated in Delaware in 1981 and for three decades we have been committed to providing safe and reliable energy.
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 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, gas, fuel oil, biomass and renewable sources such as hydroelectric power, wind and solar, which reduces the risks associated with dependence on any one fuel source. Our presence in mature markets helps reduce the volatility associated with our businesses in 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 hedging some of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. However, our business is still subject to these and other risks, which are further described in Item 1A.
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 since December 31, 2004 through 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 since 2003 we had to restate our annual financial statements six times to correct these errors.
The material weaknesses in our internal control over financial reporting also caused us to delay the filing of certain quarterly and annual reports with the SEC to dates that went beyond the deadlines prescribed by the SEC’s rules to file such reports. We did not timely file with the SEC our quarterly and annual reports for the year ended December 31, 2005, our quarterly reports for the second and third quarters of 2005, our annual report for the year ended December 31, 2006, and our quarterly report for the quarter ended March 31, 2007. Under SEC rules, failure to timely file these reports prohibited us for a period of twelve months from offering and selling our securities pursuant to our shelf registration statement on Form S-3, which impaired our ability to access the capital markets through the public sale of registered securities in a timely manner. The failure to file our annual and quarterly reports with the SEC in a timely fashion also resulted in covenant defaults under our senior secured credit facility and the indenture governing certain of our outstanding debt securities. Such defaults required us to obtain a waiver from the lenders under the senior secured credit facility; however the default under the indentures was cured upon the filing of the reports within the permitted grace period. In addition to these problems, the material weaknesses in internal controls, the restatements of our financial statements and the delay in the filing of our annual and quarterly reports exposed us to other risks including, but not limited to:
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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;
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negative publicity;
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ratings downgrades;
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inability to raise capital in the public markets and/or private markets when desired or necessary; or
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the loss or impairment of investor confidence in the Company.
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 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 all of the risks described above.
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.
In the future, we may be adversely impacted by 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 in 2011. 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 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, 2010, we had approximately $19.7 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:
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making it more difficult to satisfy debt service and other obligations at the holding company and/or individual subsidiaries;
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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;
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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;
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reducing the availability of cash flow to fund other corporate purposes and grow our business;
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limiting our flexibility in planning for, or reacting to, changes in our business and the industry;
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placing us at a competitive disadvantage to our competitors that are not as highly leveraged; and
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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 10-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 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, 2010, we had approximately $19.7 billion of outstanding indebtedness on a consolidated basis, of which approximately $4.6 billion was recourse debt of The AES Corporation and approximately $15.1 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 Liquidity-Parent Company Liquidity.
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 $1.4 billion at December 31, 2010. While the lenders under our non-recourse project financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults thereunder can still have important consequences for The AES Corporation, including, without limitation:
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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;
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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;
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causing The AES Corporation to record a loss in the event the lender forecloses on the assets;
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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;
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the loss or impairment of investor confidence in the Company; or
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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:
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principal repayments of debt;
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interest and preferred dividends;
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acquisitions;
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construction and other project commitments;
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other equity commitments, including business development investments;
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equity repurchases;
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taxes; and
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Parent Company overhead costs.
The AES Corporation’s principal sources of liquidity are:
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dividends and other distributions from its subsidiaries;
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proceeds from debt and equity financings at the Parent Company level; and
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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:
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general economic and capital market conditions;
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the availability of bank credit;
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investor confidence;
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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
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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, 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:
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plant availability in the markets generally;
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availability and effectiveness of transmission facilities owned and operated by third parties;
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competition;
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demand for energy commodities;
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electricity usage;
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seasonality;
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interest rate and foreign exchange rate fluctuation;
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availability and price of emission credits;
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input prices;
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hydrology and other weather conditions;
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illiquid markets;
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transmission or transportation constraints or inefficiencies;
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availability of competitively priced renewables sources;
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available supplies of natural gas, crude oil and refined products, and coal;
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generating unit performance;
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natural disasters, terrorism, wars, embargoes and other catastrophic events;
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energy, market and environmental regulation, legislation and policies;
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geopolitical concerns affecting global supply of oil and natural gas; and
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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 procedures we have in place may not always be followed or may not work 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 system 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 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 2010, we 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. In particular, our coal-fired plants in New York and our petroleum coke-fired plant in Texas have been affected by these conditions. In North America, current dark spreads and the corresponding forward curves do not currently present a long-term opportunity to engage in hedging activity for 2011 and we have very limited hedges in place. As short-term opportunities occur or should dark spreads improve, the Company may engage in additional hedging in 2011. As a result of these and other challenges that arose from new regulatory concerns, we impaired $1.1 billion of assets and goodwill in North America as described in Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Impairments. In addition, AES Thames, our 208 MW coal-fired generation business in Connecticut, filed for bankruptcy protection in January 2011.
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 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:
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economic, social and political instability in any particular country or region;
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adverse changes in currency exchange rates;
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government restrictions on converting currencies or repatriating funds;
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unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;
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high inflation and monetary fluctuations;
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restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
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threatened or consummated expropriation or nationalization of our assets by foreign governments;
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difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with GAAP expertise;
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unwillingness of governments, government agencies, similar organizations or other counterparties to honor their contracts;
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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;
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inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
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adverse changes in government tax policy;
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difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and
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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 Chavez 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 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:
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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
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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. This equipment is also likely to require periodic upgrading and improvement. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of a power purchase or other agreement or incurring 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 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 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 affect 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 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 thereunder, 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. 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 2011 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. 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.
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 nine defined benefit plans, three 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 Accounting-Estimates-Pension and Postretirement Obligations and Note 13 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.
Certain delays have occurred at the 670 MW Maritza coal-fired project in Bulgaria, and the project has not begun commercial operations. As noted in Note 10-Debt included in Item 8 of this Form 10-K, as a result of these delays the project debt is in default and the Company is working with its lenders to resolve the default. In addition, as noted in Item 3. -Legal Proceedings, the Company is in litigation with the contractor regarding the cause of delays. At this time, management believes that Maritza will commence commercial operations for at least some of the project’s capacity by the second half of 2011. However, commencement of commercial operations could be delayed beyond this timeframe. There can be no assurance that Maritza will achieve commercial operations, in whole or in part, by the second half of 2011, resolve the default with the lenders or prevail in the litigation referenced above, which could result in the loss of some or all of our investment or require additional funding for the project. Any of these events could have a material adverse effect on the Company’s operating.
In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals (“VCA”) that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant stopped as a consequence of the Supreme Court’s decision. In December 2009, Chilean authorities approved new land use regulations that entitled EEC to apply for a new environmental permit. EEC applied for a new environmental permit in January 2010 and permit approval was granted by the Environmental Authority in February 2010. In March 2010, the Mayor of Puchuncaví and another third party challenged the new environmental permit before the VCA. The parties later entered into a settlement agreement pursuant to which the challenge to the new environmental permit was withdrawn in July 2010. In addition, the construction permit that is required to resume construction of the Plant was issued by the Municipality in August 2010. In September 2010, neighbors of Puchuncaví challenged the construction permit filing claims in the VCA. In November 2010, the VCA rejected the claims. The challenging parties subsequently filed appeals with the Supreme Court. In January 2011, the Supreme Court confirmed the decision of the VCA, finally rejecting the constitutional action. EEC has resumed construction of the Plant.
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 be 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:
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we will be successful in transitioning them to private ownership;
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such businesses will perform as expected;
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integration or other one-time costs will not be greater than expected;
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we will not incur unforeseen obligations or liabilities;
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such business will generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them; or
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the rate of return from such businesses will justify our decision to invest our capital to acquire them.
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.
AES 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. If these incentives are repealed, 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 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 many 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 require that we obtain third party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to develop 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.
An impairment in the carrying value of goodwill or long-lived assets would negatively impact our consolidated results of operations and net worth.
Goodwill is initially recorded at fair value and is not amortized, but is evaluated for impairment at least annually, or more frequently if impairment indicators are present. In assessing the recoverability of goodwill, we make estimates and assumptions about sales, operating margin growth rates and discount rates based on our budgets, business plans, economic projections, anticipated future cash flows and marketplace data. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. The fair value of a reporting unit has been determined using an income approach based on the present value of future cash flows of each reporting unit. We could be required to evaluate the recoverability of goodwill outside of the required annual assessment process if we experience situations, including but not limited to, disruptions to the business, unexpected significant declines in operating results, divestiture of a significant component of our business or adverse actions or assessments by a regulator. There could also be impairments if our acquisitions do not perform as expected. See further discussion in Risk Factor, “Our Acquisitions May Not Perform as Expected.” These types of events and the resulting analyses could result in goodwill impairment charges in the future. Impairment charges could substantially affect our financial results in the periods of such charges. As of December 31, 2010, we had $1.3 billion of goodwill, which represented approximately 3% of total assets. If current conditions in the global economy continue or worsen, this could increase the risk that we will have to
impair goodwill, as further described in Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Global Economic Conditions.
Long-lived assets are initially recorded at fair value and are amortized or depreciated over their useful lives. Long-lived assets are evaluated for impairment when impairment indicators are present. In assessing the recoverability of long-lived assets, we make estimates and assumptions about sales, operating margin growth rates, commodity prices and discount rates based on our budgets, business plans, economic projections, anticipated future cash flows and marketplace data. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a long-lived asset or asset group is determined using an income approach based on the present value of future cash flows of each asset group. We could be required to evaluate the recoverability of long-lived assets if we experience situations, including but not limited to, disruptions to the business, unexpected significant declines in operating results, divestiture of a significant component of our business or adverse action or assessment by a regulator. These types of events and the resulting analyses could result in additional long-lived asset impairment charges in the future. Impairment charges could substantially affect our financial results in the periods of such charges. If current conditions in the global economy continue or worsen, this could increase the risk that we will have to impair long-lived assets, as further described in Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Global Economic Conditions.
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.
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:
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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;
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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;
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changes in the definition or determination of controllable or non-controllable costs;
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adverse changes in tax law;
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changes in the definition of events which may or may not qualify as changes in economic equilibrium;
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changes in the timing of tariff increases;
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other changes in the regulatory determinations under the relevant concessions; or
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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 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 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 any necessary environmental permits pursuant to such laws and regulations could result in fines or other sanctions. Environmental laws and regulations affecting power generation and distribution are complex and have tended to become more stringent over time. Congress and other domestic and foreign governmental authorities have either considered or implemented various laws and regulations to restrict or tax certain emissions, particularly those involving air and water emissions. See the various descriptions of these laws and regulations contained in 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 us 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.
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 17 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 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 businesses, IPL, is currently the subject of such an EPA enforcement action, and another business, Eastern Energy, has received an information request from the EPA in connection with a possible enforcement action. See Item 3.-Legal Proceedings of this Form 10-K for more detail with respect to these EPA enforcement actions and information requests. 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 2010, the Company’s subsidiaries operated businesses which had total approximate CO2 emissions of 77.2 million metric tonnes approximately 40 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 18 million metric tonnes (ownership adjusted). This overall estimate is based upon a number of projections and assumptions which may prove to be incorrect such as the forecast dispatch, anticipated plant efficiency, fuel type, CO2 emissions 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 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 the 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.
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 the price and availability of offsets, the extent to which market based compliance options are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the ability of our subsidiaries to recover costs incurred through rate increases or otherwise. As a result of these factors, our cost of compliance could be substantial and could have a material impact on our results of operations.
In January 2005, based on European Community “Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading,” the European Union Greenhouse Gas Emission Trading Scheme (“EU ETS”) commenced operation as the largest multi-country GHG emission trading scheme in the world. On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires the 40 developed countries that have ratified it to substantially reduce their GHG emissions, including CO2. To date, compliance with the Kyoto Protocol and the EU ETS has not had a material adverse effect on the Company’s consolidated results of operations, financial condition and cash flows.
The United States has not ratified the Kyoto Protocol. In the United States, there currently is no legislation establishing federal mandatory GHG emission reduction programs (including CO2) affecting the electric power generation facilities of the Company’s subsidiaries. However, federal GHG legislation has been proposed in the United States Congress that would, if enacted, constrain GHG emissions, including CO2, and/or impose costs on
us that could be material to our business or results of operations. The EPA has also initiated regulations pertaining to GHG emissions that require new sources of GHG emissions of over 100,000 tons per year, and existing sources planning physical changes that would increase their GHG emissions by more than 75,000 tons per year, to obtain new source review permits from the EPA prior to construction or modification.
Such regulations could increase our costs directly and indirectly and have a material adverse effect on our business and/or results of operations. See Item 1. Business-Regulatory Matters-Environmental and Land Use Regulations of this Form 10-K for further discussion about these environmental agreements, laws and regulations.
At the state level, RGGI, a cap-and-trade program covering CO2 emissions from electric power generation facilities in the Northeast, became effective in January 2009, and the WCI is also developing market-based programs to address GHG emissions in seven western states. In addition, several states, including California, have adopted comprehensive legislation that, when effective, will require mandatory GHG reductions from several industrial sectors, including the electric power generation industry. See Item 1.-Business-Regulatory Matters-Environmental and Land Use Regulations of this Form 10-K for further discussion about the United States state environmental regulations we face. At this time, other than with regard to RGGI (further described below), the Company cannot estimate the costs of compliance with United States federal, regional or state CO2 emissions reduction legislation or initiatives, due to the fact that these proposals are in earlier stages of development and any final regulations or legislation, if adopted, could vary drastically from current proposals.
The RGGI program became effective in January 2009. The first regional auction of RGGI allowances needed to be acquired by power generators to comply with state programs implementing RGGI was held in September 2008, with subsequent auctions occurring approximately every quarter. Our subsidiaries in New York, New Jersey, Connecticut and Maryland are subject to RGGI. Of the approximately 40 million metric tonnes of CO2 emitted in the United States by our subsidiaries in 2010 (ownership adjusted), approximately 11.3 million metric tonnes were emitted in United States states participating in RGGI. Over the past three years, such emissions have averaged approximately 10.9 million metric tonnes. 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 forecasting purposes, the Company has modeled the impact of CO2 compliance based on a 3-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 $1.86 per allowance under RGGI. The source of this allowance price estimate was the clearing price in the recent RGGI allowance auction held in December 2010. Based on these assumptions, the Company estimates that the RGGI compliance costs could be approximately $15 million for 2011, which is the last year of the first RGGI compliance period. Given the fact that the assumptions utilized in the model may prove to be incorrect, there is a significant risk that our actual compliance costs under RGGI will differ from our estimates by a material amount and that our model could underestimate our costs of compliance.
In addition to government regulators, other groups such as politicians, environmentalists and other private parties have expressed increasing concern about GHG emissions. For example, certain financial institutions have expressed concern about providing financing for facilities which would emit GHGs, which can affect our ability to obtain capital, or if we can obtain capital, to receive it on commercially viable terms. In addition, rating agencies may decide to downgrade our credit ratings based on the emissions of the businesses operated by our subsidiaries or increased compliance costs which could make financing unattractive. In addition, environmental groups and other private plaintiffs have brought and may decide to bring additional private lawsuits against the Company because of its subsidiaries’ GHG emissions. The Company is facing and may face in the future private lawsuits relating to GHG emissions that may have a material impact on the Company’s results of operations. In one recent case in the United States, which does not involve the Company, a federal appellate court reversed the dismissal by a federal district court of nuisance and other claims against emitters of GHG based on property damage allegedly caused by their contributions to global warming. While the scope of relief sought in that case is
unclear, the plaintiffs in this case evidently seek injunctive relief to prevent or reduce further GHG emissions. The defendants appealed the appellate court decision to the Supreme Court of the United States, and the Supreme Court is expected to render a decision in 2011. If the defendants do not prevail, other parties may be encouraged to bring similar suits against electric power generators, including the Company or any of its United States subsidiaries. Also, unless the United States Congress acts to preempt such suits as part of comprehensive federal legislation, additional lawsuits may be brought against the Company or its subsidiaries. At this stage of the litigation, it is impossible to predict whether such lawsuits are likely to prevail or result in damages awards. Consequently, it is impossible to determine whether such lawsuits are likely to have a material adverse effect on the Company’s consolidated results of operations and financial condition.
Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect the Company’s business and operations, and any such potential impact may render it more difficult for our businesses to obtain financing. For example, extreme weather events could result in increased downtime and operation and maintenance costs at the electric power generation facilities and support facilities of the Company’s subsidiaries. Variations in weather conditions, primarily temperature and humidity also would be expected to affect the energy needs of customers. A decrease in energy consumption could decrease the revenues of the Company’s subsidiaries. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of the fossil-fuel fired electric power generation facilities of the Company’s subsidiaries. Changes in temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric generation.
In addition to potential physical risks noted by the Intergovernmental Panel on Climate Change, there could be damage to the reputation of the Company and its subsidiaries due to public perception of GHG emissions by the Company or any of its subsidiaries, and any such negative public perception or concerns could ultimately result in a decreased demand for electric power generation or distribution from our subsidiaries. The level of GHG emissions made by subsidiaries of the Company is not a factor in the compensation of executives of the Company.
If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on the electric power generation businesses of the Company’s subsidiaries and on the Company’s consolidated results of operations, financial condition and cash flows.
Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.
Our subsidiaries have operations in the United States and various non-United States jurisdictions. As such, we are subject to the tax laws and regulations of the United States federal, state and local governments and of many non-United States jurisdictions. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these initiatives. In addition, United States federal, state and local, as well as non-United States, tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities.
We and our affiliates are subject to material litigation and regulatory proceedings.
We and our affiliates are parties to material litigation and regulatory proceedings. See Item 3.-Legal Proceedings below. There can be no assurances that the outcome of such matters will not have a material adverse effect on our consolidated financial position.
The SEC is conducting an informal inquiry relating to our restatements.
We have been cooperating with an informal inquiry by the SEC Staff concerning our past restatements and related matters, and have been providing information and documents to the SEC Staff on a voluntary basis. Although we have not received correspondence regarding this inquiry for some time, we have not been advised that the matter is closed. Because we are unable to predict the outcome of this inquiry, the SEC Staff may disagree with the manner in which we have accounted for and reported the financial impact of the adjustments to previously filed financial statements and there may be a risk that the inquiry by the SEC could lead to circumstances in which we may have to further restate previously filed financial statements, amend prior filings or take other actions not currently contemplated.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-term leases, none of which we believe are material. With a few exceptions, our facilities, which are described in Item 1 of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project’s related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims for approximately $450 million and $482 million as of December 31, 2010 and 2009. These are reported on the Consolidated Balance Sheet within “accrued and other liabilities” and “other long-term liabilities.” A significant portion of these reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that this reserve will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s financial statements. However, even where no reserve has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company, and could require the Company to pay damages or make expenditures in amounts that could be material.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court
found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$1.10 billion ($659 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil were dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás may restart the accounting proceedings at the Fifth District Court at any time, which would proceed according to the AC’s April 2010 decision. In the Fifth District Court proceedings, the expert’s conclusions will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected, and in turn the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. The parties are disputing the proper venue for the CTEEP lawsuit. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In August 2000, the FERC announced an investigation into the organized California wholesale power markets to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. After hearings at FERC, AES Placerita was found subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001. As FERC investigations and hearings progressed, numerous appeals on related issues were filed with the U.S. Court of Appeals for the Ninth Circuit. Over the years, the Ninth Circuit issued several opinions that had the potential to expand the scope of the FERC proceedings and increase refund exposure for AES Placerita and other sellers of electricity. Following remand of one of the Ninth Circuit appeals in March 2009, FERC started a new hearing process involving AES Placerita and other sellers. In May 2009, AES Placerita entered into a settlement, approved by FERC in July 2009, concerning the claims before FERC against AES Placerita relating to the California energy crisis of 2000-2001, including the California refund proceeding. Pursuant to the settlement, AES Placerita paid $6 million and assigned a receivable of $168,119 due to it from the California Power Exchange in return for a release of all claims against it at FERC by the settling parties and other consideration. More than 98% of the buyers in the market elected to join the settlement. A small amount of AES Placerita’s settlement payment was placed in escrow for buyers that did not join the settlement (“non-settling parties”). It is unclear whether the escrowed funds will be enough to satisfy any additional sums that might be determined to be owed to
non-settling parties at the conclusion of the FERC proceedings concerning the California energy crisis. However, any such additional sums are expected to be immaterial to the Company’s consolidated financial statements. In November 2009, one non-settling party, the Sacramento Municipal Utility District (“SMUD”), filed an appeal of the FERC’s approval of the settlement which is pending in the Ninth Circuit. SMUD’s appeal has been stayed pending further order of the court. The settlement agreement is still effective and will continue to remain effective unless it is vacated by the Ninth Circuit. SMUD has reached a settlement in principal with buyers of electricity that, if approved by FERC, will leave only immaterial claims of non-settling parties against AES Placerita.
In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd. (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. In September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd.’s (“OPGC”), an equity method investment, and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPAs terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter is awaiting further hearing.
Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA’s terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified AES Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgás and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers, and requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FSCP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney’s office has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul
and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Public Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($4 million). The injunction was rejected and the case is in the evidentiary stage awaiting the judge’s determination concerning the production of expert evidence. The above-referenced proposal was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response, Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. It is estimated that remediation could cost approximately R$14.7 million ($9 million). Discussions between Sul and CEEE are ongoing.
In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”) filed lawsuits against Itabo, an affiliate of the Company, in the First and Fifth Chambers of the Civil and Commercial Court of First Instance for the National District. CDEEE alleges in both lawsuits that Itabo spent more than was necessary to rehabilitate two generation units of an Itabo power plant and, in the Fifth Chamber lawsuit, that those funds were paid to affiliates and subsidiaries of AES Gener and Coastal Itabo, Ltd. (“Coastal”), a former shareholder of Itabo, without the required approval of Itabo’s board of administration. In the First Chamber lawsuit, CDEEE seeks an accounting of Itabo’s transactions relating to the rehabilitation. In November 2004, the First Chamber dismissed the case for lack of legal basis. On appeal, in October 2005 the Court of Appeals of Santo Domingo ruled in Itabo’s favor, reasoning that it lacked jurisdiction over the dispute because the parties’ contracts mandated arbitration. The Supreme Court of Justice is considering CDEEE’s appeal of the Court of Appeals’ decision. In the Fifth Chamber lawsuit, which also names Itabo’s former president as a defendant, CDEEE seeks $15 million in damages and the seizure of Itabo’s assets. In October 2005, the Fifth Chamber held that it lacked jurisdiction to adjudicate the dispute given the arbitration provisions in the parties’ contracts. The First Chamber of the Court of Appeal ratified that decision in September 2006. In a related proceeding, in May 2005, Itabo filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel CDEEE to arbitrate its claims. The petition was denied in July 2005. Itabo’s appeal of that decision to the U.S. Court of Appeals for the Second Circuit has been stayed since September 2006. Further, in September 2006, in an International Chamber of Commerce arbitration, an arbitral tribunal determined that it lacked jurisdiction to decide arbitration claims concerning these disputes. Itabo believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In April 2006, a putative class action was filed in the U.S. District Court for the Southern District of Mississippi (“District Court”) on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions contributed to alleged global
warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs subsequently appealed to the U.S. Court of Appeals for the Fifth Circuit, which, in October 2009, affirmed the District Court’s dismissal of the plaintiffs’ unjust enrichment, fraudulent misrepresentation, and civil conspiracy claims. However, the Fifth Circuit reversed the District Court’s dismissal of the plaintiffs’ public and private nuisance, trespass, and negligence claims, and remanded those claims to the District Court for further proceedings. In February 2010, the Fifth Circuit granted the petitions for en banc rehearing filed by the Company and other defendants, and thereby vacated its October 2009 decision. In May 2010, the Fifth Circuit dismissed the appeal on the ground that it had lost its quorum for en banc review. In August 2010, the plaintiffs filed a petition for a writ of mandamus in the U.S. Supreme Court, requesting the Supreme Court to direct the Fifth Circuit to reinstate the appeal and return it to the panel that issued the October 2009 decision. In January 2011, the Supreme Court denied the petition, ending the case.
In July 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan (the “Competition Committee”) ordered Nurenergoservice, an AES subsidiary, to pay approximately KZT 18 billion ($120 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee’s order was affirmed by the economic court in April 2008 (“April 2008 Decision”). The economic court also issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. Nurenergoservice’s subsequent appeals to the court of appeals were rejected. In February 2009, the Antimonopoly Agency (the Competition Committee’s successor) seized approximately KZT 783 million ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. However, on appeal to the Kazakhstan Supreme Court, in October 2009, the Supreme Court annulled the decisions of the lower courts because of procedural irregularities and remanded the case to the economic court for reconsideration. On remand, in January 2010, the economic court reaffirmed its April 2008 Decision. Nurenergoservice’s appeals in the court of appeals (first panel) and the court of appeals (second panel) were unsuccessful. Nurenergoservice intends to file a further appeal to the Kazakhstan Supreme Court. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately KZT 1.8 billion ($12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court was rejected in February 2009. Given the adverse court decisions against Nurenergoservice, the Antimonopoly Agency may attempt to seize Nurenergoservice’s remaining assets, which are immaterial to the Company’s consolidated financial statements. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious defenses to the claims asserted against it; however, there can be no assurances that it will prevail in these proceedings.
In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”), in January through February 2009. The investigation of Shulbinsk HPP is ongoing, but the investigation of UK HPP has been completed. The Antimonopoly Agency determined that UK HPP abused its market position and charged monopolistically high prices for power in January through February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($3 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of UK HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
In April 2009, the Antimonopoly Agency initiated an investigation of Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales in 2008 through February 2009. The Antimonopoly Agency subsequently concluded that UKT abused its market position and charged monopolistically high prices for power and should pay an administrative fine of approximately KZT 136 million ($1 million). The Antimonopoly Agency later sought an order from the administrative court requiring UKT to pay the fine. The administrative court proceedings have been suspended due to a related criminal investigation of UKT employees. If the investigation is terminated and the Antimonopoly Agency prevails in the administrative proceedings, UKT may be ordered to pay the administrative fine and disgorge the profits from the sales at issue, estimated by the Antimonopoly Agency to be approximately 514 million KZT ($3 million). UKT believes it has meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In December 2007, an arbitral tribunal terminated ESSA’s gas supply contracts with members of the Sierra Chata Consortium in light of the restrictions that had been placed on the export of gas by the Argentine Republic. ESSA thereafter terminated its gas transportation contract with Transportadora de Gas del Norte S.A. (“TGN”), and initiated arbitration seeking relief from the obligation to pay the firm tariff under ESSA’s gas transportation contracts with Gasoducto GasAndes (Argentina) S.A. (“GasAndes Argentina”) and Gasoducto GasAndes S.A. (“GasAndes Chile”) or in the alternative, termination of such contracts. TGN (which later filed a lawsuit against ESSA in Argentina), GasAndes Argentina, and GasAndes Chile disputed that the restrictions on the export of gas justified the adjustment or termination of the respective gas transportation contracts and sought due tariff payments. On December 29, 2010, ESSA reached settlement agreements with GasAndes Argentina, GasAndes Chile, and TGN terminating the respective gas transportation contracts and resolving all pending legal disputes and potential future claims. ESSA recognized approximately $72 million as other expense for the three months ended December 31, 2010 related to the settlement agreements. Upon termination of the TGN gas transportation contract, ESSA is no longer required to pay certain charges imposed by the Argentine Republic relating to gas supply infrastructure.
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions have contributed to alleged global warming which, in turn, allegedly has led to the erosion of the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit. The parties have briefed the appeal and are awaiting a date for oral argument. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In July, 1993 the Public Attorney’s office filed a claim against Eletropaulo, the Sao Paulo State Government, SABESP (a state-owned company), CETESB (a state-owned company) and DAEE (the municipal Water and Electric Energy Department) alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from the Pinheiros River into the Billings Reservoir. The events in question occurred while Eletropaulo was a state-owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately R$670 million ($401 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. In 2009, the Public Attorney’s Office has filed appeals to both Superior Court of Justice (“SCJ”) and the Supreme Court (“SC”) and such appeals were answered by Eletropaulo in the fourth quarter of 2009. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the
Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of Sao Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1 million ($599 thousand) as of December 31, 2010, or pay an indemnification amount of approximately R$10.2 million ($6 million). Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.
In February 2009, a CAA Section 114 information request from the EPA regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. Cayuga and Somerset responded to the EPA’s information request in June 2009, and they are awaiting a response from the EPA regarding their submittal. At this time, it is not possible to predict what impact, if any, this request may have on the Company, its results of operations or its financial position.
On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation (“NYSDEC”) that the facility had exceeded the permitted volume limit of coal ash that can be disposed of in the on-site landfill. Cayuga has met with NYSDEC and submitted a Landfill Liner Demonstration Report to them. Such report found that the landfill has adequate engineering integrity to support the additional coal ash and there is no inherent environmental threat. NYSDEC has indicated they accept the finding of the report. A permit modification was approved by the NYSDEC on May 14, 2010 and such permit modification allows for closure of this approximately 10-acre portion of the landfill. The construction in accordance with the approved permit modification was completed in November 2010 and the certification report for this construction project is currently being drafted to submit to the NYSDEC in the second quarter of 2011. While at this time it is not possible to predict what impact, if any, this matter may have on the Company, its results of operations or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Esado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. The procedural schedules for the arbitrations have been established but the hearing dates have not been scheduled to date. AESU believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously; however, there can be no assurances that it will be successful in its efforts.
In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals (“VCA”) that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant stopped as a consequence of the Supreme Court’s decision. In December 2009, Chilean authorities approved new land use regulations that entitled EEC to apply for a new environmental permit. EEC applied for a new environmental permit in January 2010 and permit approval was granted by the Environmental Authority in February 2010. In March 2010, the Mayor of Puchuncaví and another third party challenged the new environmental permit before the VCA. The parties later entered into a settlement agreement pursuant to which the challenge to the new environmental permit
was withdrawn in July 2010. In addition, the construction permit that is required to resume construction of the Plant was issued by the Municipality in August 2010. In September 2010, neighbors of Puchuncaví challenged the construction permit filing claims in the VCA. In November 2010, the VCA rejected the claims. The challenging parties subsequently filed appeals with the Supreme Court. In January 2011, the Supreme Court confirmed the decision of the VCA, finally rejecting the constitutional action. EEC has resumed construction of the Plant.
In June 2009, the Inter-American Commission on Human Rights of the Organization of American States (“IACHR”) requested that the Republic of Panama suspend the construction of AES Changuinola S.A.’s hydroelectric project (“Project”) until the bodies of the Inter-American human rights system can issue a final decision on a petition (286/08) claiming that the construction violates the human rights of alleged indigenous communities. In July 2009, Panama responded by informing the IACHR that it would not suspend construction of the Project and requesting that the IACHR revoke its request. In June 2010, the Inter-American Court of Human Rights vacated the IACHR’s request. With respect to the merits of the underlying petition, the IACHR heard arguments by the communities and Panama in November 2009, but has not issued a decision to date. The Company cannot predict Panama’s response to any determination on the merits of the petition by the bodies of the Inter-American human rights system.
In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that the proceeds of the sale of electricity from AES Cartagena’s plant should be reduced by roughly the value of the CO2 allowances that were granted to AES Cartagena for free for the years 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately 20 million ($27 million) for 2007-2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for 523,548 (approximately $694,000) for the allowances granted for free for 2007 and 19,907,248 (approximately $26 million) for 2008. In July 2010, AES Cartagena received an invoice for approximately 5.4 million ($7 million) for the allowances granted for free for the first half of 2009. AES Cartagena does not expect to be charged for CO2 allowances issued free of charge for subsequent periods. AES Cartagena has paid the amounts invoiced and has filed challenges to the CNE’s demands in the Spanish judicial system. There can be no assurances that the challenges will be successful. AES Cartagena has demanded indemnification from its fuel supply and electricity toller, GDF-Suez, in relation to the CNE invoices under the long-term energy agreement (the “Energy Agreement”) with GDF-Suez. However, GDF-Suez has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena initiated arbitration against GDF-Suez, seeking to recover the payments made to CNE. In the arbitration, AES Cartagena also seeks a determination that GDF-Suez is responsible for procuring and bearing the cost of CO2 allowances that are required to offset the CO2 emissions of AES Cartagena’s power plant, which is also in dispute between the parties. To date, AES Cartagena has paid approximately 20 million ($27 million) for the CO2 allowances that have been required to offset 2008 and 2009 CO2 emissions. AES Cartagena expects that allowances will need to be purchased to offset emissions for subsequent years. The evidentiary hearing in the arbitration took place from May 31-June 4, 2010, and closing arguments were heard on September 1, 2010. In February 2011, the arbitral tribunal requested further briefing from the parties on certain issues in the arbitration. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected and, in turn, there could be a material adverse effect on the Company and its results of operations. AES Cartagena believes it has meritorious claims and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 2009, the Public Defender’s Office of the State of Rio Grande do Sul (“PDO”) filed a class action against AES Sul in the 16th District Court of Porto Alegre, Rio Grande do Sul (“District Court”), claiming that AES Sul has been illegally passing PIS and COFINS taxes (taxes based on AES Sul’s income) to consumers. According to ANEEL’s Order No. 93/05, the federal laws of Brazil, and the Brazilian Constitution, energy companies such as AES Sul are entitled to highlight PIS and COFINS taxes in power bills to final consumers, as the cost of those taxes is included in the energy tariffs that are applicable to final consumers. Before AES Sul had
been served with the action, the District Court dismissed the lawsuit in October 2009 on the ground that AES Sul had been properly highlighting PIS and COFINS taxes in consumer bills in accordance with Brazilian law. In April 2010, the PDO appealed to the Appellate Court of the State of Rio Grande do Sul (“AC”). In November 2010, the AC affirmed the dismissal. The PDO is expected to appeal. If the dismissal is ever reversed and AES Sul does not prevail in the lawsuit and is ordered to cease recovering PIS and COFINS taxes pursuant to its energy tariff, its potential prospective losses could be approximately R$9.6 million ($6 million) per month, as estimated by AES Sul. In addition, if AES Sul is ordered to reimburse consumers, its potential retrospective liability could be approximately R$1.2 billion ($718 million), as estimated by AES Sul. AES Sul believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings if it is served with the action; however, there can be no assurances that it would be successful in its efforts. Furthermore, if AES Sul does not prevail in the litigation it will seek to adjust its energy tariff to compensate it for its losses, but there can be no assurances that it would be successful in obtaining an adjusted energy tariff.
In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from EPA pursuant to CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to EPA’s Prevention of Significant Deterioration and nonattainment New Source Review (“NSR”) requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff and is currently in discussions with the EPA regarding possible resolutions to this NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties and to install additional pollution control technology on coal-fired electric generating units. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery through customer rates of any operating or capital expenditures related to pollution control technology systems to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In November 2009, April 2010 and December 2010, substantially similar personal injury lawsuits were filed by a total of 26 residents and estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic in October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs do not quantify their alleged damages, but generally allege that they are entitled to compensatory and punitive damages. The AES defendants have moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. (The AES Defendants have until mid-February to respond to the December 2010 lawsuit.) In September 2010, the Superior Court heard arguments on the motions. The Superior Court dismissed the plaintiffs’ fraud allegations without prejudice to replead, and the plaintiffs filed amended complaints in November 2010. The AES defendants have filed a renewed motion to dismiss the amended issues. The remaining claims (other than fraud) addressed in the AES defendants’ original motion to dismiss are still pending. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns an unfinished 670MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond is approximately 155 million ($205 million). However, the Contractor obtained a temporary injunction from a French court preventing the issuing bank from honoring the bond demands. As the performance bond is governed by English law, Maritza obtained a judgment from an English court that the bond should be paid, and then presented this judgment to the French court which issued the temporary injunction. However, on February 10, 2011, the French court issued a decision enjoining the issuing bank from honoring the demands on the performance bond pending the determination of the arbitration between Maritza and the Contractor, described below. Maritza is attempting to
lift that injunction or otherwise obtain payment on its demands. In addition, in December 2010, the Contractor issued a notice of dispute alleging that the lignite that has been supplied by Maritza for commissioning of the power plant is out of specification, allegedly entitling the Contractor to an extension of time to complete the power plant, an increase to the contract price of approximately 62 million ($82 million), and other relief. The Contractor thereafter advised Maritza that it had stopped commissioning of the power plant’s two units because of the characteristics of the lignite supplied, and, in January 2011, initiated arbitration on its lignite claim. Maritza disputes that the lignite is out of specification and intends to defend the arbitration and assert counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC contract. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
ITEM 4.
ITEM 4. REMOVED AND RESERVED
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Recent Sales of Unregistered Securities
On March 12, 2010, the Company and Terrific Investment Corporation (“Investor”), a wholly owned subsidiary of China Investment Corporation, entered into a stockholder agreement (the “Stockholder Agreement”) in connection with the agreement discussed in the following paragraph. Under the Stockholder Agreement, as long as Investor holds more than 5% of the outstanding shares of common stock of the Company, Investor will have the right to designate one nominee, who must be reasonably acceptable to the Board, for election to the Board of Directors of the Company. Investor has not designated its nominee for election to the Board of Directors of the Company. In addition, until such time as Investor holds 5% or less of the outstanding shares of common stock, Investor has agreed to vote its shares in accordance with the recommendation of the Company on any matters submitted to a vote of the stockholders of the Company relating to the election of directors and compensation matters. Otherwise, Investor may vote its shares at its discretion. Further, under the Stockholder Agreement, Investor will be subject to a standstill restriction which generally prohibits Investor from purchasing additional securities of the Company beyond the level acquired by it under the stock purchase agreement entered into between Investor and the Company on November 6, 2009. In addition, Investor has agreed to a lock-up restriction such that Investor would not sell its shares for a period of 12 months following the closing, subject to certain exceptions. The standstill and lock-up restrictions also terminate at such time as Investor holds 5% or less of the outstanding shares of common stock. Investor will have certain registration rights and preemptive rights under the Stockholder Agreement with respect to its shares of common stock of the Company.
On March 15, 2010, the Company completed the sale of 125,468,788 shares of common stock to Investor. The shares were sold for $12.60 per share, for an aggregate purchase price of $1.58 billion. Investor’s ownership in the Company’s common stock is now approximately 15% of the Company’s total outstanding shares of common stock on a fully diluted basis.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In July 2010, the Company’s Board of Directors approved a stock repurchase program under which the Company may repurchase up to $500 million of AES common stock. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. The original authorization was set to expire on December 31, 2010, however; in December 2010, the Board authorized an extension of the stock repurchase program. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time. During the year ended December 31, 2010, shares of common stock repurchased under this plan totaled 8,382,825 at a total cost of $99 million plus a nominal amount of commissions (average of $11.86 per share including commissions). There was $401 million remaining under the stock repurchase program available for future repurchases at December 31, 2010.
The following table presents information regarding purchases made by The AES Corporation of its common stock in the fourth quarter of 2010:
Market Information
Our common stock is currently traded on the New York Stock Exchange (“NYSE”) under the symbol “AES.” The closing price of our common stock as reported by the NYSE on February 23, 2011, was $12.25, per share. The Company repurchased 8,382,825 and 10,691,267 shares of its common stock in 2010 and 2008, respectively, and did not repurchase any of its common stock in 2009. The following tables set forth the high and low sale prices, and performance trends for our common stock as reported by the NYSE for the periods indicated:
Performance Graph
THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE
Source: Bloomberg
We have selected the Standard and Poor’s (“S&P”) 500 Utilities Index as our peer group index. The S&P 500 Utilities Index is a published sector index comprising the 32 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 2005 in AES Common Stock, the S&P 500 Index and the S&P 500 Utilities Index. The information included under the heading “Performance Graph” shall not be considered “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934.
Holders
As of February 23, 2011, there were approximately 7,379 record holders of our common stock.
Dividends
We do not currently pay dividends on our common stock. We intend to retain our future earnings, if any, to finance the future development and operation of our business. Accordingly, we do not anticipate paying any dividends on our common stock in the foreseeable future.
Under the terms of our senior secured credit facility, which we entered into with a commercial bank syndicate, we have limitations on our ability to pay cash dividends and/or repurchase stock. In addition, under the terms of a guaranty we provided to the utility customer in connection with the AES Thames project, we are precluded from paying cash dividends on our common stock if we do not meet certain net worth and liquidity tests.
Our project subsidiaries’ ability to declare and pay cash dividends to us is subject to certain limitations contained in the project loans, governmental provisions and other agreements to which our project subsidiaries are subject.
See the information contained under the caption “Securities Authorized for Issuance under Equity Compensation Plans” of the Proxy Statement for the 2010 Annual Meeting of Shareholders of the Registrant, which information is incorporated herein by reference.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data as of the dates and for the periods indicated. You should read this data together with Item 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of Our Business
We are a global power company. We operate two primary lines of business. 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, other intermediaries and certain end-users. The second is our Utilities business, where we own and/or operate utilities to distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. For the year ended December 31, 2010, our Generation and Utilities businesses comprised approximately 45% and 55% of our consolidated revenue, respectively.
We are also continuing to expand our wind and solar generation businesses. These initiatives are not material contributors to our operating results at this time, but we believe that certain of these initiatives may become material in the future. For additional information regarding our business, see Item 1.-Business of this Form 10-K.
Our Organization and Segments. Our management 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”), each managed by a regional president. The financial reporting segment structure uses our management reporting structure as its foundation and reflects how we manage the business internally. Based on our application of the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, we have concluded that the Company has the following six reportable segments:
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Latin America-Generation;
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Latin America-Utilities;
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North America-Generation;
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North America-Utilities;
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Europe-Generation;
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Asia-Generation.
We report the Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation and Climate Solutions operating segments within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our financial statement presentation of reportable segments, individually or in the aggregate. “Corporate and Other” also includes corporate overhead costs 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.
During the second quarter of 2010, the Company modified its internal reporting structure to move the management of the Company’s generation business in Jordan, Amman East, from Asia to Europe. Accordingly, Amman East is now reported within the Europe-Generation segment. All prior periods have been retrospectively restated to reflect this change and conform to current period presentation.
Key Drivers of Our Results of Operations. Our Generation and Utilities businesses are distinguished by the nature of their customers, operational differences, cost structure, regulatory environment and risk exposure. As a result, each line of business has slightly different drivers which affect operating results. Performance drivers for our Generation businesses include, among other things, plant reliability and efficiency, power prices, volume,
management of fixed and variable operating costs, management of working capital including collection of receivables, and the extent to which our plants have hedged their exposure to currency and commodities such as fuel. For our Generation businesses which sell power under short-term contracts or in the spot market, the most crucial factors are the current market price of electricity and the marginal costs of production. Growth in our Generation business is largely tied to securing new PPAs, expanding capacity in our existing facilities and building or acquiring new power plants. Performance drivers for our Utilities businesses include, but are not limited to, reliability of service; management of working capital, including collection of receivables; negotiation of tariff adjustments; compliance with extensive regulatory requirements; and in developing countries, reduction of commercial and technical losses. The operating results of our Utilities businesses are sensitive to changes in economic growth and weather conditions in areas in which they operate. In addition to these drivers, as further explained below, the Company also has exposure to currency exchange rate fluctuations.
One of the key factors which affect our Generation business is our ability to enter into contracts for the sale of electricity and the purchase of fuel used to produce that electricity. Long-term contracts are intended to reduce exposure to volatility associated with fuel prices in the market and the price of electricity by fixing the revenue and costs for these businesses. The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. In turn, most of these businesses enter 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. While these long-term contractual agreements reduce exposure to volatility in the market price for electricity and fuel, the predictability of operating results and cash flows vary by business based on the extent to which a facility’s generation capacity and fuel requirements are contracted and the negotiated terms of these agreements. Entering into these contracts exposes us to counterparty credit risk. For further discussion of these risks, see “Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks” in Item 1A.-Risk Factors of this Form 10-K.
When fuel costs increase, many of our businesses are able to pass these costs on to their customers. Generation businesses with long-term contracts in place do this by including fuel pass-through or fuel indexing arrangements in their contracts. Utilities businesses can pass costs on to their customers through increases in current or future tariff rates. Therefore, in a rising fuel cost environment, the increased fuel costs for these businesses often result in an increase in revenue to the extent these costs can be passed through (though not necessarily on a one-for-one basis). Conversely, in a declining fuel cost environment, the decreased fuel costs can result in a decrease in revenue. Increases or decreases in revenue at these businesses that have the ability to pass through costs to the customer have a corresponding impact on cost of sales, to the extent the costs can be passed through, resulting in a limited impact on gross margin, if any. Although these circumstances may not have a large impact on gross margin, they can significantly affect gross margin as a percentage of revenue. As a result, gross margin as a percentage of revenue is a less relevant measure when evaluating our operating performance. To the extent our businesses are unable to pass through fuel cost increases to their customers, gross margin may be adversely affected.
Global diversification also helps us mitigate risk. Our presence in mature markets helps mitigate the exposure associated with our businesses in emerging markets. Additionally, our portfolio employs a broad range of fuels, including coal, gas, fuel oil, water (hydroelectric power), wind and solar, which reduces the risks associated with dependence on any one fuel source. However, to the extent the mix of fuel sources enabling our generation capabilities in any one market is not diversified, the spread in costs of different fuels or the availability of natural resources such as water for hydroelectric power production or wind may also influence the operating performance and the ability of our subsidiaries to compete within that market. For example, in a market where gas prices fall to a low level compared to coal prices, power prices may be set by low gas prices which can affect the profitability of our coal plants in that market. In certain cases, we may attempt to hedge fuel prices to manage this risk, but there can be no assurance that these strategies will be effective.
We also attempt to limit risk by hedging much of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. However, we only hedge a
portion of our currency and commodity risks, and our businesses are still subject to these risks, as further described in Item 1A.-Risk Factors of this Form 10-K, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” Commodity and power price volatility could continue to impact our financial metrics to the extent this volatility is not hedged. For a discussion of our sensitivities to commodity, currency and interest rate risk, see Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks
We are a global company in the power generation and distribution businesses. We own and/or operate power plants to generate and sell power to wholesale customers. We also own and/or operate utilities to distribute, transmit and sell electricity to end-user customers. Our primary market risk exposure is to the price of commodities particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at the subsidiary level and between our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.
These disclosures set forth in this Item 7A are based upon a number of assumptions, and actual impacts to the Company may not follow the assumptions made by the Company. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 7A. For further information regarding market risk, see Item 1A.-Risk Factors, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations”, “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” and “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” in this Form 10-K.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the price of electricity, fuels and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions, a portion of our current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.
When hedging the output of our generation assets, we have PPAs or other hedging instruments that lock in the spread per MWh between variable costs, such as fuel, to generate a unit of electricity and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements will be exposed to commodity price risk.
AES businesses will see variance in variable margin performance as global commodity prices shift. For 2011, including operations from the Company’s merchant generation assets in New York, we project pre-tax earnings exposure would be approximately $10 million for a $10/barrel move in oil, $110 million for a $1/MMBTU move in natural gas, and $50 million for a $10/ton shift in coal prices. Excluding New York, we project approximately $35 million for a $1/MMBTU move in natural gas and $35 million for a $10/ton shift in coal prices. The decrease in oil exposure from $15 million on December 31, 2009 is primarily due to higher hedge levels at some businesses and lower hedging of fuel costs at our Hungarian facility where fuel cost is indexed to oil partially offset by higher exposure at Gener due to the commissioning of new power facilities. The increase in natural gas exposure from $50 million on December 31, 2009 is primarily due to lower hedging levels at Eastern Energy, due to dark spread compression, and our Kilroot facility, which is no longer operating under a long-term PPA. The increase in coal exposure from $20 million on December 31, 2009 arises primarily from the lower hedge levels at Eastern Energy, Kilroot long-term PPA termination, Argentina pricing rules that limit the ability to reflect coal price movement under some conditions, and inclusion of China due to a delay in energy tariff resets intended to reflect changes in coal prices. These numbers have been produced by forecasting the impact of a change in commodity price to spot power prices and power and fuel contracts held by each business. Our estimates exclude correlation. For example, a decline in oil or natural gas prices can be accompanied by a decline
in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed.
Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Generation costs can be directly affected by movements in the price of natural gas, oil and coal. Spot power prices and contract indexation provisions are affected by these same commodity price movements. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Variance is not perfectly linear or symmetric. The sensitivities are affected by a number of non-market, or indirect market, factors. Examples of these factors include hydrology, energy market supply/demand balances, regional fuel supply issues, and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, power plants may reduce dispatch in low market environments limiting downside exposure. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.
Our larger contributors to commodity risk include Eastern Energy and wholesale power sales from IPL in North America; Gener, Argentina, the Dominican Republic and Panama in Latin America; Kilroot in Europe; and Masinloc in Asia.
In North America, commodity risk is due to “dark spread” to the extent a portion of sales are un-hedged. Given that natural gas-fired generators set power prices for many periods, higher natural gas prices expand margins and higher coal prices cause a decline in margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure.
In Chile, we own assets and have associated contracts in both the central and northern regions of the country. Contracts tend to be long-term and indexed to fuel limiting commodity risk. Oil-fired generators set power prices for some periods impacting spot power margins. Gener has been adding coal-fired generation to its portfolio, increasing its exposure to dark spreads on un-hedged volumes. Gener also owns natural gas/diesel, hydropower and biomass generation facilities.
In other Latin American markets, the businesses have commodity exposure on un-hedged volumes. In Panama and Colombia, we own hydropower assets, so contracts are not indexed to fuel. In the Dominican Republic, we own natural gas-fired and coal-fired assets, and both contract and spot prices may move with commodity prices. In Argentina, prices are set according to government rules that result in commodity exposure based on the spread between cost of coal-fired generation and oil-fired generation and other factors.
In Europe, our Kilroot facility’s long term PPA was terminated during the fourth quarter of 2010. The commodity risk at our Kilroot business is due to “dark spread” to the extent sales are un-hedged. Natural gas-fired generators set power prices for many periods, so higher natural gas prices expand margins and higher coal prices cause a decline. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods.
Our Masinloc business in Asia is a coal-fired generation facility, which hedges its output through medium term contracts that are indexed to fuel prices. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.
Foreign Exchange Rate Risk
In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. Primarily, we are exposed to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Cameroonian Franc, Chilean Peso, Colombian Peso, Euro, Kazakhstani Tenge, Mexican Peso, and Philippine Peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.
During 2010, we entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. As of December 31, 2010, assuming a 10% U.S. Dollar appreciation, 2011 pre-tax earnings attributable to foreign subsidiaries exposed to movements in the exchange rates of the Brazilian Real, Chilean Peso, Philippine Peso and Euro (the earnings attributable to subsidiaries exposed to Cameroonian Franc movements are included under Euro due to the fixed exchange rate of the Cameroonian Franc to the Euro) relative to the U.S. Dollar are projected to be approximately $40 million, $15 million, $10 million, and $20 million, respectively, and represent the majority of the Company’s pre-tax earnings exposure to currency moves. The increases relative to December 31, 2009 figures, which were $35 million, $10 million, $5 million and $10 million for the Brazilian Real, Chilean Peso, Philippine Peso and Euro, respectively, are primarily driven by forecasted increases in the foreign currency denominated pre-tax earnings notably attributable to businesses in Brazil, Chile, the Philippines and Europe. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pre-tax earnings for 2011 coming from subsidiaries where the local currency is either not the U.S. Dollar or is not exhibiting the characteristics of a peg or managed float relative to the U.S. Dollar, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges unwound. Additionally, updates to the forecasted pre-tax earnings exposed to foreign exchange risk may result in further modification.
Interest Rate Risks
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements.
Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.
As of December 31, 2010, the portfolio’s 2011 pre-tax earnings exposure (adjusted to reflect noncontrolling interests) to a 100 basis point increase in Brazilian Real, British Pound, Colombian Peso, Euro, Philippine Peso, Ukraine Hryvnia and U.S. Dollar interest rates would be approximately $25 million. This number is based on the impact of a one-time, 100 basis point increase in interest rates on interest expense for Brazilian Real, British Pound, Colombian Peso, Euro, Philippine Peso, Ukraine Hryvnia and U.S. Dollar-denominated debt, which is primarily non-recourse financing. The numbers do not take into account the historical correlation between these interest rates. This compares to $20 million as of December 31, 2009. The increase is driven by an increase in the notional amount of floating rate debt in the portfolio.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries as of December 31, 2010 and December 31, 2009, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedules listed in the index at Item 15(a). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The AES Corporation and subsidiaries at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, in 2010 The AES Corporation and subsidiaries changed their method of accounting for the consolidation of variable interest entities with the adoption of amendments to Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 810, Consolidation, and their method of accounting for transfers and servicing of financial assets with the adoption of the amendments to FASB ASC 860, Transfers and Servicing, both effective January 1, 2010.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The AES Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011 expressed an unqualified opinion thereon.
/s/: Ernst & Young LLP
McLean, Virginia
February 25, 2011
THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2010 AND 2009
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010, 2009, AND 2008
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The AES Corporation is a holding company (the “Parent Company”) that through its subsidiaries and affiliates, (collectively, “AES” or “the Company”) operates a geographically diversified portfolio of electricity generation and distribution businesses. Generally, given this holding company structure, the liabilities of the individual operating entities are not recourse to the parent and are isolated to the operating entities. Most of our operating entities are structured as corporations, therefore limiting the liability of the shareholders. The structure is generally the same regardless of whether a subsidiary is consolidated under a voting or variable interest model.
PRINCIPLES OF CONSOLIDATION-The Consolidated Financial Statements of the Company include the accounts of The AES Corporation, its subsidiaries and controlled affiliates, and variable interest entities (“VIEs”) of which the Company is the primary beneficiary. All intercompany transactions and balances have been eliminated in consolidation.
A VIE is an entity (a) that has a total equity investment at risk that is not sufficient to finance its activities without additional subordinated financial support or (b) where the group of equity holders does not have (i) the ability to make significant decisions about the entity’s activities, (ii) the obligation to absorb the entity’s expected losses or (iii) the right to receive the entity’s expected residual returns or (c) where the voting rights of some equity holders are not proportional to their obligations to absorb expected losses, receive expected residual returns, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights.
Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on the consolidation of VIEs. The new guidance requires an entity to determine qualitatively, rather than quantitatively, the primary beneficiary of a VIE. This determination is based on whether the entity has the power to direct the activities that most significantly impact the economic performance of the VIE and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Other key changes include: a requirement for the ongoing reconsideration of the primary beneficiary, the criteria used for determining whether service provider or decision maker contracts are variable interests, the consideration of kick-out and removal rights in determining whether an entity is a VIE, the types of events that trigger the reassessment of whether an entity is a VIE and expansion of the disclosures previously required.
The determination of which party has the power to direct the activities that most significantly impact the economic performance of the VIE could require significant judgment and assumptions. That determination considers the purpose and design of the business, the risks that the business was designed to create and pass along to other entities, the activities of the business that can be directed and which party can direct them, and the expected relative impact of those activities on the economic performance of the business through its life. The businesses for which significant judgment and assumptions were required were primarily certain generation businesses who have power purchase agreements (“PPAs”) to sell energy exclusively or primarily to a single counterparty for the term of those agreements. For these generation businesses, the counterparty has the power to dispatch energy and, in some instances, to make decisions regarding the sale of excess energy. As such, the counterparty has the power to direct certain activities that significantly impact the economic performance of the business primarily through the cash flows and gross margin, if any, earned by the business from the sale of energy to the counterparty and sometimes through the counterparty’s absorption of fuel price risk. However, the counterparty usually does not have the power to direct any of the other activities that could significantly impact the economic performance. These other activities include: daily operation and management, maintenance, repairs and capital expenditures, plant expansion, decisions regarding the overall financing of ongoing operations and budgets and, in some instances, decisions regarding the sale of excess energy. As such, AES has the power to
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
direct some activities of the business that significantly impact its economic performance, primarily through the cash flows and gross margin earned from capacity payments received from being available to produce energy and from the sale of energy to other entities (particularly during any period beyond the end of the power purchase agreement). For these businesses, the determination as to which set of activities most significantly impact the economic performance of the business requires significant judgment and the use of assumptions. The Company concluded that the activities directed by the counterparty were less significant than those directed by AES.
The adoption of the new accounting guidance on the consolidation of VIEs resulted in the deconsolidation of certain immaterial VIEs previously consolidated. Additionally, assets, liabilities and operating results of two of the Company’s VIEs, previously accounted for under the equity method of accounting, were required to be consolidated. Cartagena, a 71% owned generation business in Spain, and Cili, a 51% owned generation business in China, were consolidated under the new guidance. This resulted in a cumulative effect adjustment of $47 million to retained earnings as of January 1, 2010. The cumulative effect adjustment is primarily comprised of losses that were not recognized while the equity method of accounting was suspended for Cartagena. The equity method of accounting was suspended in December 2008 when the Company’s basis in its investment in Cartagena was reduced to zero. As of December 31, 2010, total assets and total liabilities related to these VIEs were $850 million and $919 million, respectively. In addition, revenue for the year ended December 31, 2010 included $416 million of revenue from these VIEs. Prior period operating results of these VIEs are reflected in “Net equity in earnings of affiliates” except for those prior periods during which the equity method of accounting was suspended.
USE OF ESTIMATES-The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Items subject to such estimates and assumptions include: the carrying value and estimated useful lives of long-lived assets; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of deferred regulatory assets; the valuation of certain financial instruments; the determination of noncontrolling interest using the hypothetical liquidation at book value (“HLBV”) method for certain wind generation partnerships; pension liabilities; environmental liabilities; and potential litigation claims and settlements.
DISCONTINUED OPERATIONS AND RECLASSIFICATIONS-A discontinued operation is a component of the Company that either has been disposed of or is classified as held for sale. A component of the Company comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the Company. In accordance with the accounting standards on the impairment or disposal of long-lived assets, the prior period Consolidated Financial Statements in this Form 10-K have been restated to reflect the businesses determined to be discontinued operations, as further discussed in Note 21-Discontinued Operations and Held for Sale Businesses. The Company has reclassified certain of its trade related payables from accrued and other liabilities to accounts payable within the Consolidated Financial Statements to conform to current year presentation.
FAIR VALUE-Fair value, as defined in the fair value measurement accounting guidance, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The Company applies the fair value measurement accounting guidance for financial assets and liabilities to determine the fair value of short and long term investments in marketable debt and equity securities, included in the consolidated balance sheet line items “Short-term investments” and “Other assets (noncurrent),” derivative assets, included in “Other current assets” and “Other
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
assets (noncurrent)” and derivative liabilities, included in “Accrued and other liabilities (current)” and “Other long-term liabilities.” The Company applies the fair value measurement guidance for nonfinancial assets upon the acquisition of a business in accordance with the accounting guidance for business combinations or in conjunction with the measurement of an impairment loss on an asset group or reporting unit under the accounting guidance for the impairment of long-lived assets or goodwill.
The fair value measurement accounting guidance requires that the Company make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity.
Fair value, where available, is based on observable quoted market prices. Where observable prices or inputs are not available, several valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity.
To increase consistency and enhance disclosure of the fair value of financial instruments, the fair value measurement accounting guidance creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:
Level 1-unadjusted quoted prices in active markets accessible by the reporting entity for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2-pricing inputs other than quoted market prices included in Level 1 which are based on observable market data, that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from observable market data by correlation or other means. The fair value of most over-the-counter derivatives derived from internal valuation models using market inputs and most investments in marketable debt securities qualify as Level 2.
Level 3-pricing inputs that are unobservable, or less observable, from objective sources. Unobservable inputs are only used to the extent observable inputs are not available. These inputs maintain the concept of an exit price from the perspective of a market participant and should reflect assumptions of other market participants. An entity should consider all market participant assumptions that are available without unreasonable cost and effort. These are given the lowest priority and are generally used in internally developed methodologies to generate management’s best estimate of the fair value when no observable market data is available. The fair value of the Company’s reporting units determined using a discounted cash flows valuation model for goodwill impairment assessment and the fair value of the Company’s long-lived asset groups determined using a discounted cash flows valuation model for the long-lived asset impairment assessments qualify as Level 3.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Any transfers between the fair value hierarchy levels are recognized at the end of the reporting period.
CASH AND CASH EQUIVALENTS-The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit and short-term marketable securities, with an original or remaining maturity at the date of acquisition of three months or less, to be cash and cash equivalents. The carrying amount of such balances approximate fair value.
RESTRICTED CASH-Restricted cash includes cash and cash equivalents which are restricted as to withdrawal or usage. The nature of restrictions includes restrictions imposed by financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves and others, as well as restrictions imposed by long-term PPAs.
INVESTMENTS IN MARKETABLE SECURITIES-Short-term investments in marketable debt and equity securities consist of securities with original or remaining maturities in excess of three months but less than one year. The Company’s marketable investments are primarily certificates of deposit, government debt securities and money market funds.
Marketable debt securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at amortized cost. Other marketable securities that the Company does not intend to hold to maturity are classified as available-for-sale or trading and are carried at fair value. Available-for-sale investments are marked-to-market at the end of each reporting period, with unrealized holding gains or losses, which represent changes in the market value of the investment, reflected in accumulated other comprehensive income (“AOCI”), a separate component of stockholders’ equity. In measuring the other-than-temporary impairment of debt securities, the Company identifies two components: 1) the amount representing the credit loss, which is recognized as “other non-operating expense” in the Consolidated Statements of Operations; and 2) the amount related to other factors, which is recognized in AOCI unless there is a plan to sell the security, in which case it would be recognized in earnings. The amount recognized in AOCI for held-to-maturity debt securities is then amortized over the remaining life of the security.
Investments classified as trading are marked-to-market on a periodic basis through the Consolidated Statements of Operations. Interest and dividends on investments are reported in interest income and other income, respectively. Gains and losses on sales of investments are determined using the specific identification method.
See Note 4-Fair Value and the Company’s fair value policy for additional discussion regarding the determination of the fair value of the Company’s investments in marketable debt and equity securities.
ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS-Accounts and Notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectable amount as appropriate. Certain of our businesses charge interest on accounts receivable either under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. In situations where the collection of interest is uncertain, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectible. Included in “Noncurrent Other Assets” are long-term financing receivables of $151 million, primarily with certain Latin American governmental
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
bodies. These receivables have contractual maturities of greater than one year and are being collected in installments. Of the total $151 million, amounts of $81 million and $55 million, respectively, relate to our businesses in Argentina and the Dominican Republic. The remaining amount relates to our distribution businesses in Brazil.
INVENTORY-Inventory primarily consists of coal, fuel oil and other raw materials used to generate power, and spare parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost or market. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. Cost is determined under the first-in, first-out (“FIFO”), average cost or specific identification method. Generally, cost is reduced to market value if the market value of inventory has declined and it is probable that the utility of inventory, in its disposal in the ordinary course of business, will not be recovered through revenue earned from the generation of power.
LONG-LIVED ASSETS-Long-lived assets include property, plant and equipment, assets under capital leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).
Property, plant and equipment
Property, plant and equipment are stated at cost, net of accumulated depreciation. The cost of renewals and improvements that extend the useful life of property, plant and equipment are capitalized.
Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the project is deemed probable, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Construction in progress balances are transferred to electric generation and distribution assets when an asset group is ready for its intended use. Government subsidies are recorded as a reduction to property, plant and equipment and reflected in cash flows from investing activities.
Depreciation, after consideration of salvage value and asset retirement obligations, is computed primarily using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Maintenance and repairs are charged to expense as incurred. Capital spare parts, including rotable spare parts, are included in electric generation and distribution assets. If the spare part is considered a component, it is depreciated over its useful life after the part is placed in service. If the spare part is deemed part of a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.
Intangible Assets Subject to Amortization
Finite-lived intangible assets are amortized over their useful lives which range from 1- 89 years. The Company accounts for purchased emission allowances as intangible assets and records an expense when utilized or sold. Granted allowances are valued at zero.
Impairment of Long-lived Assets
The Company evaluates the impairment of long-lived assets (asset group) using internal projections of undiscounted cash flows when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under the relevant accounting standards. Events or
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
changes in circumstances that may necessitate a recoverability evaluation may include but are not limited to: changes to or the passage of new legislation, changes in the relative pricing of wholesale electricity, anticipated demand and/or cost of fuel. The carrying amount of a long-lived asset (asset group) may not be recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposal of the asset (asset group). In such cases, fair value of the long-lived asset (asset group) is determined in accordance with the fair value measurement accounting guidance. The excess of carrying amount over fair value, if any, is recognized as an impairment expense. For regulated assets, an impairment expense could be reduced by the establishment of a regulatory asset, if recovery through approved rates was probable. For non-regulated assets, impairment is recognized as an expense against earnings.
DEFERRED FINANCING COSTS-Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight-line method when it does not differ materially from the effective interest method. Make-whole payments in connection with early debt retirements are classified as cash flows used in investing activities.
EQUITY METHOD INVESTMENTS-Investments in entities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in “Investments in and advances to affiliates” on the Consolidated Balance Sheets. In accordance with the accounting guidance for equity method investments, the Company periodically assesses the recoverability of its equity method investments. If an identified event or change in circumstances requires an impairment evaluation, management assesses the fair value based on valuation methodologies, including discounted cash flows, estimates of sale proceeds and external appraisals, as appropriate. The difference between the carrying amount of the equity method investment and its estimated fair value is recognized as impairment when the loss in value is deemed other-than-temporary and included in “Other non-operating expense” on the Consolidated Statements of Operations.
In accordance with the accounting standards for equity method investments, the Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the equity method if the investee subsequently reports net income to the extent that the Company’s share of such net income equals the share of net losses not recognized during the period in which the equity method of accounting was suspended.
GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS-In accordance with the accounting guidance on goodwill and other intangible assets, the Company recognizes goodwill as an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. The Company evaluates goodwill and indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. The Company’s annual impairment testing date is October 1st.
Goodwill:
The Company evaluates goodwill impairment at the reporting unit level, which is an operating segment, as defined in the segment reporting accounting guidance, or one level below an operating segment, a component. In determining its reporting units, the Company starts with its segment reporting structure. Operating segments are identified and then analyzed to identify components (usually businesses) which make up these operating segments. Two or more components are combined into a single reporting unit if they share the economic similarity criteria prescribed by the accounting guidance. Assets and liabilities are allocated to a reporting unit if
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
the assets will be employed by or a liability relates to the operations of a reporting unit or would be considered by a market participant in determining its fair value. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the synergies of the acquisition. Generally, each AES business constitutes a reporting unit.
Goodwill impairment evaluation is performed in two steps. In Step 1, the carrying amount of a reporting unit is compared to its fair value and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. In determining the implied fair value of goodwill for impairment measurement, the accounting guidance requires measuring all assets and liabilities, including unrecognized assets and liabilities, at fair value, as would be done in a business combination. When a Step 2 analysis is required to be completed, the fair value of individual assets and liabilities is determined using valuations (which in some cases may be based in part on third party valuation reports), or other observable sources of fair value, as appropriate. An impairment loss is recognized to the extent the carrying amount of goodwill exceeds its implied fair value, not to exceed the carrying value of goodwill.
Most of the Company’s reporting units are not publicly traded. Therefore, the Company estimates the fair value of its reporting units under the fair value measurement accounting guidance which requires making assumptions that a market participant would make in a hypothetical sale transaction at the testing date. The fair value of a reporting unit is estimated using internal budgets and forecasts, adjusted for any market participants’ assumptions and discounted at the rate of return required by a market participant. The Company considers both market and income-based approaches to determine a range of fair value, but typically concludes that the value derived using an income-based approach is more representative of fair value due to the lack of direct market comparables. The Company does use market data to corroborate and determine the reasonableness of the fair value derived from the income-based discounted cash flow analysis.
Indefinite-lived Intangible Assets:
The Company’s indefinite-lived intangible assets include items such as land use rights, easements, and concessions. These are tested for impairment on an annual basis or whenever events or changes in circumstances necessitate an evaluation for impairment in accordance with applicable accounting guidance for indefinite-lived intangible assets.
INCOME TAXES-Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more-likely-than-not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
PENSION AND OTHER POSTRETIREMENT PLANS-In accordance with the accounting guidance on defined benefit pension and other postretirement plans, the Company recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current year
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
changes in the funded status recognized in AOCI. All plan assets are recorded at fair value. AES follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
NONCONTROLLING INTERESTS-In accordance with the accounting guidance on noncontrolling interests, such interests are classified as a separate component of equity in the Consolidated Balance Sheets and Statements of Changes in Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income in the Consolidated Statements of Operations and Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero.
Although in general, the noncontrolling ownership interest in earnings is calculated based on ownership percentage, certain of the Company’s wind businesses use the HLBV method in consolidation. HLBV uses a balance sheet approach, which measures the Company’s equity in income or loss by calculating the change in the amount of net worth the partners are legally able to claim based on a hypothetical liquidation of the entity at the beginning of a reporting period compared to the end of that period. This method is used in AES Wind Generation partnerships which contain agreements designating different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership.
ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES-Accounts payable consists of amounts due to trade creditors related to the Company’s core business operations. The nature of these payables include amounts owed to vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and employee related costs including payroll, benefits and related taxes.
ASSET RETIREMENT OBLIGATIONS-In accordance with the accounting standards for asset retirement obligations, the Company records the fair value of the liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
GUARANTOR ACCOUNTING-In accordance with the accounting standards on guarantees, at the inception of a guarantee, the Company records the fair value of a guarantee as a liability, with the offset dependent on the circumstances under which the guarantee was issued.
TRANSFER OF FINANCIAL ASSETS-Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on transfers of financial assets, which among other things: removes the concept of a qualifying special purpose entity; introduces the concept of participating interests and specifies that in order to qualify for sale accounting a partial transfer of a financial asset or a group of financial assets should meet the definition of a participating interest; clarifies that an entity should consider all arrangements made contemporaneously with or in contemplation of a transfer and requires enhanced disclosures to provide financial statement users with greater transparency about transfers of financial assets and a transferor’s continuing involvement with transfers of financial assets accounted for as sales. Upon adoption on January 1, 2010, the Company recognized $40 million as accounts receivable and as an associated secured borrowing on its
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Consolidated Balance Sheet; both of which have since increased to $50 million as of December 31, 2010, as additional interests in receivables have been sold. While securitizing these accounts receivable through IPL Funding, a special purpose entity, IPL, the Company’s integrated utility in Indianapolis, had previously recognized the transaction as a sale, but had not recognized the accounts receivable and secured borrowing on its balance sheet. Under the facility, interests in these accounts receivable are sold, on a revolving basis, to unrelated parties (the Purchasers) up to the lesser of $50 million or an amount determinable under the facility agreement. The Purchasers assume the risk of collection on the interest sold without recourse to IPL, which retains the servicing responsibilities for the interest sold. While no direct recourse to IPL exists, IPL risks loss in the event collections are not sufficient to allow for full recovery of the retained interests. No servicing asset or liability is recorded since the servicing fee paid to IPL approximates a market rate. Under the new accounting guidance, the retained interest in these securitized accounts receivable does not meet the definition of a participating interest, thereby requiring the Company to recognize on its Consolidated Balance Sheet the portion transferred and the proceeds received as accounts receivable and a secured borrowing, respectively.
FOREIGN CURRENCY TRANSLATION-A business’ functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the U.S. Dollar translate their assets and liabilities into U.S. Dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. Dollars at the average exchange rates that prevailed during the period. Translation adjustments are included in AOCI. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in AOCI. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income.
REVENUE RECOGNITION-Revenue from Utilities is classified as regulated on the Consolidated Statements of Operations. Revenue from the sale of energy is recognized in the period during which the sale occurs. The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. Revenue from the Generation business is classified as non-regulated and is recognized based upon output delivered and capacity provided, at rates as specified under contract terms or prevailing market rates. The Company has businesses where it makes sales and purchases of power to and from Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”). In those instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
SHARE-BASED COMPENSATION-The Company grants share-based compensation in the form of stock options and restricted stock units. The Company accounts for stock-based compensation plans under the accounting guidance on stock-based compensation, which requires entities to recognize compensation costs relating to share-based payments in their financial statements. That cost is measured on the grant date based on the fair value of the equity or liability instrument issued and is expensed on a straight-line basis over the requisite service period, net of estimated forfeitures. Currently, the Company uses a Black-Scholes option pricing model to estimate the fair value of stock options granted to its employees.
GENERAL AND ADMINISTRATIVE EXPENSES-General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management,
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
finance, legal, human resources and information systems, which are not directly allocable to our business segments. Additionally, all costs associated with business development efforts are classified as general and administrative expenses.
REGULATORY ASSETS AND LIABILITIES-The Company accounts for certain of its regulated operations in accordance with the accounting standards on regulated operations. As a result, AES records assets and liabilities that result from the regulated ratemaking process that are not recognized under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred due to the probability of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs previously deferred ceases to be probable, the asset write-offs are recognized in continuing operations.
DERIVATIVES AND HEDGING ACTIVITIES-Derivatives primarily consist of interest rate swaps, cross currency swaps, foreign currency instruments, and commodity and embedded derivatives. The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. AES primarily uses derivative instruments to manage its interest rate, foreign currency and commodity exposures. The Company does not enter into derivative transactions for trading purposes.
Under the accounting standards for derivatives and hedging, the Company recognizes all contracts that meet the definition of a derivative, except those designated as normal purchase or normal sale at inception, as either assets or liabilities in the Consolidated Balance Sheets and measures those instruments at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Gains and losses related to derivative instruments that qualify as hedges are recognized in the same category as generated by the underlying asset or liability. Gains or losses on derivatives that do not qualify for hedge accounting are recognized as interest expense for interest rate and cross currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity derivatives.
The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective, designated and qualifies as a fair value hedge are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective, designated and qualifies as a cash flow hedge are deferred in AOCI and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is recognized in earnings immediately. The ineffective portion is recognized as interest expense for interest rate and cross currency hedges, foreign currency transaction gains or losses for foreign currency hedges, and non-regulated revenue or non-regulated cost of sales for commodity hedges. For all hedge contracts, the Company maintains formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If AES determines that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.
For cash flow hedges of forecasted transactions, AES estimates the future cash flows of the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from AOCI into earnings.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
See Note 4-Fair Value and the Company’s fair value policy for additional discussion regarding the determination of the fair value of the Company’s derivative assets and liabilities.
Accounting Pronouncements Issued But Not Yet Effective
The following accounting standards have been issued, but as of December 31, 2010 are not yet effective for and have not been adopted by AES.
Accounting Standards Update (“ASU”) No. 2010-28, Intangibles-Goodwill and Other (Topic 350), “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”
In December 2010, the FASB issued ASU No. 2010-28, which amends the accounting guidance related to goodwill. The amendments in ASU No. 2010-28 modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists, eliminating an entity’s ability to assert that a reporting unit is not required to perform Step 2 because the carrying amount of the reporting unit is zero or negative despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. ASU No. 2010-28 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010, or January 1, 2011 for AES. Early adoption is prohibited. The adoption is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
2. INVENTORY
As of December 31, 2010, 77% of the Company’s inventory was valued using average cost, 21% was determined using the FIFO method and the remaining inventory was valued using the specific identification method. The following table summarizes our inventory balances as of December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
3. PROPERTY, PLANT & EQUIPMENT
The following table summarizes the components of the electric generation and distribution assets and other property, plant and equipment with their estimated useful lives:
(1) Net electric generation and distribution assets and other related to Lal Pir, Pak Gen, Barka and Ras Laffan of $848 million as of December 31, 2009 were excluded from the table above and were included in the noncurrent assets of discontinued and held for sale businesses.
The amounts as of December 31, 2010 in the table above are stated net of impairment losses recognized in 2010 as further discussed in Note 19-Impairment Expense.
The following table summarizes interest capitalized during development and construction on qualifying assets for the years ended December 31, 2010, 2009 and 2008:
Recoveries of liquidated damages from construction delays and government subsidies are reflected as a reduction in the related projects’ construction costs. Approximately $12.2 billion of property, plant and equipment, net of accumulated depreciation, was mortgaged, pledged or subject to liens as of December 31, 2010.
Depreciation expense, including the amortization of assets recorded under capital leases, was $1.1 billion, $980 million and $928 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Net electric generation and distribution assets and other include unamortized internal use software costs of $170 million and $182 million as of December 31, 2010 and 2009, respectively. Amortization expense associated with software costs was $52 million, $48 million and $41 million for the years ended December 31, 2010, 2009 and 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation as of December 31, 2010 and 2009:
The following table summarizes the amounts recognized, which were related to asset retirement obligations, for the years ended December 31, 2010 and 2009:
The Company’s asset retirement obligations covered by the relevant guidance primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. The fair value of legally restricted assets for purposes of settling asset retirement obligations was $12 million and $0 at December 31, 2010 and 2009, respectively.
4. FAIR VALUE
The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The fair value of non-recourse debt is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow analyses. See Note 10-Debt for additional information on the fair value and carrying value of debt. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards, swaps and options, and energy derivatives is the estimated net amount that the Company would receive or pay to sell or transfer the agreements as of the balance sheet date.
The estimated fair values of the Company’s assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes the carrying and fair value of certain of the Company’s financial assets and liabilities as of December 31, 2010 and 2009:
Valuation Techniques:
The fair value measurement accounting guidance describes three main approaches to measuring the fair value: (1) market approach; (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach often uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and emissions allowances etc). In general, the Company determines the fair value of investments using the market approach and of derivatives using the income approach. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, fair value generated by the income approach is often selected.
Investments
The Company’s investments measured at fair value primarily consist of marketable debt and equity securities. Equity securities are measured at fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to London Inter Bank Offered Rate (“LIBOR”), a benchmark interest rate widely used by banks in the money market), or Selic (overnight borrowing rate) rates in Brazil. Fair value is determined from comparisons of market data obtained for similar assets and is considered Level 2 in the fair value hierarchy. For more detail regarding the fair value of investments see Note 5-Investments in Marketable Securities.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Derivatives
When deemed appropriate, the Company manages its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of financial and physical derivative instruments. The Company’s derivatives are primarily interest rate swaps to hedge non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations, commodity derivatives to hedge against commodity price fluctuations and embedded derivatives associated with commodity contracts. The Company’s subsidiaries are counterparties to various over-the-counter derivatives, which include interest rate swaps and options, foreign currency options and forwards and commodity swaps. In addition, the Company’s subsidiaries are counterparties to certain PPAs and fuel supply agreements that are derivatives or include embedded derivatives.
For the derivatives where there is a standard industry valuation model, the Company uses that model to estimate the fair value. For the derivatives (such the PPAs and fuel supply agreements that are derivatives or include embedded derivatives) where there is not a standard industry valuation model, the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. For all derivatives, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The following are among the most common market data inputs used in the income approach: volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates and prices are generally obtained from published information provided by pricing services for an instrument with the same duration as the derivative instrument being valued. In situations where significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis, Monte Carlo simulation or prices for similarly traded instruments available in the market.
For each derivative, the income approach is used to estimate the cash flows over the remaining term of the contract. Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR) plus a spread that reflects the credit or nonperformance risk. This risk is estimated by the Company using credit spreads and risk premiums that are observable in the market, whenever possible, or estimated borrowing costs based on bank quotes, industry publications and/or information on financing closed on similar projects. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are classified as Level 2.
In certain instances, the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. In addition, in certain instances, there may not be third party data readily available which requires the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. The fair value hierarchy of an asset or a liability is based on the Level of significance of input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are transferred to Level 3 when the use of unobservable inputs becomes significant. Similarly, when the use of unobservable input becomes insignificant for Level 3 assets and liabilities, they are transferred to Level 2.
Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2. The Company has not had any Level 1 derivatives so there have not been any transfers between Levels 1 and 2.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Nonfinancial assets and liabilities
For nonrecurring measurements derived using the income approach, fair value is determined using valuation models based on the principles of discounted cash flows (“DCF”). The income approach is most often used in the impairment evaluation of long-lived tangible assets, goodwill and intangible assets. The Company has developed internal valuation models for such valuations; however, an independent valuation firm may be engaged in certain situations. In such situations, the independent valuation firm largely uses DCF valuation models as the primary measure of fair value though other valuation approaches are also considered. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever possible, the Company attempts to obtain market observable data to develop input assumptions. Where the use of market observable data is limited or not possible for certain input assumptions, the Company develops its own estimates of such assumptions using a variety of techniques such as regression analysis and extrapolations.
For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to find sale transactions of identical or similar assets. This approach is used in the impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.
For nonrecurring measurements derived using the cost approach, fair value is typically determined using the replacement cost approach. Under this approach, the depreciated replacement cost of assets is determined by first determining the current replacement cost of assets and then applying the remaining useful lives percentages to such cost. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment which is why its use is limited to the measurement of a few long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach. For the year ended December 31, 2010, the Company did not measure any nonfinancial assets under the cost approach.
Fair Value Considerations:
In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company’s nonperformance. The conditions and criteria used to assess these factors are:
Sources of market assumptions:
The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Platt’s). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine the fair value.
Market liquidity:
The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company’s current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of the assets traded without significantly affecting the market price. Other factors the Company considers when determining
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
whether a market is active or inactive include the presence of government or regulatory control over pricing that could make it difficult to establish a market based price when entering into a transaction.
Nonperformance risk:
Nonperformance risk refers to the risk that the obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company or counterparty’s credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary Level are generally non-recourse to the Parent Company.
Nonperformance risk on the investments held by the Company is incorporated in the investment’s exit price that is derived from quoted market data that is used to mark the investment to fair value.
The Company adjusts for nonperformance risk or credit risk on its derivative instruments by deducting a credit valuation adjustment (“CVA”). The CVA is based on the margin or debt spread of the Company or counterparty and the tenor of the respective derivative instrument. The counterparty for a derivative asset position is considered to be the bank or government sponsored banking entity or counterparty to the PPA or commodity contract. The CVA for asset positions is based on the counterparty’s credit ratings and debt spreads or, in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. The CVA for liability positions is based on the Parent Company’s or the subsidiary’s current debt spread, the margin on indicative financing arrangements, or in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. If the instrument is recourse to the Parent Company, the Parent Company’s current debt spread is used to adjust for nonperformance risk. All derivative instruments are analyzed individually and are subject to unique risk exposures.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Recurring Measurements:
The following table sets forth, by Level within the fair value hierarchy, the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2010 and 2009. Financial assets and liabilities have been classified in their entirety based on the lowest Level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table presents a reconciliation of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009:
(1) Derivative assets and (liabilities) are presented on a net basis.
(2) The gains (losses) included in earnings for these Level 3 derivatives are classified as follows: interest rate and cross currency derivatives as interest expense, foreign currency derivatives as foreign currency transaction gains (losses) and commodity and other derivatives as either non-regulated revenue, non-regulated cost of sales or other expense. See Note 6-Derivative Instruments and Hedging Activities for further information regarding the classification of gains and losses included in earnings in the Consolidated Statements of Operations.
(3) Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2. The (assets) liabilities transferred out of Level 3 are primarily the result of a decrease in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments. Similarly, the assets (liabilities) transferred into Level 3 are primarily the result of an increase in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments.
The following table presents a reconciliation of available-for-sale securities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Available-for-sale securities in Level 3 are auction rate securities and variable rate demand notes which have failed remarketing or are not actively trading and for which there are no longer adequate observable inputs to measure the fair value.
Nonrecurring Measurements:
For the purpose of impairment evaluation, the Company measured fair values of long-lived assets, goodwill and intangibles assets, and assets and liabilities of discontinued operations under the fair value measurement accounting guidance. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the year and their level within the fair value hierarchy:
(1) Carrying amount as of the month end prior to impairment.
Long-lived Assets Held and Used
In the fourth quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Eastern Energy, our coal-fired generation plants in New York. These long-lived assets had a carrying amount of $827 million and were considered fully impaired. This resulted in the recognition of asset impairment expense of $827 million.
In the fourth quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Deepwater, our pet-coke-fired generation facility in Texas. These long-lived assets had a carrying amount of $83 million and were written down to their fair value of $4 million. This resulted in the recognition of asset impairment expense of $79 million.
In the third quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Tisza II, our gas-fired generation plant in Hungary, and Huntington Beach, one of our gas-fired generation plants in California. These long-lived assets had carrying amounts of $160 million and $288 million, respectively, and were written down to their fair value of $75 million and $88 million, respectively. These resulted in the recognition of asset impairment expense of $85 million and $200 million, respectively.
Since the majority of significant assumptions used in the valuations were not observable, management believes that the measurements are Level 3 in the fair value hierarchy. For further discussion of these impairments, see Note 19-Impairment Expense.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Discontinued Operations and Held for Sale Businesses
The Company determined the fair value of nonfinancial assets and liabilities of our held for sale businesses during the year ended December 31, 2010. These included the Company’s operations in Oman and Qatar.
Since the fair value estimates were based on sale price, management believes that the measurement is Level 2 in the fair value hierarchy. For further discussion, see Note 21-Discontinued Operations and Held for Sale Businesses.
Goodwill
As noted in Note 8-Goodwill and Other Intangible Assets, goodwill of $18 million related to our Deepwater business was written down to its implied fair value of zero during an interim impairment evaluation, resulting in the recognition of goodwill impairment of $18 million for the year ended December 31, 2010.
Since the majority of significant assumptions used in the valuation were not observable, management believes that the measurement is Level 3 in the fair value hierarchy. For further discussion, see Note 8-Goodwill and Other Intangible Assets.
5. INVESTMENTS IN MARKETABLE SECURITIES
The following table sets forth the Company’s investments in marketable debt and equity securities classified as trading and available-for-sale as of December 31, 2010 and 2009 by type of investment and by level within the fair value hierarchy. The security types are determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its securities.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Amortized cost approximated fair value at December 31, 2010 and 2009, with the exception of certain common stock investments with a cost basis of $6 million carried at their fair value of $7 million and $16 million at December 31, 2010 and 2009, respectively.
(2) Unsecured debentures are instruments similar to certificates of deposit that are held primarily by our subsidiaries in Brazil. The unsecured debentures and certificates of deposit included here do not qualify as cash equivalents and meet the definition of a security under the relevant guidance and are therefore classified as available-for-sale securities.
(3) Held-to-maturity securities are carried at amortized cost and not measured at fair value on a recurring basis. These investments consist primarily of certificates of deposit and government debt securities. The amortized cost approximated fair value of the held-to-maturity securities at December 31, 2009.
As of December 31, 2010, all available-for-sale debt securities had stated maturities less than one year, with the exception of $42 million of auction rate securities and variable rate demand notes held by IPL, a subsidiary of the Company in Indiana. These securities, classified as other debt securities in the table above, had stated maturities of greater than ten years.
During the second quarter of 2009, three of the Company’s generation businesses in the Dominican Republic exchanged $110 million of accounts receivable due from the government-owned distribution companies in the Dominican Republic for sovereign bonds of the same amount. The bonds, which were classified as available-for-sale securities, were adjusted to fair value when acquired. During the second and third quarters of 2009, the Company used a portion of the bonds with a carrying value of $31 million to settle third-party liabilities and sold the remaining bonds. As of December 31, 2009, all of the sovereign bonds had been sold or transferred.
The following table summarizes the pre-tax gains and losses related to available-for-sale securities for the years ended December 31, 2010, 2009 and 2008. There were no realized gains or losses on trading securities and there were no realized losses on the sale of available-for-sale securities. There was no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income for the years ended December 31, 2010, 2009 or 2008.
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Risk Management Objectives
The Company is exposed to market risks associated with its enterprise-wide business activities, namely the purchase and sale of fuel and electricity as well as foreign currency risk and interest rate risk. In order to manage the market risks associated with these business activities, we enter into contracts that incorporate derivatives and financial instruments, including forwards, futures, options, swaps or combinations thereof, as appropriate. The Company applies hedge accounting for all contracts as long as they are eligible under the accounting standards for derivatives and hedging. While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Interest Rate Risk
AES and its subsidiaries utilize variable rate debt financing for construction projects and operations, resulting in an exposure to interest rate risk. Interest rate swap, cap and floor agreements are entered into to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing. These interest rate contracts range in maturity through 2027, and are typically designated as cash flow hedges. The following table sets forth, by underlying type of interest rate index, the Company’s current and maximum outstanding notional under its interest rate derivative instruments, the weighted average remaining term and the percentage of variable-rate debt hedged that is based on the related index as of December 31, 2010 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:
(1) The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between December 31, 2010 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The weighted average remaining term represents the remaining tenor of our interest rate derivatives weighted by the corresponding maximum notional.
(2) Excludes variable-rate debt tied to other indices where the Company has no interest rate derivatives.
(3) The debt that was being hedged is no longer exposed to variable interest payments because it is now held on IPL’s behalf and no longer bears interest.
Cross currency swaps are utilized in certain instances to manage the risk related to fluctuations in both interest rates and certain foreign currencies. These cross currency contracts range in maturity through 2028. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional of its cross currency derivative instruments as of December 31, 2010 which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional as of December 31, 2010:
(1) Represents the remaining tenor of our cross currency swaps weighted by the corresponding notional.
(2) Represents the proportion of foreign currency denominated debt hedged by the same foreign currency denominated notional of the cross currency swap.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Foreign Currency Risk
We are exposed to foreign currency risk as a result of our investments in foreign subsidiaries and affiliates. AES operates businesses in many foreign environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards are utilized, where possible, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2011. The following tables set forth, by type of foreign currency denomination, the Company’s outstanding notional over the remaining terms of its foreign currency derivative instruments as of December 31, 2010 regardless of whether the derivative instruments are in qualifying hedging relationships:
(1) Represents contractual notionals at inception of trade.
(2) Represents the gross notional amounts times the probability of exercising the option, which is based on the relationship of changes in the option value with respect to changes in the price of the underlying currency.
(3) Represents the remaining tenor of our foreign currency options weighted by the corresponding notional.
(1) Represents the remaining tenor of our foreign currency forwards weighted by the corresponding notional.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives that require separate valuation and accounting due to the fact that the item being purchased or sold is denominated in a currency other than the functional currency of that subsidiary or the currency of the item. These contracts range in maturity through 2025. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional over the remaining terms of its foreign currency embedded derivative instruments as of December 31, 2010:
(1) Represents the remaining tenor of our foreign currency embedded derivatives weighted by the corresponding notional.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the price of electricity, fuel and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions (which provide our distribution businesses with a franchise to serve a specific geographic region), a portion of our current and expected future revenues are derived from businesses without significant long-term purchase or sales contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuel and environmental credits in competitive markets. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy can involve the use of commodity forward contracts, futures, swaps and options. Some of our businesses hedge certain aspects of their commodity risks using financial hedging instruments, as described below.
We also enter into short-term contracts for electricity and fuel in other competitive markets in which we operate. When hedging the output of our generation assets, we have power purchase agreements or other hedging instruments that lock in the spread in dollars per MWh between the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold (“Dark Spread” where the fuel is coal). The portion of our sales and fuel purchases that are not subject to such agreements will be exposed to commodity price risk. Eastern Energy sells electricity into the power pools managed by the New York Independent System Operator (“NYISO”). In addition, Eastern Energy hedges a portion of its power exposure by entering into hedges of natural gas prices, as movements in natural gas prices affect power prices. As of December 31, 2010, Eastern Energy has no net exposure under its hedges of natural gas prices. While there is a strong relationship between natural gas and power prices, the natural gas hedges do not currently qualify for hedge accounting treatment. The following table sets forth the Company’s current notionals under its commodity hedges at Eastern Energy and the percentage of forecasted electricity sales for 2011 hedged as of December 31, 2010 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The PPAs and fuel supply agreements entered into by the Company are evaluated to determine if they meet the definition of a derivative or contain embedded derivatives, either of which require separate valuation and accounting. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could then be net settled and meet the definition of a derivative.
Nonetheless, certain of the PPAs and fuel supply agreements entered into by certain of the Company’s subsidiaries are derivatives or contain embedded derivatives requiring separate valuation and accounting. These agreements range in maturity through 2024. The following table sets forth by type of commodity the Company’s outstanding notionals for the remaining term of its commodity derivative (excluding Eastern Energy which is presented in the above table) and embedded derivative instruments as of December 31, 2010:
(1) Represents the remaining tenor of our commodity and embedded derivatives weighted by the corresponding volume.
(2) De minimis amount.
(3) Our exposure is to fluctuations in the price of aluminum while the notional is based on the amount of power we sell under the PPA.
In addition, as part of the settlement agreements terminating the gas transportation contracts with Gasoducto GasAndes (Argentina) S.A. and Gasoducto GasAndes (Chile) S.A. discussed in Note 12-Contingencies, we have an embedded derivative related to the dividends that could result from our 13% ownership in these two gas transportation companies.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Accounting and Reporting
The following table sets forth the Company’s derivative instruments as of December 31, 2010 and 2009 by type of derivative and by level within the fair value hierarchy. Derivative assets and liabilities are recognized at their fair value. Derivative assets and liabilities are combined with other balances and included in the following captions in our Consolidated Balance Sheets: current derivative assets in other current assets, noncurrent derivative assets in other noncurrent assets, current derivative liabilities in accrued and other liabilities and long-term derivative liabilities in other long-term liabilities.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $1 million of current assets and $4 million of noncurrent assets on foreign currency derivatives and $19 million of current liabilities and $46 million of long-term liabilities for interest rate derivatives as of December 31, 2010.
The following table sets forth the fair value and balance sheet classification of derivative instruments as of December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $1 million of current assets and $4 million of noncurrent assets on foreign currency derivatives and $19 million of current liabilities and $46 million of long-term liabilities for interest rate derivatives as of December 31, 2010.
The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements. At December 31, 2010 and 2009, we held $0 and $8 million, respectively, of cash collateral that we received from counterparties to our derivative positions, which is recorded in restricted cash and in accrued and other liabilities in the Consolidated Balance Sheets. Beyond the cash collateral we received, our derivative assets are exposed to the credit risk of the respective counterparty and, due to this credit risk, the fair value of our derivative assets (as shown in the above two tables) have been reduced by a credit valuation adjustment. Also, at December 31, 2010 and 2009, we had no cash collateral posted with (held by) counterparties to our derivative positions.
The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of December 31, 2010 for the following types of derivative instruments:
The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for interest rate hedges and cross currency swaps, as depreciation is recognized for interest rate hedges during construction, as foreign currency transaction gains and losses are recognized for hedges of foreign currency exposure, and as electricity sales and fuel purchases are recognized for hedges of forecasted electricity and fuel transactions. These balances are included in the consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.
For the years ended December 31, 2010, 2009 and 2008, pre-tax gains (losses) of $(1) million, $7 million, and $(1) million net of noncontrolling interests, respectively, were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table sets forth the pre-tax gains (losses) recognized in accumulated other comprehensive loss (“AOCL”) and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the years ended December 31, 2010 and 2009:
(1) Includes amounts that were reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting. Excludes $(113) million and $(35) million related to discontinued operations for the years ended December 31, 2010 and 2009, respectively.
(2) De minimis amount.
(3) Includes $(29) million related to Cartagena for the year ended December 31, 2010, which was consolidated prospectively beginning January 1, 2010 under VIE accounting guidance.
Amounts recognized in AOCL due to derivative instruments that currently are, or previously were (but no longer are) qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, after income taxes, during the year ended December 31, 2008 are as follows:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table sets forth the pre-tax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the years ended December 31, 2010 and 2009:
(1) De minimis amount.
The Company recognized after-tax losses of $45 million, net of noncontrolling interests, related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the year ended December 31, 2008.
The following table sets forth the pre-tax gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the years ended December 31, 2010 and 2009:
(1) De minimis amount.
The Company recognized after-tax gains of $10 million net of noncontrolling interests related to the changes in fair value of derivative instruments not in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the year ended December 31, 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
In addition, IPL has two derivative instruments for which the gains and losses are accounted for in accordance with accounting standards for regulated operations, as regulatory assets or liabilities. Gains and losses on these derivatives due to changes in the fair value of these derivatives are probable of recovery through future rates and are initially recognized as an adjustment to the regulatory asset or liability and recognized through earnings when the related costs are recovered through IPL’s rates. Therefore, these gains and losses are excluded from the above table. The following table sets forth the change in regulatory assets and liabilities resulting from the change in the fair value of these derivatives for the years ended December 31, 2010 and 2009:
Credit Risk-Related Contingent Features
The following businesses have derivative agreements that contain credit contingent provisions which would permit the counterparties with which we are in a net liability position to require collateral credit support when the fair value of the derivatives exceeds the unsecured thresholds established in the agreements. These thresholds vary based on our subsidiaries’ credit ratings and as their credit ratings are lowered, the thresholds decrease, requiring more collateral support.
Eastern Energy, our generation business in New York, enters into commodity derivative transactions with several counterparties who have market exposure limits defined in their transaction agreements. Pursuant to the aforementioned credit contingent provisions, if Eastern Energy’s credit rating were to fall below the minimum thresholds established in each of the respective transaction agreements, the counterparties could demand immediate collateralization of the entire mark-to-market value of the derivatives (excluding credit valuation adjustments) if the derivatives were in a net liability position. As of December 31, 2010, Eastern Energy has $1 million in net liability positions but had posted no collateral. As of December 31, 2009, Eastern Energy had net liability positions of $2 million and had posted a nominal amount of collateral to support these positions based on its current credit rating and the related thresholds in the agreements.
Gener, our generation business in Chile, has a cross currency swap agreement with a counterparty to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. Pursuant to the aforementioned credit contingent provisions, if Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparty can demand immediate collateralization of the entire mark-to-market value of the swaps (excluding credit valuation adjustments) if Gener is in a net liability position, which was zero and $12 million, respectively, at December 31, 2010 and 2009. As of December 31, 2010 and 2009, Gener had posted zero and $25 million, respectively, in the form of a letter of credit to support these swaps.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
7. INVESTMENTS IN AND ADVANCES TO AFFILIATES
The following table summarizes the relevant effective equity ownership interest and carrying values for the Company’s investments accounted for under the equity method as of December 31, 2010 and 2009.
(1) Represent VIEs in which we hold a variable interest, but are not the primary beneficiary.
(2) The Company sold its interest in CEMIG during the year ended December 31, 2010; and retains its equity ownership in Cayman Energy Traders (“CET”). See additional discussion of the sale below.
AES Solar Energy Ltd.-In March 2008, the Company formed AES Solar Energy Ltd (“AES Solar”), a joint venture with Riverstone Holdings LLC (“Riverstone”). AES Solar develops land-based solar photovoltaic panels that capture sunlight to convert into electricity that feed directly into power grids. AES Solar is accounted for under the equity method of accounting based on the Company’s 50% ownership and significant influence, but not control over the joint venture. Under the terms of the agreement, the Company and Riverstone may each provide up to $500 million of capital over the next five years. As of December 31, 2010, AES had invested approximately $312 million in the joint venture.
AES Solar Power Ltd.-In March 2010, the Company formed AES Solar Power Ltd. (“AES Solar Power”), a joint venture with Riverstone. AES Solar Power develops solar photovoltaic projects in the United States. AES Solar Power is accounted for under the equity method of accounting based on the Company’s 50% ownership and significant influence, but not control over the joint venture. Under the terms of the agreement, the Company and Riverstone may each provide up to $100 million of capital over the next five years. As of December 31, 2010, AES had invested approximately $11 million in the joint venture.
AES Barry Ltd.-The Company holds a 100% ownership interest in AES Barry Ltd. (“Barry”), a dormant entity in the United Kingdom that disposed of its generation and other operating assets. As a result of a debt agreement, no material financial or operating decisions can be made without the banks’ consent, and the Company does not control Barry. As of December 31, 2010 and 2009, other long-term liabilities included $53 million and $54 million, respectively, related to this debt agreement.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Cartagena Energia-The Company owns 71% of Cartagena Energia (“Cartagena”), a 1,199 MW power plant in Cartagena, Spain completed in November 2007. The Company’s initial investment in Cartagena was approximately $29 million. As a result of the accounting guidance issued in 2009 regarding VIEs, the Company consolidated Cartagena effective January 1, 2010. Cartagena is no longer accounted for under the equity method of accounting. For further discussion, see Note 1-General and Summary of Significant Accounting Policies.
CEMIG-During the second quarter of 2010, the Company, through its Brazilian subsidiary, Southern Electric Brasil Participações Ltda. (“SEB”), transferred its shares of Companhia Energética de Minas Gerais (“CEMIG”), an integrated utility in Minas Gerais, Brazil, to Andrade Gutierrez Concessões S.A. and an affiliated company (jointly referred to as, “AG”). AG also assumed SEB’s debt with Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”) in the amount of approximately $1.4 billion (the “BNDES Loan”) including all unpaid interest and penalties. In exchange, SEB received $25 million and obtained a full release from any claims of BNDES and originating from the BNDES Loan. See Note 12-Contingencies, for additional information regarding these claims and proceedings.
Prior to the transfer of shares, the Company, through SEB, a VIE, had a 14.8% voting interest in CEMIG. The Company holds its interest in SEB through its equity ownership in Cayman Energy Traders (“CET”), a holding company whose sole activity is its investment in SEB. Although our interest in CEMIG was below 20%, AES had significant influence over the operational and financial policies of CEMIG through representation on the board of directors of CEMIG. In 2002, the Company determined there was an other-than-temporary impairment of its investment in CEMIG and wrote it down to fair market value, $155 million. Additionally, AES established a valuation allowance against a deferred tax asset related to its investment in CEMIG. The total amount of these charges, net of tax, was $587 million. As a result, the Company’s investment in CEMIG was a $484 million net liability at December 31, 2009 and was included in “Other long-term liabilities” on the Consolidated Balance Sheet. The Company discontinued the application of the equity method in accordance with its accounting policy regarding equity method investments.
The consummation of the share purchase and sale agreement along with AG’s assumption of the BNDES Loan in June 2010 resulted in the reversal of the Company’s net long-term liability along with the associated cumulative translation adjustment, resulting in the recognition of a $115 million pre-tax gain reflected in “Net equity in earnings of affiliates” on the Consolidated Statement of Operations for the year ended December 31, 2010. Additionally, $70 million of net tax expense resulting from the CEMIG sale transaction was recorded as “income tax expense,” rather than equity earnings, since the expense is attributable to a consolidated corporate level partner in the CEMIG investment.
The Company retains its ownership in CET.
China Wind-In May 2007, the Company entered into a joint venture with Guohua Energy Investment Co. Ltd. (“Guohua”) for a 49% interest in Guohua AES (Huanghua) Wind Power Co., Ltd. (“AES Huanghua”) that is primarily engaged to develop, construct, own and operate wind projects in Huanghua. Huanghua I went live in the third quarter of 2009 and Huanghua II went live in April 2010. In the second and third quarters of 2008, the Company acquired a 49% interest in Guohua AES (“Hulunbeier”) Wind Power Co., Ltd. and entered into joint venture agreements with Guohua for 49% interest in Guohua AES (“Xinba’erhu”) Wind Power Co., Ltd. (“Dong Qi”) which went live in June 2010 and Guohua AES (“Chenba’erhu”) Wind Power Co., Ltd. (“Chen Qi”) which is expected to go live in 2011. The Company invested approximately $12 million in the aforementioned projects in 2010, bringing the cumulative investment to $62 million.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Jianghe Rural Electrification Development Co., LTD (“JHRH”)- On June 3, 2010, the Company entered into an agreement to acquire a 35% ownership in this joint venture which operates seven hydro plants in China. The agreement entitled the Company to acquire up to a 49% interest. The purchase of an additional 14% ownership is expected to be completed by May 2011.
Trinidad Generation Unlimited-In 2007, the Company began pursuing a development project to construct and operate a 720 MW combined cycle power plant in Trinidad through its wholly owned subsidiary, Trinidad Generation Unlimited (“TGU”). In July 2008, a shareholder agreement was executed establishing the Company’s ownership interest in TGU at 60% with the remaining 40% interest held by the Government of Trinidad and Tobago. Although the Company’s ownership in TGU was reduced to 10% in 2009, the Company continues to account for its investment in Trinidad as an equity method investment because AES continues to exercise significant influence through the supermajority vote requirement for any significant future project development activities.
Summarized Financial Information
The following tables summarize financial information of the Company’s 50%-or-less owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method.
At December 31, 2010, retained earnings included $168 million related to the undistributed earnings of the Company’s 50%-or-less owned affiliates. Distributions received from these affiliates were $49 million, $35 million and $50 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Refer to Item 1 of this Form 10-K for additional information on these affiliates.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
8. GOODWILL AND OTHER INTANGIBLE ASSETS
The following table summarizes the changes in the carrying amount of goodwill, by segment for the years ended December 31, 2010, 2009 and 2008. There was no goodwill associated with our North America-Utilities segment during the years ended December 31, 2010, 2009 and 2008.
During the third quarter of 2010, Deepwater, our petcoke-fired merchant generation facility in Texas, reported in the North America Generation segment, incurred a goodwill impairment of $18 million. The Company determined that there was an impairment indicator for Deepwater’s goodwill. This determination was based primarily on the fact that Deepwater did not operate for more than 30 days in the third quarter of 2010, incurred current operating and cash flow losses and, at that time, was forecasting operating and cash flow losses for the remainder of 2010 through 2014. This resulted from a decrease in future power price expectations and an increase in pet coke prices affecting the market. The Company performed the two-step goodwill impairment test of Deepwater’s goodwill as of August 31, 2010 and recognized the entire $18 million carrying amount of goodwill as goodwill impairment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
In 2009, Kilroot, our subsidiary in the United Kingdom, reported in the Europe Generation segment, incurred a goodwill impairment loss of $118 million. Kilroot is a generation plant fired primarily by coal. Factors contributing to the impairment included: reduced profit expectations based on latest estimates of future commodity prices and reduced expectations on the recovery of cash flows on the existing plant following the Company’s decision to forgo capital expenditures to meet emission allowance requirements taking effect in 2024. Additionally, one of our subsidiaries located in the Ukraine and reported within “Corporate and Other” incurred a goodwill impairment loss of $4 million. For the year ended December 31, 2008, the Company had no goodwill impairment.
The following tables summarize the balances comprising other intangible assets in the accompanying Consolidated Balance Sheets as of December 31, 2010 and 2009:
(1) Represent development rights, including but not limited to, land control, various permits and right to acquire equity interests in development projects resulting from asset acquisitions by our Wind group.
(2) Represent legal rights to receive system reliability payments from the regulator.
(3) Acquired or purchased emission allowances are expensed when utilized and included in net income for the year.
(4) Represent various intangible assets relating to an asset acquisition in the state of New York in 1999. During the fourth quarter of 2010, the unamortized amount of $158 million was recognized as impairment expense as part of Eastern Energy long-lived asset impairment evaluation.
(5) Consists of various intangible assets including PPAs and transmission rights, none of which is individually significant.
(6) Represent perpetual emission allowances without an expiration date.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes, by category, intangible assets acquired during the years ended December 31, 2010 and 2009:
In 2009, the Company reclassified $42 million from other assets into intangible assets at a subsidiary in Latin America.
The following table summarizes the estimated amortization expense, broken down by intangible asset category, for 2011 through 2015:
Intangible asset amortization expense was $21 million, $24 million and $19 million for the years ended December 31, 2010, 2009 and 2008, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
9. REGULATORY ASSETS & LIABILITIES
The Company has recorded regulatory assets and liabilities that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Recoverable per National Electric Energy Agency (“ANEEL”) regulations through the Annual Tariff Adjustment (“IRT”). These costs are generally non-controllable costs and primarily consist of purchased electricity, energy transmission costs and sector costs that are considered volatile. These costs are recovered in 24 installments through the annual IRT process and are amortized over the tariff reset period.
(2) Deferred fuel costs incurred by our El Salvador subsidiaries associated with purchase of energy from the El Salvador spot market and the power generation plants. In El Salvador, the deferred fuel adjustment represents the variance between the actual fuel costs and the fuel costs recovered in the tariffs. The variance is recovered semi-annually at the tariff reset period.
(3) Includes assets with and without a rate of return. All current regulatory assets earned a rate of return as of December 31, 2010 and 2009. Other noncurrent regulatory assets that did not earn a rate of return were $95 million and $90 million, as of December 31, 2010 and 2009, respectively. Those without a rate of return that are recoverable primarily consist of transmission service costs and other administrative costs from IPL’s participation in the Midwest ISO market. Recovery of costs is probable, but the timing is not yet determined.
(4) Past expenditures on which the Company does not earn a rate of return.
(5) The regulatory accounting standards allow the defined pension and postretirement benefit obligation to be recorded as a regulatory asset equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Pension expense is recognized based on the plan’s actuarially determined pension liability. Recovery of costs is probable, but not yet determined. Pension contributions made by our Brazilian subsidiaries are not included in regulatory assets as those contributions are not covered by the established tariff in Brazil.
(6) Probable of recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This amount is expected to be recovered, without interest, over the period as book-tax temporary differences reverse and become current taxes.
(7) Payments received for costs expected to be incurred to improve the efficiency of our plants in Brazil that are refunded as part of the IRT.
(8) Other Current and Noncurrent Regulatory Liabilities consist of:
•
Deferred fuel costs, which are expected to be refunded to customers as a credit against future fuel adjustment charges. In the United States, deferred fuel costs at IPL represent variances between estimated and actual fuel and purchased power costs. IPL is required to refund overestimated fuel and purchased power costs in future rates.
•
Penalties and fees from regulators at our Brazilian subsidiaries.
•
Financial transmission rights used to hedge exposure in the Midwest ISO market that are credited per specific rate orders.
•
The cost incurred by electricity generators due to variance in energy prices during rationing periods (Free Energy). Our Brazilian subsidiaries are authorized to recover or refund this cost associated with monthly energy price variances between the wholesale energy market prices owed to the power generation plants producing Free Energy and the capped price reimbursed by the local distribution companies which are passed through to the final customers through energy tariffs.
(9) Obligations for removal costs which do not have an associated legal retirement obligation as defined by the accounting standards on asset retirement obligations.
(10) Obligations established by ANEEL in Brazil associated with electric utility concessions and represent amounts received from customers or donations not subject to return. These donations are allocated to support energy network expansion and to improve utility operations to meet customers’ needs. The term of the obligation is established by ANEEL. Settlement shall occur when the concession ends.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The current regulatory assets and liabilities are recorded in “Other current assets” and “Accrued and other liabilities,” respectively, on the accompanying Consolidated Balance Sheets. The noncurrent regulatory assets and liabilities are recorded in “Other assets” and “Other long-term liabilities,” respectively, in the accompanying Consolidated Balance Sheets.
The following table summarizes regulatory assets by region as of December 31, 2010 and 2009:
The following table summarizes regulatory liabilities by region as of December 31, 2010 and 2009:
10. DEBT
The Company has two types of debt reported on its Consolidated Balance Sheets: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for the construction and acquisition of electric power plants, wind projects, distribution companies and other project-related investments at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. Absent guarantees, intercompany loans or other credit support, the default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries, though the Company’s equity investments and/or subordinated loans to projects (if any) are at risk. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisitions, including serving as funding for equity investments or loans to the affiliates. The Parent Company’s debt is, among other things, recourse to the Parent Company and is structurally subordinated to the affiliates’ debt.
The following table summarizes the carrying amount and estimated fair values of the Company’s recourse and non-recourse debt as of December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon the type of loan. The fair value of fixed rate loans is estimated using quoted market prices, if available or a discounted cash flow analysis. In the discounted cash flow analysis, the discount rate is based on the credit rating of the individual debt instruments if available, or the credit rating of the subsidiary. If the subsidiary’s credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry specific factors. For subsidiaries located outside of the U.S., in the event that the country rating is lower than the credit rating previously determined, the country rating is used for the purposes of the discounted cash flow analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date.
The estimated fair value was determined using available market information as of December 31, 2010 and 2009. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2010.
NON-RECOURSE DEBT
The following table summarizes the carrying amount and terms of non-recourse debt as of December 31, 2010 and 2009:
(1) Weighted average interest rate at December 31, 2010.
(2) The Company has interest rate swaps and interest rate option agreements in an aggregate notional principal amount of approximately $4.3 billion on non-recourse debt outstanding at December 31, 2010. The swap agreements economically change the variable interest rates on the portion of the debt covered by the notional amounts to fixed rates ranging from approximately 0.71% to 6.98%. The option agreements fix interest rates within a range from 4.03% to 7.00%. The agreements expire at various dates from 2016 through 2027.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(3) Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
(4) Non-recourse debt of $708 million as of December 31, 2009 was excluded from non-recourse debt and included in current and long-term liabilities of held for sale and discontinued businesses in the accompanying Consolidated Balance Sheets.
Non-recourse debt as of December 31, 2010 is scheduled to reach maturity as set forth in the table below:
As of December 31, 2010, AES subsidiaries with facilities under construction had a total of approximately $432 million of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $893 million in a number of available but unused committed revolving credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used in one or more of the following ways: solely for borrowings; solely for letters of credit; or a combination of these uses. The weighted average interest rate on borrowings from these facilities was 3.24% at December 31, 2010.
Non-Recourse Debt Covenants, Restrictions and Defaults
The terms of the Company’s non-recourse debt include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include but are not limited to maintenance of certain reserves, minimum levels of working capital and limitations on incurring additional indebtedness. Compliance with certain covenants may not be objectively determinable.
As of December 31, 2010 and 2009, approximately $803 million and $653 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these amounts were included within “Restricted cash” and “Debt service reserves and other deposits” in the accompanying Consolidated Balance Sheets.
Various lender and governmental provisions restrict the ability of certain of the Company’s subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $5.4 billion at December 31, 2010.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of December 31, 2010 and is included in the current portion of non-recourse debt unless otherwise indicated:
None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of December 31, 2010 in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. The bankruptcy or acceleration of material amounts of debt at such entities would cause a cross default under the recourse senior secured credit facility. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position or results of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon a bankruptcy or acceleration of its non-recourse debt trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.
RECOURSE DEBT
The following table summarizes the carrying amount and terms of recourse debt of the Company as of December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Recourse debt as of December 31, 2010 is scheduled to reach maturity as set forth in the table below:
Recourse Debt Transactions
During 2010, the Company redeemed $690 million aggregate principal of its 8.75% Second Priority Senior Secured Notes due 2013 (“the 2013 Notes”). The 2013 Notes were redeemed at a redemption price equal to 101.458% of the principal amount redeemed. The Company recognized a pre-tax loss on the redemption of the 2013 Notes of $15 million for the year ended December 31, 2010, which is included in “Other expense” in the accompanying Consolidated Statement of Operations.
On July 29, 2010, the Company entered into a second amendment (“Amendment No. 2”) to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008, among the Company, various subsidiary guarantors and various lending institutions (the “Existing Credit Agreement”) that amends and restates the Existing Credit Agreement (as so amended and restated by Amendment No. 2, the “Fifth Amended and Restated Credit Agreement”). The Fifth Amended and Restated Credit Agreement adjusted the terms and conditions of the Existing Credit Agreement, including the following changes:
•
the aggregate commitment for the revolving credit loan facility was increased to $800 million;
•
the final maturity date of the revolving credit loan facility was extended to January 29, 2015;
•
changes to the facility fee applicable to the revolving credit loan facility;
•
the interest rate margin applicable to the revolving credit loan facility is now based on the credit rating assigned to the loans under the credit agreement, with pricing currently at LIBOR + 3.00%;
•
there is an undrawn fee of 0.625% per annum;
•
the Company may incur a combination of additional term loan and revolver commitments so long as total term loan and revolver commitments (including those currently outstanding) do not exceed $1.4 billion; and
•
the negative pledge (i.e., a cap on first lien debt) of $3.0 billion.
Recourse Debt Covenants and Guarantees
Certain of the Company’s obligations under the senior secured credit facility are guaranteed by its direct subsidiaries through which the Company owns its interests in the AES Shady Point, AES Hawaii, AES Warrior Run and AES Eastern Energy businesses. The Company’s obligations under the senior secured credit facility are, subject to certain exceptions, secured by:
(i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company; and
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.
The senior secured credit facility is subject to mandatory prepayment under certain circumstances, including the sale of a guarantor subsidiary. In such a situation, the net cash proceeds from the sale of a Guarantor or any of its subsidiaries must be applied pro rata to repay the term loan using 60% of net cash proceeds, reduced to 50% when and if the parent’s recourse debt to cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption.
The senior secured credit facility contains customary covenants and restrictions on the Company’s ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.
The senior secured credit facility also contains financial covenants requiring the Company to maintain certain financial ratios including a cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company’s adjusted operating cash flow to the Company’s interest charges related to recourse debt of 1.3× must be maintained at all times and a recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company’s total recourse debt to the Company’s adjusted operating cash flow must not exceed a maximum at any time of calculation, or 7.5× at December 31, 2010.
The terms of the Company’s senior unsecured notes and senior secured credit facility contain certain covenants including, without limitation, limitation on the Company’s ability to incur liens or enter into sale and leaseback transactions.
TERM CONVERTIBLE TRUST SECURITIES
Between 1999 and 2000, AES Trust III, a wholly owned special purpose business trust, issued approximately 10.35 million of $3.375 Term Convertible Preferred Securities (“TECONS”) (liquidation value $50) for total proceeds of $517 million and concurrently purchased $517 million of 6.75% Junior Subordinated Convertible Debentures due 2029 (the “6.75% Debentures” of the Company). The TECONS are consolidated and classified as long-term recourse debt on the Company’s Consolidated Balance Sheet.
AES, at its option, can redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by AES Trust III, currently for $50 per TECON. The TECONS must be redeemed upon maturity of the 6.75% Debentures. The TECONS are convertible into the common stock of AES at each holder’s option prior to October 15, 2029 at the rate of 1.4216, representing a conversion price of $35.17 per share. The maximum number of shares of common stock AES would be required to issue should all holders decide to convert their securities would be 14.7 million shares.
Dividends on the TECONS are payable quarterly at an annual rate of 6.75%. The Trust is permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the TECONS would accumulate quarterly and accrue interest, and the Company may not declare or pay dividends on its common stock. AES has not exercised the option to defer any dividends at this time and all dividends due under the Trust have been paid.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
AES Trust III is a VIE under the relevant consolidation accounting guidance. AES’ obligations under the 6.75% Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by AES of the TECON Trusts’ obligations. Accordingly, AES consolidates AES Trust III. As of December 31, 2010 and 2009, the sole assets of AES Trust III are the 6.75% Debentures.
11. COMMITMENTS
OPERATING LEASES-As of December 31, 2010, the Company was obligated under long-term non-cancelable operating leases, primarily for certain transmission lines, office rental and site leases. Rental expense for lease commitments under these operating leases for the years ended December 31, 2010, 2009 and 2008 was $58 million, $63 million and $74 million, respectively.
The table below sets forth the future minimum lease commitments under these operating leases as of December 31, 2010 for 2011 through 2015 and thereafter:
CAPITAL LEASES-Several AES subsidiaries lease operating and office equipment and vehicles that are considered capital lease transactions. These capital leases are recognized in Property, Plant and Equipment within “Electric generation and distribution assets” and primarily relate to transmission lines at our subsidiaries in Brazil. The gross value of the leased assets as of December 31, 2010 and 2009 was $99 million and $106 million, respectively.
The following table summarizes the future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2010 for 2011 through 2015 and thereafter:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
SALE/LEASEBACK-In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas (“NYSEG”). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment. In May 2007, the subsidiary purchased a portion of the lessor’s interest in a trust estate that holds the leased plants. Future minimum lease commitments under the lease agreement are reduced by the subsidiary’s interest in the plants. Rental expense was $34 million for each of the years ended December 31, 2010, 2009 and 2008.
The following table summarizes the future minimum lease commitments under the sale/leaseback arrangement as of December 31, 2010 for 2011 through 2015 and thereafter:
CONTRACTS-Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties that primarily include energy auction agreements at our Brazil subsidiaries with extended terms from 2011 through 2042 and in some cases are subject to variable quantities or prices. Purchases in the years ended December 31, 2010, 2009 and 2008 were approximately $2.4 billion, $2.1 billion and $1.5 billion, respectively.
The table below sets forth the future minimum commitments under these electricity purchase contracts at December 31, 2010 for 2011 through 2015 and thereafter:
Operating subsidiaries of the Company have entered into various long-term contracts for the purchase of fuel subject to termination only in certain limited circumstances and in some cases are subject to variable quantities or prices. Purchases in the years ended December 31, 2010, 2009 and 2008 were $1.9 billion, $1.3 billion and $1.3 billion, respectively.
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The table below sets forth the future minimum commitments under these fuel contracts as of December 31, 2010 for 2011 through 2015 and thereafter:
The Company’s subsidiaries have entered into other various long-term contracts. These contracts are mainly for construction projects, service and maintenance, transmission of electricity and other operation services. Payments under these contracts for the years ended December 31, 2010, 2009 and 2008 were $1.7 billion, $2.8 billion and $1.9 billion, respectively.
The table below sets forth the future minimum commitments under these other purchase contracts as of December 31, 2010 for 2011 through 2015 and thereafter:
12. CONTINGENCIES
ENVIRONMENTAL LIABILITIES
The Company will record liabilities when an environmental assessment indicates that remedial actions are probable and that costs can be reasonably estimated. As of December 31, 2010, the Company has recognized liabilities of $28 million for estimated environmental remediation costs and potential fines and penalties. These are reported on the Consolidated Balance Sheet within “accrued and other liabilities” and “other long-term liabilities.” Due to the uncertainties associated with environmental assessment and remediation activities, actual future costs of compliance or remediation could be higher or lower than the amount currently accrued. Certain expenditures many also be capitalized in accordance with the Company’s property, plant and equipment policies and are excluded from environmental liabilities in accordance with accounting guidelines. Any capital expenditures incurred of this nature would be incremental to amounts reserved.
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ENVIRONMENTAL REGULATION
The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these 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 and mercury. 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 environmental 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.”
Legislation and Regulation of GHG Emissions
Currently in the United States there is no Federal legislation establishing mandatory GHG emissions reduction programs (including 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 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 impose a nationwide cap-and-trade program to reduce GHG emissions. In the United States Senate, several different draft bills pertaining to GHG legislation have been considered at various times since then, including comprehensive GHG legislation similar to the legislation that passed the United States House of Representatives and more limited legislation focusing only on the utility and electric generation industry. It is uncertain whether any such legislation or any new legislation pertaining to GHG emissions will be voted on or passed by the Senate. If any legislation is passed by the Senate, it is uncertain whether such legislation will be reconciled with the House of Representatives’ legislation and ultimately enacted into law. However, if any such legislation is enacted, the impact could be material to the Company.
EPA GHG Regulation. The EPA promulgated regulations governing GHG emissions from automobiles under the CAA. 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. Beginning on January 2, 2011, construction of new stationary sources and modifications to existing stationary sources that result in increased GHG emissions, became subject to permitting requirements under the prevention of significant deterioration (“PSD”) program of the CAA. The PSD program, as currently applicable to GHG emissions, requires sources that emit above a certain threshold of GHGs to obtain PSD permits prior to commencement of new construction or modifications to existing facilities. 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.
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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 EPA’s new source performance standards (“NSPS”) rulemaking for electric utility steam generating units (“EUSGUs”) based on the NSPS’ failure to address GHG emissions. Under the settlement agreement, the EPA has committed to propose GHG emissions standards for EUSGUs by July 26, 2011 and to finalize GHG emissions standards for EUSGUs by May 26, 2012. The NSPS will establish GHG emission standards for newly constructed and reconstructed EUSGUs. The NSPS also will establish guidelines regarding the best system for achieving further GHG emissions reductions from EUSGUs and, based on such guidelines, individual states will be required to submit a plan to the EPA to establish GHG emission 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 and adverse impact on our consolidated financial condition or results of operations.
Regional Greenhouse Gas Initiative. The primary regulation of GHG emissions affecting the United States plants of the Company’s subsidiaries has 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. States participating in RGGI in which our subsidiaries have generating facilities include Connecticut, Maryland, New York and New Jersey. Under RGGI, power plants must acquire one carbon allowance through auction or in the emission trading markets for each ton of CO2 emitted.
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. To do so, member states are required to implement EC-approved national allocation plans (“NAPs”). Under the NAPs, member states are responsible for allocating limited CO2 allowances within their borders. Directive 2003/87/EC does not dictate how these allocations are to be made, and NAPs that have been submitted thus far have varied in their allocation methodologies. For these and other reasons, uncertainty remains with respect to the implementation of the European Union Emissions Trading System (“EU ETS”) that commenced in January 2005. The European Union has announced that it intends to keep the EU ETS in place after 2012, even if the Kyoto Protocol is not extended or replaced by another agreement. The Company’s subsidiaries operate eight
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electric power generation facilities, and another subsidiary has one under construction, within six member states which have adopted NAPs to implement Directive 2003/87/EC. At this time, the Company cannot determine fully whether achieving and maintaining compliance with the NAPs, to which its subsidiaries are subject, will have a material impact on its consolidated operations or results. 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 contractual provisions that transfer the costs associated with compliance to contract counterparties. However, one such contract counterparty, GDF-Suez, is currently disputing these provisions with AES Energia Cartagena S.R.L. The matter has been submitted to arbitration and the parties are currently awaiting a decision. See Item 3.-Legal Proceedings-in this Form 10-K for more detail regarding this dispute. In connection with this dispute or any similar dispute that might arise with other contract counterparties, 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 adverse effect on the Company and its financial condition or consolidated results of operations.
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 28 countries in which the Company’s subsidiaries currently operate all but one-the United States (including Puerto Rico)-have ratified the Kyoto Protocol.
In addition to the risks and uncertainties related to GHG regulations or potential legislation, the Company faces certain risks and uncertainties related to regulations or legislation concerning other types of air emissions. 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 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 was subsequently challenged in federal court on July 11, 2008 and 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 6, 2010, the EPA issued a new proposed rule (the “Transport Rule”) to replace CAIR. The final Transport Rule is scheduled to be issued by July 2011. The Clean Air Transport Rule would require significant reductions in SO2 and NOX emissions in 31 states and the District of Columbia starting in 2012, including several states where subsidiaries of the Company conduct business.
The Transport Rule contemplates three possible options for reducing SO2 and NOX emissions in the designated states. The EPA’s preferred option contemplates a set limit or budget on SO2 and NOX emissions for each of the states, with limited interstate trading of emissions allowances and unlimited intrastate trading of SO2 and NOX emissions allowances. Affected power plants would receive emissions allowances based on the applicable state emissions budgets. The EPA’s second option under the Transport Rule would establish emission budgets for each state but only allow intrastate trading of emissions allowances. The final option would set emission rate limitations for each power plant but would allow for some intrastate averaging of emission rates. Under any of the proposed options, additional air emission 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 Parent Company. The EPA has received public comments on the Transport Rule, and such public comments will be considered by the EPA prior to promulgating a final rule.
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DECEMBER 31, 2010, 2009, AND 2008
As a result of prior EPA determinations and a D.C. Circuit Court ruling, 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. The EPA has entered into a consent decree under which it is obligated to propose the rule by March 2011 and to finalize the rule by November 2011. In connection with such rule, the CAA requires the EPA to establish maximum achievable control technology (“MACT”) standards for each pollutant regulated under the rule. MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. While it is impossible to project what emission rate levels the EPA may propose as MACT, the rule may require all coal-fired power plants to install acid gas scrubbers (wet or dry flue gas desulfurization technology) and/or some other type of mercury control technology, such as sorbent injection. Most of the Company’s United States coal-fired plants have acid gas scrubbers or comparable control technologies, but it is possible that EPA regulations will require improvements to such control technologies at some of our plants. Under the CAA, compliance is required within three years of the effective date of the rule; however, the compliance period for a unit, or group of units, may be extended by state permitting authorities (for one additional year) or through a determination by the President (for up to two additional years). At this time, the Company cannot predict whether new regulations for hazardous air pollutants will be promulgated or, if promulgated, the extent of such regulations, but the cost of compliance with any such regulations could be material.
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.
In Europe, the Company is, and will continue to be, required to reduce air emissions from our facilities to comply with applicable EC Directives, including Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants (the “LCPD”), which sets emission limit values for NOX, SO2, and particulate matter for large-scale industrial combustion plants for all member states. Until June 2004, existing coal plants could “opt-in” or “opt-out” of the LCPD emissions standards. Those plants that opted out will be required to cease all operations by 2015 and may not operate for more than 20,000 hours after 2008. Those that opted-in, like the Company’s AES 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.
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 will become effective upon approval of the General Comptroller of Chile. The regulation will require AES Gener, our Chilean subsidiary, to install emissions reduction equipment at its existing thermal plants from late 2011 through 2015. The exact costs of compliance with such regulation have
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not yet been determined and the Company believes some of the compliance costs are contractually passed through to counterparties. However, the compliance costs could be material.
Water Discharges
The Company also faces certain risks and uncertainties related to environmental laws and regulations pertaining to water discharge. The Company’s facilities are subject to a variety of rules governing water discharges. In particular, the Company is subject to the United States Clean Water Act Section 316(b) rule regarding existing power plant cooling water intake structures issued by the EPA in 2005 (69 Fed. Reg. 41579, July 9, 2004), and the subsequent Circuit Court of Appeals decision and Supreme Court decision regarding this rule. The rule as originally issued could affect 12 of the Company’s United States power plants and the rule’s requirements would be implemented via each plant’s National Pollutant Discharge Elimination System (“NPDES”) water quality permit renewal process. These permits are usually processed by state water quality agencies. To protect fish and other aquatic organisms, the 2004 rule requires existing steam electric generating facilities to utilize the best technology available for cooling water intake structures. To comply, a steam electric generating facility must first prepare a Comprehensive Demonstration Study to assess the facility’s effect on the local aquatic environment. Since each facility’s design, location, existing control equipment and results of impact assessments must be taken into consideration, costs will likely vary. The timing of capital expenditures to achieve compliance with this rule will vary from site to site. On January 25, 2007, the United States Court of Appeals for the Second Circuit decision (Docket Nos. 04-6692 to 04-6699) vacated and remanded major parts of the 2004 rule back to the EPA. In November 2007, three industry petitioners sought review of the Second Circuit’s decision by the United States Supreme Court, and this review was granted by the United States Supreme Court in April 2008. In its April 2009 decision, the United States Supreme Court granted the EPA authority to use a cost-benefit analysis when setting technology-based requirements under Section 316(b) of the Clean Water Act, and expressed no view on the remaining bases for the Second Circuit’s remand. New draft rule 316(b) regulations are expected to be proposed by the EPA by March 14, 2011, and finalized by July 27, 2010. 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 minimizing adverse environmental impacts from cooling water intake structures. Certain states in which the Company operates power generation facilities, such as New York, have been delegated authority and are moving forward 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 Water Resources Control Board with respect to power plant cooling water intake structures. This policy became effective on October 1, 2010 and establishes technology-based standards to implement Section 316(b) of the United States Clean Water Act. At this time, it is contemplated that the Company’s Redondo Beach, Huntington Beach and Alamitos power plants in California will need to have in place “best technology available” by December 31, 2020, or repower the facilities. At present, the Company cannot predict the final requirements under Section 316(b) or whether compliance with the anticipated new 316(b) rule will have a material impact on our operations or results, but the Company expects that capital investments and/or modifications resulting from such requirements could be significant.
Waste Management
The Company also faces certain risks and uncertainties related to environmental laws and regulations pertaining to 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
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disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities include CCB, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl 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 December 22, 2009, a dike at a coal ash containment area at the Tennessee Valley Authority’s plant in Kingston, Tennessee failed, and over 1 billion gallons of ash was released into adjacent waterways and properties. Following such incident, there has been heightened focus on the regulation of CCBs. 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, 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.
The public comment period for this proposed regulation has expired, and the EPA is required to consider the public comments prior to promulgating a final rule. Requirements under a final rule are expected to become effective by January 2012, with a compliance schedule of five years. 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.
GUARANTEES, LETTERS OF CREDIT
In connection with certain project financing, acquisition, power purchase and other agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations primarily relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 16 years. In addition to the contingent obligations of the Parent Company identified in the table below, the Company’s subsidiaries had letters of credit outstanding to support various contingent obligations.
The following table summarizes the Parent Company’s contingent contractual obligations as of December 31, 2010. Amounts presented in the table below represent the Parent Company’s current undiscounted
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exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of businesses of $101 million.
The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, sponsor support and liquidated damages under power purchase agreements and other agreements for projects in development, under construction and operating. While the Company does not expect to be required to fund any material amounts under these contingent contractual obligations during 2011 or beyond that are not recognized on the Consolidated Balance Sheet, many of the events which would give rise to such an obligation are beyond the Parent Company’s control. There can be no assurance that the Parent Company would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder.
During 2010, the Company paid letter of credit fees ranging from 3.19% to 3.75% per annum on the outstanding amounts of letters of credit.
LITIGATION
The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims for approximately $450 million and $482 million as of December 31, 2010 and 2009. These are reported on the Consolidated Balance Sheet within “accrued and other liabilities” and “other long-term liabilities.” A significant portion of these reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that this reserve will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s financial statements. However, even where no reserve has
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been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company, and could require the Company to pay damages or make expenditures in amounts that could be material.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$1.10 billion ($659 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil were dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás may restart the accounting proceedings at the Fifth District Court at any time, which would proceed according to the AC’s April 2010 decision. In the Fifth District Court proceedings, the expert’s conclusions will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected, and in turn the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. The parties are disputing the proper venue for the CTEEP lawsuit. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In August 2000, the FERC announced an investigation into the organized California wholesale power markets to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. After hearings at FERC, AES Placerita was found subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001. As FERC investigations and hearings progressed, numerous appeals on related issues were filed with the U.S. Court of Appeals for the Ninth Circuit.
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Over the years, the Ninth Circuit issued several opinions that had the potential to expand the scope of the FERC proceedings and increase refund exposure for AES Placerita and other sellers of electricity. Following remand of one of the Ninth Circuit appeals in March 2009, FERC started a new hearing process involving AES Placerita and other sellers. In May 2009, AES Placerita entered into a settlement, approved by FERC in July 2009, concerning the claims before FERC against AES Placerita relating to the California energy crisis of 2000-2001, including the California refund proceeding. Pursuant to the settlement, AES Placerita paid $6 million and assigned a receivable of $168,119 due to it from the California Power Exchange in return for a release of all claims against it at FERC by the settling parties and other consideration. More than 98% of the buyers in the market elected to join the settlement. A small amount of AES Placerita’s settlement payment was placed in escrow for buyers that did not join the settlement (“non-settling parties”). It is unclear whether the escrowed funds will be enough to satisfy any additional sums that might be determined to be owed to non-settling parties at the conclusion of the FERC proceedings concerning the California energy crisis. However, any such additional sums are expected to be immaterial to the Company’s consolidated financial statements. In November 2009, one non-settling party, the Sacramento Municipal Utility District (“SMUD”), filed an appeal of the FERC’s approval of the settlement which is pending in the Ninth Circuit. SMUD’s appeal has been stayed pending further order of the court. The settlement agreement is still effective and will continue to remain effective unless it is vacated by the Ninth Circuit. SMUD has reached a settlement in principal with buyers of electricity that, if approved by FERC, will leave only immaterial claims of non-settling parties against AES Placerita.
In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd. (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. In September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Orissa Power Generation Corporation Ltd.’s (“OPGC”), an equity method investment, and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPAs terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA’s terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified AES Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgás and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers, and requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FSCP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney’s office has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Public Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($4 million). The injunction was rejected and the case is in the evidentiary stage awaiting the judge’s determination concerning the production of expert evidence. The above-referenced proposal was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response, Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. It is estimated that remediation could cost approximately R$14.7 million ($9 million). Discussions between Sul and CEEE are ongoing.
In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”) filed lawsuits against Itabo, an affiliate of the Company, in the First and Fifth Chambers of the Civil and Commercial Court of First Instance for the National District. CDEEE alleges in both lawsuits that Itabo spent more than was necessary to rehabilitate two generation units of an Itabo power plant and, in the Fifth Chamber lawsuit, that those funds
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
were paid to affiliates and subsidiaries of AES Gener and Coastal Itabo, Ltd. (“Coastal”), a former shareholder of Itabo, without the required approval of Itabo’s board of administration. In the First Chamber lawsuit, CDEEE seeks an accounting of Itabo’s transactions relating to the rehabilitation. In November 2004, the First Chamber dismissed the case for lack of legal basis. On appeal, in October 2005 the Court of Appeals of Santo Domingo ruled in Itabo’s favor, reasoning that it lacked jurisdiction over the dispute because the parties’ contracts mandated arbitration. The Supreme Court of Justice is considering CDEEE’s appeal of the Court of Appeals’ decision. In the Fifth Chamber lawsuit, which also names Itabo’s former president as a defendant, CDEEE seeks $15 million in damages and the seizure of Itabo’s assets. In October 2005, the Fifth Chamber held that it lacked jurisdiction to adjudicate the dispute given the arbitration provisions in the parties’ contracts. The First Chamber of the Court of Appeal ratified that decision in September 2006. In a related proceeding, in May 2005, Itabo filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel CDEEE to arbitrate its claims. The petition was denied in July 2005. Itabo’s appeal of that decision to the U.S. Court of Appeals for the Second Circuit has been stayed since September 2006. Further, in September 2006, in an International Chamber of Commerce arbitration, an arbitral tribunal determined that it lacked jurisdiction to decide arbitration claims concerning these disputes. Itabo believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In April 2006, a putative class action was filed in the U.S. District Court for the Southern District of Mississippi (“District Court”) on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs subsequently appealed to the U.S. Court of Appeals for the Fifth Circuit, which, in October 2009, affirmed the District Court’s dismissal of the plaintiffs’ unjust enrichment, fraudulent misrepresentation, and civil conspiracy claims. However, the Fifth Circuit reversed the District Court’s dismissal of the plaintiffs’ public and private nuisance, trespass, and negligence claims, and remanded those claims to the District Court for further proceedings. In February 2010, the Fifth Circuit granted the petitions for en banc rehearing filed by the Company and other defendants, and thereby vacated its October 2009 decision. In May 2010, the Fifth Circuit dismissed the appeal on the ground that it had lost its quorum for en banc review. In August 2010, the plaintiffs filed a petition for a writ of mandamus in the U.S. Supreme Court, requesting the Supreme Court to direct the Fifth Circuit to reinstate the appeal and return it to the panel that issued the October 2009 decision. In January 2011, the Supreme Court denied the petition, ending the case.
In July 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan (the “Competition Committee”) ordered Nurenergoservice, an AES subsidiary, to pay approximately KZT 18 billion ($120 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee’s order was affirmed by the economic court in April 2008 (“April 2008 Decision”). The economic court also issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. Nurenergoservice’s subsequent appeals to the court of appeals were rejected. In February 2009, the Antimonopoly Agency (the Competition Committee’s successor) seized approximately KZT 783 million ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. However, on appeal to the Kazakhstan Supreme Court, in October 2009, the Supreme Court annulled the decisions of the lower courts because of procedural irregularities and remanded the case to the economic court for reconsideration. On remand, in January 2010, the economic court reaffirmed its April 2008
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Decision. Nurenergoservice’s appeals in the court of appeals (first panel) and the court of appeals (second panel) were unsuccessful. Nurenergoservice intends to file a further appeal to the Kazakhstan Supreme Court. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately KZT 1.8 billion ($12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court was rejected in February 2009. Given the adverse court decisions against Nurenergoservice, the Antimonopoly Agency may attempt to seize Nurenergoservice’s remaining assets, which are immaterial to the Company’s consolidated financial statements. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious defenses to the claims asserted against it; however, there can be no assurances that it will prevail in these proceedings.
In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”), in January through February 2009. The investigation of Shulbinsk HPP is ongoing, but the investigation of UK HPP has been completed. The Antimonopoly Agency determined that UK HPP abused its market position and charged monopolistically high prices for power in January through February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($3 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of UK HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
In April 2009, the Antimonopoly Agency initiated an investigation of Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales in 2008 through February 2009. The Antimonopoly Agency subsequently concluded that UKT abused its market position and charged monopolistically high prices for power and should pay an administrative fine of approximately KZT 136 million ($1 million). The Antimonopoly Agency later sought an order from the administrative court requiring UKT to pay the fine. The administrative court proceedings have been suspended due to a related criminal investigation of UKT employees. If the investigation is terminated and the Antimonopoly Agency prevails in the administrative proceedings, UKT may be ordered to pay the administrative fine and disgorge the profits from the sales at issue, estimated by the Antimonopoly Agency to be approximately 514 million KZT ($3 million). UKT believes it has meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In December 2007, an arbitral tribunal terminated ESSA’s gas supply contracts with members of the Sierra Chata Consortium in light of the restrictions that had been placed on the export of gas by the Argentine Republic. ESSA thereafter terminated its gas transportation contract with Transportadora de Gas del Norte S.A. (“TGN”), and initiated arbitration seeking relief from the obligation to pay the firm tariff under ESSA’s gas transportation contracts with Gasoducto GasAndes (Argentina) S.A. (“GasAndes Argentina”) and Gasoducto GasAndes S.A. (“GasAndes Chile”) or in the alternative, termination of such contracts. TGN (which later filed a lawsuit against ESSA in Argentina), GasAndes Argentina, and GasAndes Chile disputed that the restrictions on the export of gas justified the adjustment or termination of the respective gas transportation contracts and sought due tariff payments. On December 29, 2010, ESSA reached settlement agreements with GasAndes Argentina, GasAndes Chile, and TGN terminating the respective gas transportation contracts and resolving all pending legal disputes and potential future claims. ESSA recognized approximately $72 million as other expense for the three months ended December 31, 2010 related to the settlement agreements. Upon termination of the TGN gas transportation contract, ESSA is no longer required to pay certain charges imposed by the Argentine Republic relating to gas supply infrastructure.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions have contributed to alleged global warming which, in turn, allegedly has led to the erosion of the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit. The parties have briefed the appeal and are awaiting a date for oral argument. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In July, 1993 the Public Attorney’s office filed a claim against Eletropaulo, the Sao Paulo State Government, SABESP (a state-owned company), CETESB (a state-owned company) and DAEE (the municipal Water and Electric Energy Department) alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from the Pinheiros River into the Billings Reservoir. The events in question occurred while Eletropaulo was a state-owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately R$670 million ($401 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. In 2009, the Public Attorney’s Office has filed appeals to both Superior Court of Justice (“SCJ”) and the Supreme Court (“SC”) and such appeals were answered by Eletropaulo in the fourth quarter of 2009. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of Sao Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1 million ($599 thousand) as of December 31, 2010, or pay an indemnification amount of approximately R$10.2 million ($6 million). Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.
In February 2009, a CAA Section 114 information request from the EPA regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. Cayuga and Somerset responded to the EPA’s information request in June 2009, and they are awaiting a response from the EPA regarding their submittal. At this time, it is not possible to predict what impact, if any, this request may have on the Company, its results of operations or its financial position.
On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation (“NYSDEC”) that the facility had exceeded the permitted volume limit of coal ash that can be disposed of in the on-site landfill. Cayuga has met with NYSDEC and submitted a Landfill Liner Demonstration Report to them. Such report found that the landfill has adequate engineering integrity to support the additional coal ash and there is no inherent environmental threat. NYSDEC has indicated they accept the finding of the report. A permit modification was approved by the NYSDEC on May 14, 2010 and
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
such permit modification allows for closure of this approximately 10-acre portion of the landfill. The construction in accordance with the approved permit modification was completed in November 2010 and the certification report for this construction project is currently being drafted to submit to the NYSDEC in the second quarter of 2011. While at this time it is not possible to predict what impact, if any, this matter may have on the Company, its results of operations or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Esado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. The procedural schedules for the arbitrations have been established but the hearing dates have not been scheduled to date. AESU believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously; however, there can be no assurances that it will be successful in its efforts.
In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals (“VCA”) that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant stopped as a consequence of the Supreme Court’s decision. In December 2009, Chilean authorities approved new land use regulations that entitled EEC to apply for a new environmental permit. EEC applied for a new environmental permit in January 2010 and permit approval was granted by the Environmental Authority in February 2010. In March 2010, the Mayor of Puchuncaví and another third party challenged the new environmental permit before the VCA. The parties later entered into a settlement agreement pursuant to which the challenge to the new environmental permit was withdrawn in July 2010. In addition, the construction permit that is required to resume construction of the Plant was issued by the Municipality in August 2010. In September 2010, neighbors of Puchuncaví challenged the construction permit filing claims in the VCA. In November 2010, the VCA rejected the claims. The challenging parties subsequently filed appeals with the Supreme Court. In January 2011, the Supreme Court confirmed the decision of the VCA, finally rejecting the constitutional action. EEC has resumed construction of the Plant.
In June 2009, the Inter-American Commission on Human Rights of the Organization of American States (“IACHR”) requested that the Republic of Panama suspend the construction of AES Changuinola S.A.’s hydroelectric project (“Project”) until the bodies of the Inter-American human rights system can issue a final decision on a petition (286/08) claiming that the construction violates the human rights of alleged indigenous communities. In July 2009, Panama responded by informing the IACHR that it would not suspend construction of the Project and requesting that the IACHR revoke its request. In June 2010, the Inter-American Court of Human Rights vacated the IACHR’s request. With respect to the merits of the underlying petition, the IACHR heard arguments by the communities and Panama in November 2009, but has not issued a decision to date. The Company cannot predict Panama’s response to any determination on the merits of the petition by the bodies of the Inter-American human rights system.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that the proceeds of the sale of electricity from AES Cartagena’s plant should be reduced by roughly the value of the CO2 allowances that were granted to AES Cartagena for free for the years 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately 20 million ($27 million) for 2007 - 2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for 523,548 (approximately $694,000) for the allowances granted for free for 2007 and 19,907,248 (approximately $26 million) for 2008. In July 2010, AES Cartagena received an invoice for approximately 5.4 million ($7 million) for the allowances granted for free for the first half of 2009. AES Cartagena does not expect to be charged for CO2 allowances issued free of charge for subsequent periods. AES Cartagena has paid the amounts invoiced and has filed challenges to the CNE’s demands in the Spanish judicial system. There can be no assurances that the challenges will be successful. AES Cartagena has demanded indemnification from its fuel supply and electricity toller, GDF-Suez, in relation to the CNE invoices under the long-term energy agreement (the “Energy Agreement”) with GDF-Suez. However, GDF-Suez has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena initiated arbitration against GDF-Suez, seeking to recover the payments made to CNE. In the arbitration, AES Cartagena also seeks a determination that GDF-Suez is responsible for procuring and bearing the cost of CO2 allowances that are required to offset the CO2 emissions of AES Cartagena’s power plant, which is also in dispute between the parties. To date, AES Cartagena has paid approximately 20 million ($27 million) for the CO2 allowances that have been required to offset 2008 and 2009 CO2 emissions. AES Cartagena expects that allowances will need to be purchased to offset emissions for subsequent years. The evidentiary hearing in the arbitration took place from May 31-June 4, 2010, and closing arguments were heard on September 1, 2010. In February 2011, the arbitral tribunal requested further briefing from the parties on certain issues in the arbitration. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected and, in turn, there could be a material adverse effect on the Company and its results of operations. AES Cartagena believes it has meritorious claims and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 2009, the Public Defender’s Office of the State of Rio Grande do Sul (“PDO”) filed a class action against AES Sul in the 16th District Court of Porto Alegre, Rio Grande do Sul (“District Court”), claiming that AES Sul has been illegally passing PIS and COFINS taxes (taxes based on AES Sul’s income) to consumers. According to ANEEL’s Order No. 93/05, the federal laws of Brazil, and the Brazilian Constitution, energy companies such as AES Sul are entitled to highlight PIS and COFINS taxes in power bills to final consumers, as the cost of those taxes is included in the energy tariffs that are applicable to final consumers. Before AES Sul had been served with the action, the District Court dismissed the lawsuit in October 2009 on the ground that AES Sul had been properly highlighting PIS and COFINS taxes in consumer bills in accordance with Brazilian law. In April 2010, the PDO appealed to the Appellate Court of the State of Rio Grande do Sul (“AC”). In November 2010, the AC affirmed the dismissal. The PDO is expected to appeal. If the dismissal is ever reversed and AES Sul does not prevail in the lawsuit and is ordered to cease recovering PIS and COFINS taxes pursuant to its energy tariff, its potential prospective losses could be approximately R$9.6 million ($6 million) per month, as estimated by AES Sul. In addition, if AES Sul is ordered to reimburse consumers, its potential retrospective liability could be approximately R$1.2 billion ($718 million), as estimated by AES Sul. AES Sul believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings if it is served with the action; however, there can be no assurances that it would be successful in its efforts. Furthermore, if AES Sul does not prevail in the litigation it will seek to adjust its energy tariff to compensate it for its losses, but there can be no assurances that it would be successful in obtaining an adjusted energy tariff.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from EPA pursuant to CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to EPA’s Prevention of Significant Deterioration and nonattainment New Source Review (“NSR”) requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff and is currently in discussions with the EPA regarding possible resolutions to this NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties and to install additional pollution control technology on coal-fired electric generating units. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery through customer rates of any operating or capital expenditures related to pollution control technology systems to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In November 2009, April 2010 and December 2010, substantially similar personal injury lawsuits were filed by a total of 26 residents and estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic in October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs do not quantify their alleged damages, but generally allege that they are entitled to compensatory and punitive damages. The AES defendants have moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. (The AES Defendants have until mid-February to respond to the December 2010 lawsuit.) In September 2010, the Superior Court heard arguments on the motions. The Superior Court dismissed the plaintiffs’ fraud allegations without prejudice to replead, and the plaintiffs filed amended complaints in November 2010. The AES defendants have filed a renewed motion to dismiss the amended issues. The remaining claims (other than fraud) addressed in the AES defendants’ original motion to dismiss are still pending. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns an unfinished 670MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond is approximately 155 million ($205 million). However, the Contractor obtained a temporary injunction from a French court preventing the issuing bank from honoring the bond demands. As the performance bond is governed by English law, Maritza obtained a judgment from an English court that the bond should be paid, and then presented this judgment to the French court which issued the temporary injunction. However, on February 10, 2011, the French court issued a decision enjoining the issuing bank from honoring the demands on the performance bond pending the determination of the arbitration between Maritza and the Contractor, described below. Maritza is attempting to lift that injunction or otherwise obtain payment on its demands. In addition, in December 2010, the Contractor issued a notice of dispute alleging that the lignite that has been supplied by Maritza for commissioning of the power plant is out of specification, allegedly entitling the Contractor to an extension of time to complete the power plant, an increase to the contract price of approximately 62 million ($82 million), and other relief. The Contractor thereafter advised Maritza that it had stopped commissioning of the power plant’s two units because of the characteristics of the lignite supplied, and, in January 2011, initiated arbitration on its lignite claim. Maritza disputes that the lignite is out of specification and intends to defend the arbitration and assert counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
power plant and other breaches of the EPC contract. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
13. BENEFIT PLANS
DEFINED CONTRIBUTION PLAN-The Company sponsors one defined contribution plan, qualified under section 401 of the Internal Revenue Code. All U.S. employees of the Company are eligible to participate in the plan except for those employees who are not covered by their collective bargaining agreement. The plan provides matching contributions in AES common stock, other contributions at the discretion of the Compensation Committee of the Board of Directors in AES common stock and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company’s matching contributions. Participants vest in other company contributions ratably over a five-year period ending on the fifth anniversary of their hire date. Company contributions to the plans were approximately $22 million, $22 million, and $21 million for the years ended December 31, 2010, 2009, and 2008, respectively.
DEFINED BENEFIT PLANS-Certain of the Company’s subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings. Of the 29 defined benefit plans, three are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.
AES adopted the measurement date provisions of the pension accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans, for the fiscal year ended December 31, 2008 and, accordingly, recognized a cumulative adjustment of $1 million to retained earnings as of December 31, 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table reconciles the Company’s funded status, both domestic and foreign, as of December 31, 2010 and 2009:
The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the funded status of the plans, both domestic and foreign, as of December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes the Company’s accumulated benefit obligation, both domestic and foreign, as of December 31, 2010 and 2009:
The table below summarizes the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of December 31, 2010 and 2009:
A subsidiary of the Company has a defined benefit obligation of $607 million and $549 million as of December 31, 2010 and 2009, respectively, and uses salary bands to determine future benefit costs rather than rates of compensation increases. Rates of compensation increases in the table above do not include amounts related to this specific defined benefit plan.
The Company establishes its estimated long-term return on plan assets considering various factors, which include the targeted asset allocation percentages, historic returns and expected future returns.
The measurement of pension obligations, costs and liabilities is dependent on a variety of assumptions. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The assumptions used in developing the required estimates include the following key factors:
•
discount rates;
•
salary growth;
•
retirement rates;
•
inflation;
•
expected return on plan assets; and
•
mortality rates.
The effects of actual results differing from the Company’s assumptions are accumulated and amortized over future periods and, therefore, generally affect the Company’s recognized expense in such future periods.
Sensitivity of the Company’s pension funded status to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric and are specific to the base conditions at year-end 2010. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The December 31, 2010 funded status is affected by the December 31, 2010 assumptions. Pension expense for 2010 is affected by the December 31, 2009 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the table below (in millions):
The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for the years ended December 31, 2010 through 2008:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes the amounts reflected in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet as of December 31, 2010 that have not yet been recognized as components of net periodic benefit cost:
The following table summarizes the Company’s target allocation for 2010 and pension plan asset allocation, both domestic and foreign, as of December 31, 2010 and 2009:
The U.S. plans seek to achieve the following long-term investment objectives:
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Maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;
•
Long-term rate of return in excess of the annualized inflation rate;
•
Long-term rate of return, net of relevant fees, that meet or exceed the assumed actuarial rate; and
•
Long-term competitive rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage risk through portfolio diversification and takes into account, among other possible factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends. The following table summarizes the Company’s U.S. plan assets by category of investment and level within the fair value hierarchy as of December 31, 2010 and 2009:
(1) Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk. The assumed asset allocation has less exposure to equities in order to closely match market conditions and near term forecasts. The following table summarizes the Company’s foreign plan assets by category of investment and level within the fair value hierarchy as of December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Plan assets of our Brazilian subsidiaries are invested in private equities and commercial real estate through the plan administrator in Brazil. The fair value of these assets is determined using the income approach through annual appraisals based on a discounted cash flow analysis.
(2) Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
(3) Loans to participants are stated at cost, which approximates fair value.
The following table presents a reconciliation of all plan assets measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009:
The following table summarizes the scheduled cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign:
14. EQUITY
STOCK PURCHASE AGREEMENT
On March 12, 2010, the Company and Terrific Investment Corporation (“Investor”), a wholly owned subsidiary of China Investment Corporation, entered into a stockholder agreement (the “Stockholder Agreement”) in connection with the agreement discussed in the following paragraph. Under the Stockholder Agreement, as long as Investor holds more than 5% of the outstanding shares of common stock of the Company, Investor will have the right to designate one nominee, who must be reasonably acceptable to the Board, for election to the Board of Directors of the Company. Investor has not designated its nominee for election to the Board of Directors of the Company. In addition, until such time as Investor holds 5% or less of the outstanding shares of common stock, Investor has agreed to vote its shares in accordance with the recommendation of the
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Company on any matters submitted to a vote of the stockholders of the Company relating to the election of directors and compensation matters. Otherwise, Investor may vote its shares at its discretion. Further, under the Stockholder Agreement, Investor will be subject to a standstill restriction which generally prohibits Investor from purchasing additional securities of the Company beyond the level acquired by it under the stock purchase agreement entered into between Investor and the Company on November 6, 2009. In addition, Investor has agreed to a lock-up restriction such that Investor would not sell its shares for a period of 12 months following the closing, subject to certain exceptions. The standstill and lock-up restrictions also terminate at such time as Investor holds 5% or less of the outstanding shares of common stock. Investor will have certain registration rights and preemptive rights under the Stockholder Agreement with respect to its shares of common stock of the Company.
On March 15, 2010, the Company completed the sale of 125,468,788 shares of common stock to Investor. The shares were sold for $12.60 per share, for an aggregate purchase price of $1.58 billion. Investor’s ownership in the Company’s common stock is now approximately 15% of the Company’s total outstanding shares of common stock on a fully diluted basis.
STOCK REPURCHASE PROGRAM
In July 2010, the Company’s Board of Directors approved a stock repurchase program under which the Company may repurchase up to $500 million of AES common stock. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. The original authorization was set to expire on December 31, 2010, however; in December 2010, the Board authorized an extension of the stock repurchase program. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time. During the year ended December 31, 2010, shares of common stock repurchased under this plan totaled 8,382,825 at a total cost of $99 million plus a nominal amount of commissions (average of $11.86 per share including commissions). There was $401 million remaining under the stock repurchase program available for future repurchases at December 31, 2010.
On August 7, 2008, the Company’s Board of Directors approved a share repurchase plan for up to $400 million of AES common stock. The Board authorization permitted the Company to repurchase shares over a six month period ended February 7, 2009. Shares of common stock repurchased under this plan through December 31, 2008 totaled 10,691,267 at a total cost of $143 million plus commissions of $0.3 million (average of $13.41 per share including commissions). The Board authorization of the stock repurchase program expired on February 7, 2009.
The shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 17,287,073 and 9,534,580 shares were held in treasury stock at December 31, 2010 and 2009, respectively. The Company has not retired any shares held in treasury during the years ended December 31, 2010, 2009 or 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
COMPREHENSIVE INCOME
The components of comprehensive income for the years ended December 31, 2010, 2009 and 2008 were as follows:
(1) Reflects the (income) loss attributed to noncontrolling interests in the form of common securities and dividends on preferred stock.
The following table summarizes the balances comprising accumulated other comprehensive loss, net of tax, as of December 31, 2010 and 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes the net income attributable to The AES Corporation and transfers (to) from noncontrolling interests for the years ended December 31, 2010 and 2009:
15. SEGMENT AND GEOGRAPHIC INFORMATION
The management 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”), each managed by a regional president. The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally. During 2010, the Company modified its internal reporting structure to move the management of the Company’s generation business in Jordan, Amman East, from Asia to Europe. Accordingly, Amman East is now reported within the Europe-Generation segment. All prior periods have been retrospectively restated to reflect this change and conform to current period presentation. The Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and the Company concluded it has six reportable segments which include:
•
Latin America-Generation;
•
Latin America-Utilities;
•
North America-Generation;
•
North America-Utilities;
•
Europe-Generation;
•
Asia-Generation.
Corporate and Other-The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation and Climate Solutions operating segments are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. 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 or gross margin. “Corporate and Other” also includes costs related to corporate overhead costs 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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The Company uses Adjusted Gross Margin, a non-GAAP measure, to evaluate the performance of its segments. Adjusted Gross Margin is defined by the Company as: Gross Margin plus depreciation and amortization less general and administrative expenses.
Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain management fees and self insurance activities which are reflected within segment Adjusted Gross Margin. All intra-segment activity has been eliminated with respect to revenue and Adjusted Gross Margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued or classified as held for sale as of December 31, 2010 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.
The tables below present the breakdown of business segment balance sheet and income statement data as of and for the years ended December 31, 2010 through 2008:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The table below presents information, by country, about the Company’s consolidated operations for each of the years ended December 31, 2010 through 2008 and as of December 31, 2010 and 2009, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Masinloc was acquired in April 2008; 2008 revenue represents results for a partial year.
(2) Cartagena was consolidated effective January 1, 2010 upon implementation of the variable interest entity accounting guidance.
(3) Maritza East 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.
(4) Excludes revenue of $129 million, $163 million and $161 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $501 million as of December 31, 2009 related to Ras Laffan, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
(5) Excludes revenue of $299 million, $470 million and $607 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $36 million as of December 31, 2009 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 and Consolidated Balance Sheets.
(6) Excludes revenue of $62 million, $101 million and $105 million for the years ended December 31, 2010, 2009 and 2008, respectively, and property, plant and equipment of $311 million as of December 31, 2009, related to Barka, which was reflected as discontinued operations and businesses held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
16. SHARE-BASED COMPENSATION
STOCK OPTIONS-AES grants options to purchase shares of common stock under stock option plans. Under the terms of the plans, the Company may issue options to purchase shares of the Company’s common stock at a price equal to 100% of the market price at the date the option is granted. Stock options are generally granted based upon a percentage of an employee’s base salary. Stock options issued under these plans in 2010, 2009 and 2008 have a three-year vesting schedule and vest in one-third increments over the three-year period. The stock options have a contractual term of ten years. At December 31, 2010, approximately 20 million shares were remaining for award under the plans. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.
The weighted average fair value of each option grant has been estimated, as of the grant date, using the Black-Scholes option-pricing model with the following weighted average assumptions:
The Company exclusively relies on implied volatility as the expected volatility to determine the fair value using the Black-Scholes option-pricing model. The implied volatility may be exclusively relied upon due to the following factors:
•
The Company utilizes a valuation model that is based on a constant volatility assumption to value its employee share options;
•
The implied volatility is derived from options to purchase AES common stock that are actively traded;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
•
The market prices of both the traded options and the underlying shares are measured at a similar point in time and on a date reasonably close to the grant date of the employee share options;
•
The traded options have exercise prices that are both near-the-money and close to the exercise price of the employee share options; and
•
The remaining maturities of the traded options on which the estimate is based are at least one year.
Pursuant to share-based compensation accounting guidance, the Company used a simplified method to determine the expected term based on the average of the original contractual term and the pro rata vesting period. This simplified method was used for stock options granted during 2010, 2009 and 2008. This is appropriate given a lack of relevant stock option exercise data. This simplified method may be used as the Company’s stock options have the following characteristics:
•
The stock options are granted at-the-money;
•
Exercisability is conditional only on performing service through the vesting date;
•
If an employee terminates service prior to vesting, the employee forfeits the stock options;
•
If an employee terminates service after vesting, the employee has a limited time to exercise the stock option; and
•
The stock option is nonhedgeable and not transferable.
The Company does not discount the grant date fair values to estimate post-vesting restrictions. Post-vesting restrictions include black-out periods when the employee is not able to exercise stock options based on their potential knowledge of information prior to the release of that information to the public.
Using the above assumptions, the weighted average fair value of each stock option granted was $5.08, $4.08 and $7.65, for the years ended December 31, 2010, 2009, and 2008, respectively.
The following table summarizes the components of stock-based compensation related to employee stock options recognized in the Company’s financial statements:
There was no cash used to settle stock options or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, $5 million of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted average period of 1.5 years. There were no modifications to stock option awards during the year ended December 31, 2010.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
A summary of the option activity for the year ended December 31, 2010 follows (number of options in thousands, dollars in millions except per option amounts):
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on the last trading day of the fourth quarter of 2010 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2010. The amount of the aggregate intrinsic value will change based on the fair market value of the Company’s stock.
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2010, AES has estimated a forfeiture rate of 18.6% and 12.09% for stock options granted in 2010 to non-officer employees and officer employees of AES, respectively. Those estimates will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rates, the Company expects to expense $3.7 million on a straight-line basis over a three year period (approximately $1.2 million per year) related to stock options granted during the year ended December 31, 2010.
RESTRICTED STOCK
Restricted Stock Units Without Market Conditions-The Company issues restricted stock units (“RSUs”) without market conditions under its long-term compensation plan. The RSUs are generally granted based upon a percentage of the participant’s base salary. The units have a three-year vesting schedule and vest in one-third increments over the three-year period. The units are then required to be held for an additional two years before they can be converted into shares, and thus become transferable. In all circumstances, restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.
For the years ended December 31, 2010, 2009, and 2008, RSUs issued without a market condition had a grant date fair value equal to the closing price of the Company’s stock on the grant date. The Company does not discount the grant date fair values to reflect any post-vesting restrictions. RSUs without a market condition granted to non-executive employees during the years ended December 31, 2010, 2009, and 2008 had grant date fair values per RSU of $12.18, $6.71 and $18.87, respectively. The total grant date fair value of RSUs granted in 2010 without a market condition was $13 million.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The following table summarizes the components of the Company’s stock-based compensation related to its employee RSUs issued without market conditions recognized in the Company’s consolidated financial statements:
(1) Amount represents fair market value on the date of conversion.
There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, $11 million of total unrecognized compensation cost related to RSUs without a market condition is expected to be recognized over a weighted average period of approximately 1.8 years. There were no modifications to RSU awards during the year ended December 31, 2010.
A summary of the activity of RSUs without a market condition for the year ended December 31, 2010 follows (number of RSUs in thousands):
The table below summarizes the RSUs without a market condition that vested and were converted during the years ended December 31, 2010, 2009 and 2008 (number of RSUs in thousands):
(1) Net of shares withheld for taxes of 127,000 and 238,000 in the years ended December 31, 2010 and 2009, respectively. No shares were withheld for taxes during the year ended December 31, 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Restricted Stock Units With Market Conditions-Restricted stock units issued to officers of the Company have a three-year vesting schedule and include a market condition to vest. Vesting will occur if the applicable continued employment conditions are satisfied and the Total Stockholder Return (“TSR”) on AES common stock exceeds the TSR of the Standard and Poor’s 500 (“S&P 500”) over the three-year measurement period beginning on January 1st in the year of grant and ending after three years on December 31st. In certain situations where the TSR of both AES common stock and the S&P 500 exhibit a gain over the measurement period, the grant may vest without the TSR of AES common stock exceeding the TSR of the S&P 500, if the Compensation Committee exercises its discretion to permit such vesting. The units are then required to be held for an additional two years subsequent to vesting before they can be converted into shares, and thus become transferable. In all circumstances, restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.
The effect of the market condition on restricted stock units issued to officers of the Company is reflected in the award’s fair value on the grant date for the year ended December 31, 2010. A discount of 5.0% was applied to the closing price of the Company’s stock on the date of grant to estimate the fair value to reflect the market condition for RSUs with market conditions granted during the year ended December 31, 2010. RSUs that included a market condition granted during the year ended December 31, 2010, 2009 and 2008 had a grant date fair value per RSU of $11.57, $6.68 and $16.23, respectively. The total grant date fair value of RSUs with a market condition granted in 2010 was $4 million. If no discount was applied to reflect the market condition for RSUs issued to officers, the total grant date fair value of RSUs with a market condition granted during the year ended December 31, 2010 would have increased by an immaterial amount.
The following table summarizes the components of the Company’s stock-based compensation related to its RSUs granted with market conditions recognized in the Company’s consolidated financial statements:
(1) Amount represents fair market value on the date of conversion.
(2) RSUs granted in 2007 with a market condition did not vest in 2010 because the TSR on AES common stock did not exceed the TSR of the S&P 500 over the three year vesting period.
There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, $5 million of total unrecognized compensation cost related to RSUs with a market condition is expected to be recognized over a weighted average period of approximately 1.7 years. There were no modifications to RSU awards during the year ended December 31, 2010.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
A summary of the activity of RSUs with a market condition for the year ended December 31, 2010 follows (number of RSUs in thousands):
The table below summarizes the RSUs with a market condition that vested and were converted during the years ended 2010, 2009 and 2008 (number of RSUs in thousands):
(1) Net of shares withheld for taxes of 102,000 and 153,000 during the years ended December 31, 2010 and 2009, respectively. There were no shares withheld for taxes during the year ended December 31, 2008.
17. SUBSIDIARY STOCK
The Company’s subsidiary had $60 million of cumulative preferred stock outstanding at December 31, 2010 and 2009. This represented five series of preferred stock of IPL, the Company’s integrated utility in Indiana. The total annual dividend requirements were approximately $3 million at December 31, 2010 and 2009. Certain series of the preferred stock were redeemable solely at the option of the issuer at prices between $100 and $118 per share. Holders of the preferred stock are entitled to elect a majority of IPL’s board of directors if IPL has not paid dividends to its preferred stockholders for four consecutive quarters. Based on the preferred stockholders’ ability to elect a majority of IPL’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity and presented in the mezzanine level of the Consolidated Balance Sheets in accordance with the relevant accounting guidance for noncontrolling interests and redeemable securities.
In February 2009, in connection with a preemptive rights period associated with a share issuance (capital increase) at AES Gener, Inversiones Cachagua Limitada (“Cachagua”), a wholly owned subsidiary of the Company, paid $175 million to AES Gener to maintain its current ownership percentage of approximately 70.6%.
On November 6, 2008, Cachagua sold a 9.6% ownership interest in AES Gener in a private transaction for $174.9 million. The sale reduced the Company’s ownership percentage of AES Gener from 80.2% to 70.6%. The Company recognized a pre-tax loss of $30.8 million, net of $3.6 million of related fees, from this transaction in the fourth quarter of 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
18. OTHER INCOME AND EXPENSE
The components of other income are summarized as follows:
Other income generally includes gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies, and other income from miscellaneous transactions.
Other income of $108 million for the year ended December 31, 2010 included the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and noncontrolling interest was $9 million. Other income also included a gain on sale of assets at Eletropaulo.
Other income of $465 million for the year ended December 31, 2009 included $165 million from the reduction in interest and penalties associated with federal tax debts at Eletropaulo and Sul as a result of the Programa de Recuperacao Fiscal (“REFIS”) program and a $129 million gain related to a favorable court decision enabling Eletropaulo to receive reimbursement of excess non-income taxes paid from 1989 to 1992 in the form of tax credits to be applied against future tax liabilities. The net impact to the Company after income taxes and noncontrolling interests for these items was $44 million. In addition, the Company recognized income of $80 million from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. The management agreement was related to the sale of these businesses in Kazakhstan in May 2008; see further discussion of this transaction in Note 22-Acquisitions and Dispositions.
Other income of $375 million for the year ended December 31, 2008 included gains on the extinguishment of a gross receipts tax liability and a legal contingency at Eletropaulo of $117 million and $75 million, respectively, $32 million of cash proceeds related to a favorable legal settlement at Southland in California, $29 million of insurance recoveries for damaged turbines at Uruguaiana, $23 million of gains associated with a sale of land at Eletropaulo and sales of turbines at Itabo, and compensation of $18 million for the impairment associated with the settlement agreement to shut down Hefei.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The components of other expense are summarized as follows:
Other expense generally includes losses on asset sales, losses on extinguishment of debt, legal contingencies and losses from other miscellaneous transactions.
Other expense of $239 million for the year ended December 31, 2010 included $72 million for a settlement agreement of gas transportation contracts at Gener. There were also previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business. These costs were written off upon the expiration of the letter of intent on June 30, 2010. In addition, there were losses on disposal of assets at Eletropaulo, Panama, and Gener, an $18 million loss on debt extinguishment at Andres and Itabo, and a $15 million loss at the Parent Company from the retirement of senior notes.
Other expense of $111 million for the year ended December 31, 2009 included a $13 million loss recognized when three of our businesses in the Dominican Republic received $110 million par value bonds issued by the Dominican Republic government to settle existing accounts receivable for the same amount from the government-owned distribution companies. The loss represented an adjustment to reflect the fair value of the bonds on the date received. Other expenses also included losses on the disposal of assets at Eletropaulo and Andres and contingencies at Alicura in Argentina and our businesses in Kazakhstan.
Other expense of $161 million for the year ended December 31, 2008 included $69 million of losses on the retirement of debt at the Parent Company in June 2008 and at IPALCO associated with a $375 million refinancing in April 2008, and losses on the disposal of assets primarily at Eletropaulo in Brazil.
19. IMPAIRMENT EXPENSE
Asset Impairment
Asset impairment expense for the year ended December 31, 2010 consisted of:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Eastern Energy-AES Eastern Energy (“AEE”) operates four coal-fired power plants: Cayuga, Greenidge, Somerset and Westover, representing generation capacity of 1,169 MW in the western New York power market. During 2010, the power prices in the New York power market trended downward, similar to North America natural gas prices. The New York Independent System Operator (“NYISO”) continues to move forward with the potential addition of a new capacity zone, which is expected to put further downward pressure on the capacity prices paid to the AEE facilities. In November 2010, legislation was proposed in the state of New Jersey for the addition of state subsidized capacity additions serving to lower PJM (“Pennsylvania, New Jersey and Maryland”) Interconnection, L.L.C. capacity price expectations. Similar changes to capacity pricing may be made in the future in New York. Continued pressure on energy prices, driven by falling natural gas prices and state actions, indicate that capacity prices are unlikely to reach levels significantly in excess of those achieved historically. Accordingly, management’s view of long-term capacity markets in western New York was revised downward. In December 2010, management revised its cash flow forecasts based on these developments and forecasted continuing negative operating cash flow and losses through 2034. The forecasted energy prices are such that a hedge strategy significantly beyond those in place at December 31, 2010 would not be economical. Additionally, on November 15, 2010, Standard & Poor’s downgraded the bond rating of AEE from BB to B+. Collectively, in the fourth quarter of 2010, these events were considered an impairment indicator for the AES New York asset group, of which AEE is the most significant component and necessitated a recoverability test of the asset group.
The long-lived asset group subject to the impairment evaluation was determined to include all of the generating plants of AEE. This determination was based on the assessment of the plants’ inability to generate independent cash flow. When the recoverability test of the asset group was performed, management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was not recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. While there were numerous assumptions that impact the fair value, potential state actions that impact capacity pricing and forward energy prices were the most significant.
In determining the fair value of the asset group, the three valuation approaches prescribed by the fair value measurement accounting guidance were considered. The fair value under the income approach was considered the most appropriate and resulted in a zero fair value. Any salvage value of the asset group is expected to be offset by environmental and other remediation costs. The carrying value of the AEE plants of $827 million exceeded the fair value of $0 million resulting in the recognition of asset impairment expense of $827 million for the year ended December 31, 2010. AEE is reported in the North America Generation segment.
Southland-In May 2010, the California State Water Board approved a policy to reduce the number of marine animals killed by seawater cooling systems in coastal power plants in California. At that time since the policy required the approval of California’s Office of Administrative Law, it was unclear whether the policy would be approved and the exact form the regulations would take. In October 2010, the Office of Administrative Law in California approved the policy that will require the Company to change the process through which it uses ocean water to cool the generation turbines at its Alamitos, Huntington Beach and Redondo Beach (collectively “Southland”) gas-fired generation facilities in California. The policy requires compliance with the new regulations by December 31, 2020. The change in the water cooling process will result in significant future capital expenditures to ensure compliance with the new regulations and the Company determined that an indicator of impairment existed at September 30, 2010. The Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment. The asset group was determined to be at the individual plant level and based on the undiscounted cash flow analysis, the Company determined that
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
the Huntington Beach asset group was not recoverable. The fair value of the Huntington Beach asset group was then determined using a discounted cash flow analysis. To assist management in determining the fair value of the asset group, an independent valuation firm was engaged. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. The carrying value of the Huntington Beach plant of $288 million exceeded the fair value of $88 million resulting in the recognition of asset impairment expense of $200 million for the year ended December 31, 2010. The undiscounted cash flows of the Alamitos and Redondo Beach generation facilities exceeded their respective carrying values and resulted in no impairment. Huntington Beach is reported in the North America Generation reportable segment.
Tisza II-During the third quarter of 2010, the Company entered into annual negotiations with the offtaker of its Tisza II generation plant in Hungary. As a result of these preliminary negotiations, as well as the further deterioration of the economic environment in Hungary, the Company determined that an indicator of impairment existed at September 30, 2010. Thus, the Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment and determined that based on the undiscounted cash flow analysis, the carrying amount of the Tisza II asset group was not recoverable. The fair value of the asset group was then determined using a discounted cash flow analysis. The carrying value of the Tisza II asset group of $160 million exceeded the fair value of $75 million resulting in the recognition of asset impairment expense of $85 million during the year ended December 31, 2010. Tisza II is reported in the Europe Generation reportable segment.
Deepwater-In March 2010, Deepwater, our 160 MW pet coke-fired merchant power plant located in Texas, experienced deteriorating market conditions due to increasing pet coke prices and diminishing power prices. As a result, Deepwater incurred an operating loss for the period and forecasted short term losses. These conditions gradually worsened in the second quarter of 2010 and management determined it could not operate the plant at certain times during the year without generating negative operating margin.
As the contraction of energy margin continued in the second quarter of 2010, management determined the collective events to be an indicator of impairment and performed an impairment evaluation of Deepwater’s goodwill and recoverability test for the long-lived asset group. Based on the results of these tests in the second quarter of 2010, management concluded no impairment was necessary. In the third quarter of 2010, these downward trends continued and management, after determining that there was an indicator of impairment, performed another impairment evaluation of Deepwater’s goodwill and recoverability test of the long-lived asset group. The results in the third quarter indicated no impairment was necessary for the asset group, but the goodwill associated with the reporting unit was deemed to be impaired and the $18 million goodwill balance was written off during the quarter ended September 30, 2010.
In the fourth quarter of 2010, further adverse trends in energy and pet coke pricing curves were observed in management’s review of external market analyses. The most significant impact on the forecasted energy prices reviewed by management in November 2010 related to the general external market consensus that Federal CO2 cap and trade legislation was less likely, resulting in a drop in long-term energy price projections. At that time, Deepwater’s revised forecasts indicated that Deepwater would have operating losses which would extend beyond 2020 and negative cash flows through 2019. Management concluded that, on an undiscounted cash flow basis, the carrying amount of the asset group was no longer recoverable. To measure the amount of impairment loss, management was required to determine the fair value of the asset group. To this end, an independent valuation firm was engaged to assist management in its estimation of fair value. Cash flow forecasts and the underlying assumptions for the valuation were developed by management. In determining the fair value of the asset group, all three valuation approaches described by the fair value measurement accounting guidance were considered.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The fair value under the income approach was considered most appropriate. On that basis, the carrying value of the asset group was determined to be impaired and $79 million of impairment expense was recognized in the fourth quarter of 2010. Deepwater is reported in the North America Generation reportable segment.
Asset impairment expense for the year ended December 31, 2009 consisted of:
During the fourth quarter of 2009, the Company recognized a pre-tax long-lived asset impairment charge of $11 million related to the Company’s Piabanha hydro project in Brazil. The Company determined that the carrying value exceeded the future discounted cash flows and abandoned the project. Piabanha is reported in the Company’s Latin America Generation segment.
Asset impairment expense for the year ended December 31, 2008 consisted of:
In the fourth quarter of 2008 and in response to the financial market crisis, the Company reviewed and prioritized projects in the development pipeline. From this review, the Company determined that the carrying value exceeded the future discounted cash flows for certain projects. In accordance with the accounting standards for the impairment or disposal of long-lived assets, the Company recorded a total pre-tax impairment charge of $75 million ($34 million, net of noncontrolling interests and income taxes) related to two liquefied natural gas projects in North America and a non-power development project at one of our facilities in North America. These projects were reported in the North America Generation segment.
Following an initial impairment charge in the fourth quarter of 2007 at Uruguaiana, there were impairment charges of $36 million recognized during the first three quarters of 2008. The impairment was triggered by a combination of gas curtailments and increases in the spot market price of energy in 2007 that continued in 2008. The additional impairment charges in 2008 were primarily due to fixed asset purchase agreements in place. Uruguaiana is a thermoelectric generation plant located in Brazil and reported in the Latin America Generation segment.
The Company recognized impairment charges totaling $31 million related to a project in South Africa the Company withdrew from during the first quarter of 2008. These represented project development costs and an impairment of turbine deposits related to the project. All costs capitalized and incurred on the project have been written off as no future benefit is expected from these assets. This project was reported in “Corporate and Other.”
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
The Anhui Development and Reform commission issued notice to our Hefei plant in China, in March 2007 as a result of the 2007 State Council’s decision to shut down smaller, inefficient and potentially polluting generation units nationwide. A settlement agreement was signed March 30, 2008 to end the contractual PPA arrangement. In accordance with the accounting standards for goodwill and other intangible assets, management concluded that the assets were impaired in March 2008, since the long-lived asset group would be sold or otherwise disposed of significantly before the end of its previously estimated life. As a result, impairment charges of $18 million were recognized associated with the settlement agreement to shut down the Hefei plant, which is reported in the Asia Generation segment.
Other Impairments
In addition to the asset impairment expense discussed above, other-than-temporary impairments of cost method investments of $1 million, $12 million and $15 million were recorded in the years ended December 31, 2010, 2009 and 2008, respectively. The impairment charges in 2009 and 2008 primarily related to the Company’s investment in a company developing a commercial facility for a “blue gas” (coal to gas) technology project. The Company accounted for the investment in convertible preferred shares under the cost method of accounting. During the fourth quarter of 2008, the market value of the shares materially declined due to downward trends in the capital markets and management concluded that the decline was other-than-temporary and recorded an impairment charge of $10 million. In 2009, this investment was determined to be further impaired and an additional $10 million other-than-temporary impairment charge, representing the remaining value of the shares, was recognized.
20. INCOME TAXES
INCOME TAX PROVISION
The following table summarizes the expense for income taxes on continuing operations, for the years ended December 31, 2010, 2009 and 2008:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
EFFECTIVE AND STATUTORY RATE RECONCILIATION
The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to the Company’s effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2010, 2009 and 2008:
The current income taxes receivable and payable are included in Other Current Assets and Accrued and Other Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent income taxes receivable and payable are included in Other Assets and Other Long-Term Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The following table summarizes the income taxes receivable and payable as of December 31, 2010 and 2009:
DEFERRED INCOME TAXES-Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.
As of December 31, 2010, the Company had federal net operating loss carryforwards for tax purposes of approximately $1.7 billion expiring in years 2023 to 2029. Approximately $68 million of the net operating loss carryforward related to stock option deductions will be recognized in additional paid-in capital when realized. The Company also had federal general business tax credit carryforwards of approximately $18 million expiring primarily from 2020 to 2030, and federal alternative minimum tax credits of approximately $5 million that carryforward without expiration. The Company had state net operating loss carryforwards as of December 31, 2010 of approximately $3.5 billion expiring in years 2016 to 2031. As of December 31, 2010, the Company had
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
foreign net operating loss carryforwards of approximately $4.6 billion that expire at various times beginning in 2011 and some of which carryforward without expiration, and tax credits available in foreign jurisdictions of approximately $37 million, $3 million of which expire in 2011 to 2013, $15 million of which expire in 2014 to 2021 and $19 million of which carryforward without expiration.
Valuation allowances decreased $338 million during 2010 to $1.3 billion at December 31, 2010. This net decrease was primarily the result of the removal of valuation allowances against deferred tax assets at foreign subsidiaries.
Valuation allowances increased $268 million during 2009 to $1.7 billion at December 31, 2009. This net increase was primarily the result of an increase in foreign net operating loss carryforwards that required full offsetting valuation allowances.
The Company believes that it is more likely than not that the net deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income. The Company continues to monitor the utilization of its deferred tax asset for its U.S. consolidated net operating loss carryforward. Although management believes it is more likely than not that this deferred tax asset will be realized through generation of sufficient taxable income prior to expiration of the loss carryforwards, such realization is not assured.
The following table summarizes the deferred tax assets and liabilities, as of December 31, 2010 and 2009:
The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings in accordance with the relevant accounting guidance for income taxes. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The Company’s income tax benefits related to the tax status of these operations are estimated to be $60 million, $35 million and $23 million for the years ended December 31, 2010, 2009 and 2008, respectively. The per share effect of these benefits after noncontrolling interests was $0.07, $0.04 and $0.03 for the year ended December 31, 2010, 2009 and 2008, respectively.
The following table summarizes the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and noncontrolling interests, for the years ended December 31, 2010, 2009 and 2008:
UNCERTAIN TAX POSITIONS
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid in one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
As of December 31, 2010 and 2009, the total amount of gross accrued income tax related interest included in the Consolidated Balance Sheets was $12 million and $21 million, respectively. The total amount of gross accrued income tax related penalties included in the Consolidated Balance Sheets as of December 31, 2010 and 2009 was $4 million and $5 million, respectively.
The total expense (benefit) for interest related to unrecognized tax benefits for the years ended December 31, 2010, 2009 and 2008 amounted to $(10) million, $4 million and $2 million, respectively. For the years ended December 31, 2010, 2009 and 2008, the total expense (benefit) for penalties related to unrecognized tax benefits amounted to $(1) million, $0 million and $(2) million, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:
As of December 31, 2010, 2009 and 2008, the total amount of unrecognized tax benefits was $437 million, $511 million and $555 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2010, 2009 and 2008 is $412 million, $484 million and $527 million, respectively, of which $51 million, $55 million and $131 million, respectively, would be in the form of tax attributes that would warrant a full valuation allowance.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2010 is estimated to be between $4 million and $8 million.
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2010, 2009 and 2008:
The amount of settlements of uncertain tax positions in 2009 was primarily the result of a non-cash audit settlement for $105 million at a Brazilian subsidiary which resulted in no tax expense or benefit.
The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe we have appropriately accrued for our uncertain tax benefits. However, audit
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of current or future examinations may exceed our provision for current unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2010. Our effective tax rate and net income in any given future period could therefore be materially impacted.
21. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES
The following table summarizes the income (loss) on disposal and impairment for the following discontinued operations for the years ended December 31, 2010, 2009 and 2008:
On October 20, 2010, the Company completed the sale of its 55% equity interest in Ras Laffan and the associated operations company in Qatar for aggregate proceeds of approximately $234 million. The Ras Laffan facility, which was previously reported in the Asia Generation segment, is comprised of a 756 MW combined cycle gas plant and a water desalination facility. The Company recognized a gain on disposal of $6 million, net of tax, during the year ended December 31, 2010.
On August 19, 2010, the Company completed the sale of its 35% ownership interest in Barka, a 456 MW combined cycle gas facility and water desalination plant and its wholly owned interest in two Barka related service companies. Barka is located in Oman and was previously reported in the Asia Generation segment. Total consideration received in the transaction was approximately $170 million, of which $124 million was AES’ portion. The Company recognized a gain on disposal of $63 million during the year ended December 31, 2010, net of noncontrolling interest and $38 million of tax expense associated with the sale.
On June 11, 2010, the Company completed the sale of its 55% ownership in Lal Pir and Pak Gen, two oil-fired facilities in Pakistan with respective generation capacities of 362 MW and 365 MW. These businesses were previously reported in the Asia Generation segment. Total consideration received in the transaction was approximately $117 million, of which $65 million was AES’ portion. The Company recognized a loss on disposal of $150 million during the year ended December 31, 2009 and impairment losses totaling $22 million ($14 million, net of tax and noncontrolling interests) during the year ended December 31, 2010 to reflect the change in the carrying value of net assets of Lal Pir and Pak Gen subsequent to meeting the held for sale criteria as of December 31, 2009.
In December 2008, the Company completed the sale of its 70% ownership interest in Jiaozuo AES Wanfang Power Co., Ltd. (“Jiaozuo”), which was reported in the Asia Generation segment, for approximately $73 million
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
net of any withholding taxes. The Company recognized a gain on the sale of approximately $7 million. Goodwill of $4 million was written off in connection with the gain on sale.
Information for business components included in discontinued operations is as follows:
As further discussed in Note 22-Acquisitions and Dispositions, in February 2008, the Company entered into an agreement to sell two of its wholly owned subsidiaries in Kazakhstan, AES Ekibastuz LLP (“Ekibastuz”) and Maikuben West LLP (“Maikuben”). These businesses are included in the Europe Generation segment. The sale was completed on May 30, 2008. As a result of AES’ continuing involvement in the management and operations of the businesses after the sale was completed, their results of operations continued to be reflected as part of income from continuing operations for all periods presented. Revenue recognized subsequent to the sale represented the management fees earned for the Company’s continued management of the operations of the businesses.
22. ACQUISITIONS AND DISPOSITIONS
Acquisitions
The Company completed its acquisition of the Ballylumford Power Station in the third quarter of 2010 and in accordance with the accounting guidance for business combinations, has recorded the preliminary amounts for the purchase price allocation. The purchase price allocation is preliminary and adjustments will continue to be made during the measurement period. Subsequent adjustments, if any, will be retrospectively adjusted in future filings with the SEC.
In April 2008, the Company completed the purchase of a 92% interest in a 660 gross MW coal-fired thermal power generation facility in Masinloc, Philippines (“Masinloc”) from the Power Sector Assets & Liabilities Management Corporation, a state enterprise, for $930 million in cash. Project financing of $665 million was obtained from International Finance Corporation (“IFC”), the Asian Development Bank and a consortium of commercial banks. IFC is also an 8% minority shareholder in Masinloc. AES immediately embarked upon a comprehensive rehabilitation program to improve the output, reliability and general condition of the plant. Including transaction costs and completion of the planned upgrade program to improve environmental and operational performance, the total project cost was approximately $1.1 billion. Beginning on the acquisition date in April 2008, the results of operations of Masinloc are reflected in the Consolidated Financial Statements. The Company finalized the purchase price allocation of this acquisition in the fourth quarter of 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Dispositions
On May 30, 2008, the Company completed the sale of two of its wholly owned subsidiaries in Kazakhstan, Ekibastuz, a coal-fired generation plant, and Maikuben, a coal mine. Total consideration received in the transaction was approximately $1.1 billion plus additional potential earn-out provisions, a three-year management and operation agreement and a capital expenditures program bonus. Due to the fact that AES was to have significant continuing involvement in the management and operations of the businesses through its three-year management and operation agreement, the results of operations from Ekibastuz and Maikuben were included in income from continuing operations through the date of the disposition. Income earned as a result of the three-year management and operation agreement has been recognized as management fee income for all periods subsequent to the disposition.
On March 23, 2009, the Company and Kazakhmys PLC (“Kazakhmys”), which purchased the subsidiaries, mutually agreed to terminate the original sale agreement and the three-year management and operation agreement. In connection with the termination of these agreements, the Company and Kazakhmys entered into a new agreement (the “2009 Agreement”). Under the 2009 Agreement, Kazakhmys agreed to pay the Company an $80 million performance incentive bonus in April 2009 for management services provided in 2008. This was recognized as “Other Income” during the first quarter of 2009. A $13 million gain was recognized related to a reversal of a tax contingency for a contractual obligation, under which the Company provided indemnification to Kazakhmys, which expired in January 2009. This was recorded as an adjustment to the gain on the sale of Ekibastuz and Maikuben during the first quarter of 2009.
The 2009 agreement also provided for an additional $102 million payment, primarily related to the termination of the management agreement, payable to AES in January 2010. In May 2009, Kazakhmys provided an irrevocable standby letter of credit from a creditworthy institution to AES of $102 million to secure the final payment. The payment of the final component of the management termination agreement was not contingent upon any future events. As a result, the Company recognized an additional gain on the sale of Ekibastuz and Maikuben of approximately $98.5 million in the second quarter of 2009. AES received the final payment of $102 million from Kazakhmys in January 2010.
The parties agreed to terminate both the Stock Purchase Agreement and the Management Agreement, and have further agreed to a mutual release of prior claims. As part of the management termination agreement, AES agreed to transition the management of the businesses to Kazakhmys over a period of 100 days from March 13, 2009. The transition period ended June 21, 2009 and at that time the management of Ekibastuz and Maikuben became the responsibility of Kazakhmys. The Company’s involvement with the businesses remained in place for more than one year from the date of the sale; therefore, the Company has continued to include the businesses as part of continuing operations in the Consolidated Financial Statements for all periods presented, despite the termination of the management agreement.
Excluding income earned under the three-year management and operation agreement (terminated in March 2009), Ekibastuz and Maikuben generated no revenue or net income in 2010 and 2009 and generated revenue and net income of $114 million and $61 million, respectively, for the year ended December 31, 2008.
23. EARNINGS PER SHARE
Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.
The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income from continuing operations. In the table below, income represents the numerator (in millions) and shares represent the denominator (in millions):
The calculation of diluted earnings per share at December 31, 2010 excluded all convertible securities, stock options and restricted stock units because they are antidilutive.
The calculation of diluted earnings per share excluded 18,035,813 and 11,150,853 options outstanding at December 31, 2009 and 2008, respectively, that could potentially dilute basic earnings per share in the future. Those options were not included in the computation of diluted earnings per share because the exercise price of those options exceeded the average market price during the related period. In 2009, all convertible debentures were omitted from the earnings per share calculation because they were antidilutive. In 2008, all convertible debentures were included in the earnings per share calculation. In arriving at income attributable to AES Corporation common stockholders in computing basic earnings per share, dividends on preferred stock of our subsidiary were deducted.
In addition, on March 15, 2010, the Company issued 125,468,788 shares of common stock to an investor as described in Note 14-Equity.
24. RISKS AND UNCERTAINTIES
AES is a global power producer in 28 countries on five continents. See additional discussion of the Company’s principal markets in Note 15-Segment and Geographic Information. Our principal lines of business are Generation and Utilities. The Generation line of business uses a wide range of technologies, including coal, gas, hydroelectric, and biomass as fuel to generate electricity. Our Utilities business is comprised of businesses that transmit, distribute, and in certain circumstances, generate power. In addition, the Company continues to expand its reach into the renewables area. These efforts include projects primarily in wind and solar.
POLITICAL AND ECONOMIC RISKS-The Company’s market capitalization was negatively impacted largely in the second half of 2008 and in 2009. During this period, credit markets and global markets deteriorated and experienced increased market volatility, which can pose risks to the overall liquidity and/or asset values of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
our businesses with heightened unpredictability in currencies, counterparty credit risk and the widening of credit spreads in certain markets. If market conditions are protracted or continue to deteriorate, the Company may be at risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets or deterioration in global macroeconomic conditions. With the tightening of the credit markets, there is a risk that future investments may not be able to be financed through accessing capital and debt markets and may be subject to restrictions in the near future.
Currently, the Company has a below-investment grade rating from Standard & Poor’s of BB-. This may limit the ability of the Company to finance new and existing development projects to cash currently available on hand and through reinvestment of earnings. As of December 31, 2010, the Company had $2.6 billion of unrestricted cash and cash equivalents.
During 2010, approximately 84% of our revenue, and all of our revenue from discontinued businesses, was generated outside the United States and a significant portion of our international operations is conducted in developing countries. We continue to invest in projects 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;
•
ability to economically hedge energy prices;
•
volatility in commodity prices;
•
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;
•
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 just result in local jurisdictions; and
•
potentially adverse tax consequences of operating in multiple jurisdictions.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
Any of these factors, individually or in combination with others, could materially and adversely affect our business, results of operations and financial condition. In addition, our Latin American operations experience volatility in revenue and earnings which have caused 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 fluctuations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.
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 businesses where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:
•
changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;
•
changes in the definition or determination of controllable or noncontrollable 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
•
changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect our business.
RISKS RELATED TO FOREIGN CURRENCIES-AES operates businesses in many foreign countries and such operations may be impacted by significant fluctuations in foreign currency exchange rates. The Company’s financial position and results of operations have been significantly affected by fluctuations in the value of the Brazilian real, the Argentine peso, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian peso and the Philippine peso relative to the U.S. Dollar.
RISKS RELATED TO POWER SALES CONTRACTS-Several of the Company’s power plants rely on power sales contracts with one or a limited number of entities for the majority of, and in some case all of, the relevant plant’s output over the term of the power sales contract. The remaining term of the power sales contracts related to the Company’s power plants range from less than one to 38 years. No single customer accounted for 10% or more of total revenue in 2010, 2009, or 2008.
The cash flows and results of operations of such plants are dependent on the credit quality of the purchasers and the continued ability of their customers and suppliers to meet their obligations under the relevant power sales contract. If a substantial portion of the Company’s long-term power sales contracts were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company’s cash flow, results of operations and financial condition.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
25. RELATED PARTY TRANSACTIONS
Our generation businesses in Panama are partially owned by the Government of Panama (the “Panamanian Government”). The Panamanian Government, in turn, partially owns the distribution companies within Panama. For the years ended December 31, 2010, 2009 and 2008, our Panamanian businesses recognized electricity sales to the Panamanian Government totaling $146 million, $143 million and $203 million, respectively. For the same period, our Panamanian businesses purchased electricity, which excludes transmission charges from the Panamanian Government, totaling $21 million, $25 million and $27 million, respectively. As of December 31, 2010 and 2009, our Panamanian businesses owed the Panamanian Government $4 million and $7 million, respectively, payable on normal trade terms. For the same period, the Panamanian Government owed our Panamanian businesses $12 million and $25 million, respectively, payable on normal trade terms.
Our generation businesses in the Dominican Republic are partially owned by the Government of the Dominican Republic (the “Dominican Government”). The Dominican Government, in turn, owns the distribution companies within the Dominican Republic. For the years ended December 31, 2010, 2009 and 2008, our Dominican Republic businesses recognized electricity sales to the Dominican Government totaling $179 million, $204 million and $244 million, respectively. For the same period, the Dominican Government owed our Dominican Republic businesses $88 million and $121 million, respectively, payable on normal trade terms.
In December 2010, ESSA , one of our subsidiaries in Latin America, signed termination agreements related to its long term gas transportation contracts that were under dispute in arbitration tribunals. As a result of these settlements, ESSA paid $52 million to two of the gas transportation companies which are related parties and recorded a loss of $43 million. In addition, an aggregate amount of $16 million was payable to these related parties at December 31, 2010. See Note 12-Contingencies, Litigations for details.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
26. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data
The following tables summarize the unaudited quarterly statements of operations for the Company for 2010 and 2009. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods. Amounts have been restated to reflect discontinued operations in all periods presented.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2010, 2009, AND 2008
(1) Includes pretax impairment expense of $314 million and $927 million, for the third and fourth quarters of 2010, respectively. See Note 19-Impairment Expense and Note 8-Goodwill and Other Intangible Assets for additional discussion on these impairment expenses.
(2) Includes pretax impairment expense $140 million for the fourth quarter of 2009. See Note 19-Impairment Expense and Note 8-Goodwill and Other Intangible Assets for additional discussion on the impairment expense.
27. SUBSEQUENT EVENTS
Subsequent to December 31, 2010, the Company continued to repurchase stock under the stock repurchase program announced on July 7, 2010. The Company has repurchased 1,026,610 shares at a cost of $13 million in 2011, bringing the cumulative total through February 22, 2010 to 9,409,435 shares at a total cost of $112 million (average price of $11.92 per share including commissions). As of February 22, 2011, $388 million of the $500 million authorized remained available under the stock repurchase program. For additional information, see Note 14-Equity.
On February 1, 2011, AES Thames, LLC (“Thames”), our 208 MW coal-fired plant in Connecticut, filed petitions for bankruptcy protection under Chapter 11 in the U. S. Bankruptcy Court. The bankruptcy is due, in part, to the increased cost of energy production. The bankruptcy protection is not expected to have a material impact on the Company’s financial position or the results of operations.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the chief executive officer (“CEO”) and chief financial officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures.
The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2010, our disclosure controls and procedures were effective.
Management’s Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•
provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.
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. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations (“COSO”). Based on this assessment management, believes that the Company maintained effective internal control over financial reporting as of December 31, 2010.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which appears herein.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited The AES Corporation’s internal control over financial reporting as of December 31, 2010 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The AES Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, The AES Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of The AES Corporation and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2010 and our report dated February 25, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
McLean, Virginia
February 25, 2011
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following information is incorporated by reference from the Registrant’s Proxy Statement for the Registrant’s 2011 Annual Meeting of Stock Holders which the Registrant expects will be filed on or around March 1, 2011 (the “2011 Proxy Statement”):
•
Information regarding the directors required by this item found under the heading Board of Directors
•
Information regarding AES’ Code of Ethics found under the heading AES Code of Business Conduct and Corporate Governance Guidelines
•
Information regarding compliance with Section 16 of the Exchange Act required by this item found under the heading Governance Matters-Section 16(a) Beneficial Ownership Reporting Compliance
•
Information regarding AES’ Financial Audit Committee found under the heading The Committees of the Board-Financial Audit Committee (the “Audit Committee”)
Certain information regarding executive officers required by this Item is set forth as a supplementary item in Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this Item, to the extent not included above, will be contained in our 2011 Proxy Statement and is herein incorporated by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following information is contained in the 2011 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the heading Compensation Discussion and Analysis and the Compensation Committee Report on Executive Compensation under the heading Report of the Compensation Committee.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
(a) Security Ownership of Certain Beneficial Owners.
See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the Proxy Statement for the 2011 Annual Meeting of Shareholders of the Registrant, which information is incorporated herein by reference.
(b) Security Ownership of Directors and Executive Officers.
See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the Proxy Statement for the 2011 Annual Meeting of Shareholders of the Registrant, which information is incorporated herein by reference.
(c) Changes in Control.
None.
(d) Securities Authorized for Issuance under Equity Compensation Plans.
The following table provides information about shares of AES common stock that may be issued under AES’ equity compensation plans, as of December 31, 2010:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2010)
(1) The following equity compensation plans have been approved by the Company’s Stockholders:
(A) The LTC Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES’ stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES’ stockholders, bringing the total authorized shares to 38,000,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $14.87 (excluding RSU awards), with 19,723,351 shares available for future issuance.
(B) The AES Corporation 2001 Stock Option Plan adopted in 2001 provided for 15,000,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $14.95. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 2,067,856 shares is not included in Column (c) above.
(C) The AES Corporation 2001 Plan for Outside Directors adopted in 2001 provided for 2,750,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $11.70. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 2,194,404 shares is not included in Column (c) above.
(D) The AES Corporation Second Amended and Restated Deferred Compensation Plan for Directors provided for 2,000,000 shares authorized for issuance. Column (b) excludes the Director stock units granted thereunder. In conjunction with the 2010 amendment to the 2003 Long Term Compensation Plan, ongoing award issuance from this plan was discontinued in 2010 as Director stock units will be issued from the 2003 Long Term Compensation Plan. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 105,341 shares is not included in Column (c) above.
(E) The AES Corporation Incentive Stock Option Plan adopted in 1991 provided for 57,500,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $55.29. This plan terminated on June 1, 2001, such that no additional grants may be granted under the plan after that date. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance in light of this plan’s termination and thus the amount 23,502,620 shares is not included in Column (c) above.
(2) Includes 5,448,036 (2,217,074 of which are vested and 3,230,962 are unvested) shares underlying RSU awards (assuming performance at a maximum level), 778,328 shares underlying Director stock unit awards, and 14,901,643 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 21,128,007 shares.
(3) The AES Corporation 2001 Non-Officer Stock Option Plan provided for 12,000,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan shown in Column (b) is $13.15. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 1,549,919 shares is not included in Column (c) above. This plan is described in the narrative below.
The AES Corporation 2001 Non-Officer Stock Option Plan (the “2001 Plan”) was adopted by the Board on October 18, 2001, and became effective October 25, 2001. The 2001 Plan did not require approval of AES’ stockholders under SEC or NYSE rules and/or regulations at that time. All employees that are not Officers, Directors or beneficial owners of more than 10% of AES’ common stock are eligible to participate in the 2001 Plan. The total aggregate number of shares for which Options can be granted pursuant to the 2001 Plan is 12 million. As of December 31, 2010, approximately 3,423 employees held Options under the 2001 Plan. The exercise price of each Option awarded under the 2001 Plan is equal to the fair market value of AES’ common stock on the grant date of the Option. Options under the 2001 Plan generally vest as to 50% of their underlying shares on each anniversary of the Option grant date; however, grants dated October 25, 2001 vested in one year. Unless otherwise provided by the Compensation Committee of the Board, upon the death or disability of an employee, or a change of control (as defined therein), all Options granted under the 2001 Plan will become fully vested and exercisable. Unless otherwise provided by the Compensation Committee of the Board, in the event that the employee’s employment with the Company terminates for any reason other than death or disability, all Options held by such employee will automatically expire on the earlier of (a) the date the Option would have expired had the employee continued in such employment, and (b) 180 days after the date that such employee’s employment ceases. The 2001 Plan will expire on October 25, 2011. The Board may amend, modify or terminate the 2001 Plan at any time.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information regarding related party transactions required by this item is included in the 2011 Proxy Statement found under the headings Transactions with Related Persons, Proposal I: Election of Directors and The Committees of the Board and are incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information concerning principal accountant fees and services included in the 2011 Proxy Statement contained under the heading Information Regarding The Independent Registered Public Accounting Firm’s Fees, Services and Independence and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements.
(b) Exhibits.
(c) Schedules
Schedule I-Condensed Financial Information of Registrant
Schedule II-Valuation and Qualifying Accounts
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
THE AES CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule I-Condensed Financial Information of Registrant
S-2
Schedule II-Valuation and Qualifying Accounts
S-8
Schedules other than those listed above are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.
S-1
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
UNCONSOLIDATED BALANCE SHEETS
See Notes to Schedule I
S-2
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED OPERATIONS
See Notes to Schedule I
S-3
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED CASH FLOWS
See Notes to Schedule I
S-4
THE AES CORPORATION
SCHEDULE I
NOTES TO SCHEDULE I
1. Application of Significant Accounting Principles
Accounting for Subsidiaries and Affiliates-The AES Corporation (the “Company”) has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated financial information.
Revenue-Construction management fees earned by the parent from its consolidated subsidiaries are eliminated.
Income Taxes-Positions taken on the Company’s income tax return which satisfy a more-likely-than-not threshold will be recognized in the financial statements. The unconsolidated income tax expense or benefit computed for the Company reflects the tax assets and liabilities of the Company on a stand-alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies.
Accounts and Notes Receivable from Subsidiaries-such amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements.
Selected Unconsolidated Balance Sheet Data:
Selected Unconsolidated Operations Data:
S-5
2. Notes Payable
FUTURE MATURITIES OF DEBT-Recourse debt as of December 31, 2010 is scheduled to reach maturity as set forth in the table below:
3. Dividends from Subsidiaries and Affiliates
Cash dividends received from consolidated subsidiaries and from affiliates accounted for by the equity method were as follows:
S-6
4. Guarantees and Letters of Credit
GUARANTEES-In connection with certain of its project financing, acquisition, and power purchase agreements, the Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter of credit and other obligations discussed below, were limited as of December 31, 2010, by the terms of the agreements, to an aggregate of approximately $415 million representing 24 agreements with individual exposures ranging from less than $1 million up to $62 million.
LETTERS OF CREDIT-At December 31, 2010, the Company had $85 million in letters of credit outstanding representing 30 agreements with individual exposures ranging from less than $1 million up to $26 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. During 2010, the Company paid letter of credit fees ranging from 3.19% to 3.75% per annum on the outstanding amounts.
S-7
THE AES CORPORATION
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(IN MILLIONS)
S-8