SEC Form 10-K Filing Report

Company: AES CORP
CIK: 874761
SIC Code: 4991
Filing Date: 2010-02-26 00:00:00
Market Capitalization: 7814402.329499245

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ITEM 1. BUSINESS
Item 1.-Business-Regulatory Matters-North America of this Form 10-K for further information regarding these credits.
Utilities gross margin decreased $22 million, or 8%, from the previous year primarily due to a decrease in wholesale margin of $16 million due to unfavorable prices and increased pension expense of $25 million largely due to the decline in market value of IPL’s pension assets during 2008. These decreases were partially offset by an increase in retail margin of $15 million and a $5 million decrease in property tax expenses. The increase in retail margin was primarily due to the $32 million of voluntary customer credits IPL issued to its to retail customers in 2008 partially offset by lower retail sales volumes in 2009.
The primary drivers for the percentage decline in utilities gross margin being greater than the percentage decline in revenue for the comparable periods are (i) the $25 million increase in pension expense and (ii) the $32 million of voluntary customer credits IPL issued to its retail customers in 2008.
Fiscal Year 2008 versus 2007
Utilities revenue increased $27 million, or 3%, from the previous year primarily due to a $42 million increase in rate adjustments at IPL, related to environmental investments, $42 million of higher fuel and purchased power costs and an $8 million increase in wholesale prices. These increases were offset by $32 million of voluntary customer credits IPL issued to its retail customers in 2008, $16 million of lower retail volume primarily due to unfavorable weather compared to 2007 and an $18 million decrease in wholesale volume.
Utilities gross margin decreased $53 million, or 17%, from the previous year primarily due to lower variable retail margin of $42 million driven by the voluntary customer credits IPL issued to its retail customers in 2008 and lower retail volume. In addition, IPL had higher maintenance expenses of $9 million primarily due to storm restoration costs and the timing and duration of major generating unit overhauls, an increase of $6 million in labor and benefits costs and an increase of $3 million in contractor and consulting costs. These decreases to gross margin were offset by a return recovered through rates on approved environmental investments of $14 million.
Europe-Generation
The following table summarizes revenue and gross margin for our Generation segment in Europe for the periods indicated:
Fiscal Year 2009 versus 2008
Excluding the unfavorable impact of foreign currency translation of $146 million across the region, driven mainly by our businesses in Hungary, Kilroot in the United Kingdom and our businesses in Kazakhstan, generation revenue decreased $230 million, or 21%, from the previous year primarily due to lower revenue of
$101 million as a result of the sale of Ekibastuz and Maikuben in May 2008, lower volume at our businesses in Hungary of $81 million due to the combined impact of the cancellation of one of our PPAs and reduced demand and $67 million at Kilroot, a coal-fired plant, mainly driven by lower dispatch due to favorable gas prices compared to coal. These decreases were partially offset by higher rates of $15 million at our businesses in Kazakhstan.
Excluding the unfavorable impact of foreign currency translation of $35 million, driven mainly by Kilroot and our businesses in Kazakhstan, generation gross margin decreased $36 million, or 14%, from the previous year primarily due to lower gross margin of $41 million as a result of the sale of Ekibastuz and Maikuben in May 2008, lower demand in Hungary of $12 million and an overall increase in fixed costs across the region of $16 million, partially offset by higher capacity revenue at Kilroot and higher energy prices at our businesses in Kazakhstan.
Fiscal Year 2008 versus 2007
Generation revenue increased $187 million, or 21% from the previous year primarily due to an increase in capacity income and energy payments at Kilroot of approximately $105 million, rate recovery and higher volume of approximately $93 million at our businesses in Hungary. In addition, revenue at Kilroot increased approximately $21 million compared to the previous year primarily due to the unfavorable impact of two major overhauls in 2007. These increases were partially offset by a reduction in revenue of approximately $49 million in Kazakhstan following the sale of Ekibastuz and Maikuben in the second quarter of 2008 that was partially offset by approximately $12 million in management fees earned from continuing management agreements for those businesses.
Generation gross margin increased $20 million, or 8% from the previous year primarily due to higher rates and volume of $43 million at Tisza II in Hungary and an increase in capacity income and fewer forced outages at Kilroot of approximately $32 million. These were offset by an increase in fixed costs of $24 million at Kilroot and Tisza II and a reduction in gross margin of $29 million in Kazakhstan following the sale of Ekibastuz and Maikuben in the second quarter of 2008 that was partially offset by $9 million in net gross margin from continuing management agreements for those businesses.
Asia-Generation
The following table summarizes revenue and gross margin for our Generation segment in Asia for the periods indicated:
Fiscal Year 2009 versus 2008
Excluding the unfavorable impact of foreign currency translation of $23 million, primarily in the Philippines and Sri Lanka, generation revenue increased $113 million, or 20% from the previous year primarily due to the benefit of our new businesses, Masinloc in the Philippines, of $46 million which was acquired in April 2008, and Amman East in Jordan, of $50 million, which commenced single cycle operations in July 2008. Revenue also increased $70 million in 2009 at Masinloc due to improved rates and volume as a result of improved availability and new customer contracts, and $18 million from a one-time favorable energy sales settlement. These increases were partially offset by the decrease in revenue of $71 million at Kelanitissa in Sri Lanka primarily due to a decline in fuel costs which are largely passed through to the customer and higher outages in 2009 as compared to 2008.
Excluding the unfavorable impact of foreign currency translation of $6 million, primarily in the Philippines, generation gross margin increased $118 million, or 176% from the previous year primarily due to the impact of our new businesses at Masinloc of $23 million and Amman East of $17 million. The remaining net increase was primarily a result of a $91 million increase at Masinloc due to higher contract sales, where margins are more favorable than spot sales, lower fuel prices, improved availability and the favorable energy sales settlement described above; and higher capacity charges at Kelanitissa of $10 million. These increases were partially offset by higher fixed costs of $20 million at Masinloc.
Generation revenue increased 16% while gross margin increased 167% primarily due to higher contract margins at Masinloc as a result of improved operations, availability and lower fuel prices, as well as the larger relative impact on gross margin from the one-time favorable energy sales settlement described above.
Fiscal Year 2008 versus 2007
Excluding the favorable impact of foreign currency translation of $4 million, generation revenue increased $234 million, or 74% from the previous year primarily due to revenue generated from our new businesses at Masinloc and Amman East of $149 million and $46 million, respectively, and an increase in rates due to pass-through fuel prices at Kelanitissa of $55 million.
Generation gross margin for the twelve months ended December 31, 2008 decreased $15 million, or 18% from the previous year primarily due to a $15 million unfavorable impact on revenue due to an amended PPA accounted for as a lease at Ras Laffan in Qatar. In addition, following the acquisition in April 2008, Masinloc generated a net gross margin loss of $18 million for the year ended December 31, 2008. These unfavorable effects were partially offset by the favorable impact of $14 million from the start up of commercial operations in July 2008 at Amman East.
Corporate and Other
Corporate and other includes the net operating results from our generation and utilities businesses in Africa, utilities businesses in Europe, AES Wind Generation and other climate solutions and renewables projects which are immaterial for the purposes of separate segment disclosure. The following table excludes the elimination of inter-segment activity and summarizes revenue and gross margin for Corporate and Other entities for the periods indicated:
Fiscal Year 2009 versus 2008
Excluding the unfavorable impact of foreign currency translation of $162 million, primarily in the Ukraine, Corporate and Other revenue increased $20 million, or 2%, to $870 million in 2009 from $1.0 billion in 2008. The increase was primarily due to higher tariffs in the Ukraine of $27 million.
Excluding the unfavorable impact of foreign currency translation of $12 million, primarily in the Ukraine, Corporate and Other gross margin increased $67 million, or 108%, to $117 million in 2009 from $62 million in 2008. The increase was primarily due to a decrease in fixed costs partially offset by higher fuel consumption driven by lower hydrology at Sonel, our integrated utility in Cameroon.
Fiscal Year 2008 versus 2007
Excluding the favorable impact of foreign currency translation of $9 million, driven by the favorable impact in Cameroon partially offset by the unfavorable impact in the Ukraine, Corporate and Other revenue increased $214 million, or 27%, to $1.0 billion in 2008 from $789 million in 2007. The increase was primarily due to increased tariffs and volume in the Ukraine of $82 million; an increase of $65 million at our wind generation businesses, primarily due to the expansion of our Buffalo Gap wind facilities in Texas, and an increase in rate and volume of $30 million at Sonel.
Corporate and Other gross margin decreased $35 million, or 36%, to $62 million in 2008 from $97 million in 2007. The decrease was primarily due to increased fixed costs of $55 million at our Utilities businesses in the Ukraine and Cameroon. These were partially offset by the expansion of the Buffalo Gap wind facilities and higher volume and tariffs of $59 million in the Ukraine and Cameroon.
General and Administrative Expense
General and administrative expense includes those expenses related to corporate staff functions and/or initiatives, executive management, finance, legal, human resources, information systems, and certain development costs which are not allocable to our business segments.
General and administrative expenses decreased $26 million, or 7%, to $345 million for the year ended December 31, 2009 from $371 million for the year ended December 31, 2008. The decrease is primarily related to 2008 professional fees associated with remediation efforts and a reduction in business development costs. The favorable variance is partially offset by an increase in current year costs associated with the worldwide implementation of SAP.
General and administrative expenses decreased $7 million, or 2%, to $371 million for the year ended December 31, 2008 from $378 million for the year ended December 31, 2007. The decrease is primarily due to a reduction in professional fees related to material weakness remediation efforts, partially offset by higher spending on SAP implementation projects and the expansion of our renewables initiatives.
Interest expense
Interest expense decreased $288 million, or 16%, to $1.5 billion in 2009 primarily due to lower interest rates globally due to economic conditions and as a result of inflationary adjustments to the market price index in Brazil. In addition, the expense decreased as a result of favorable foreign currency translation, mainly in Brazil, lower interest expenses associated with decreased debt balances at Eletropaulo and lower refinancing costs at IPALCO. These decreases were partially offset by higher interest expenses at our Masinloc plant in the Philippines which was acquired in April 2008, and interest expense at Infovias in Brazil where a fee on a non-exercised credit line was written off.
Interest expense increased $48 million, or 3%, to $1.8 billion in 2008 primarily due to additional interest expense at Masinloc following its acquisition in April 2008, interest expense associated with derivatives at Eletropaulo, Panama and Puerto Rico, as well as unfavorable foreign currency translation in Brazil. These increases were offset by decreases from the elimination of a financial transaction tax in Brazil, a decrease in regulatory liabilities at Eletropaulo, and a decrease in capitalized interest on development projects at Kilroot.
Interest income
Interest income decreased $171 million, or 33%, to $348 million in 2009 primarily due to lower interest rates and lower investment balances in Brazil, unfavorable foreign currency translation on the Brazilian Real, and the impact of decreased interest rates and inflationary adjustments on accounts receivable in 2008 at Gener in Chile, and decreased cash balance at the parent company.
Interest income increased $30 million, or 6%, to $519 million in 2008 primarily due to interest income on short-term investments and cash equivalents at two of our subsidiaries in Brazil, inflationary adjustments on accounts receivable at Gener, and interest earned on a convertible loan acquired in March 2008. These increases were offset by decreases due to lower interest income related to a gross receipts tax recovery at Tietê recorded during the second quarter of 2007 and decreased interest income related to derivatives at TEG/TEP.
Other income
Other income of $466 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 “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 in 2009 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 14-Acquisitions and Dispositions.
Other income of $377 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.
Other income of $358 million for the year ended December 31, 2007 included a $135 million contract settlement gain at Eastern Energy in New York, a $93 million gross receipts tax recovery at Eletropaulo and Tiete, and favorable legal settlements at Eletropaulo and Red Oak in New Jersey.
Other expense
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 expense also included losses on the disposal of assets at Eletropaulo and Andres and contingencies at our businesses in Kazakhstan and Alicura.
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 connection with the refinancing in June 2008, as further discussed in Note 10-Long Term Debt, and IPALCO associated with a $375 million refinancing in April 2008, and losses on disposal of assets primarily at Eletropaulo in Brazil.
Other expense of $253 million for the year ended December 31, 2007 included a loss of $90 million on the retirement of Senior Secured Notes at the parent company, a $28 million charge related to an increase in contingencies in Kazakhstan and losses on the sale and disposal of assets at Eletropaulo and Sul in Brazil.
Goodwill Impairment
In 2009, the Company recognized goodwill impairment expense of $122 million. This was a result of impairment at certain of our businesses in the United Kingdom and Ukraine as a result of the Company’s annual goodwill impairment evaluation as of October 1. The most significant goodwill impairment was at Kilroot, our generation business in the United Kingdom. Factors contributing to the recognition of 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. The fair value of the Company’s reporting units are inherently sensitive to the assumptions underlying the estimates of fair value. Note 1-General and Summary of Significant Accounting Policies, Goodwill and Intangibles, provides a more detailed discussion of those assumptions. As discussed in Key Trends and Uncertainties, in the future, the fair values of the Company’s reporting units might decline as a result of adverse changes in their operating environments or the businesses reaching the end of their finite lives, which could require the Company to record additional goodwill impairment charges.
The Company did not incur any goodwill impairment charge in 2008 and 2007.
Asset Impairment Expense
As discussed in Note 19-Asset Impairment Expense to the Consolidated Financial Statements included in Item 8 of this Form 10-K, asset impairment expense for the year 2009 was $25 million and consisted primarily of the following:
In 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.
Asset impairment expense for the year 2008 was $175 million. 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. As a result, the Company recorded an 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. During 2008, the Company recognized additional impairment charges of $36 million related to long-lived assets at Uruguaiana. 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. Following an initial impairment charge in the fourth quarter of 2007, further charges were incurred in 2008 due to fixed asset purchase agreements in place. During the first half of 2008, the Company withdrew from projects in South Africa and Israel which resulted in impairment charges of $36 million. The Company also recognized an impairment of $18 million related to the shutdown of the Hefei plant in China.
Asset impairment expense for the year 2007 was $408 million and consisted primarily of a pre-tax impairment charge of approximately $352 million at Uruguaiana, a gas-fired thermoelectric plant located in Brazil. The impairment was the result of an analysis of Uruguaiana’s long-lived assets, which was triggered by the combination of gas curtailments and increases in the spot market price of energy. In addition, asset impairments included $25 million from a compressor failure at Placerita, a subsidiary in California and $14 million related to a prepayment advanced to AgCert for a specified amount of future CER credits.
Gain on sale of investments
Gain on sale of investments of $131 million in 2009 consisted primarily of $98 million recognized in May 2009 related to the termination of the management agreement between the Company and Kazakhmys PLC for Ekibastuz and Maikuben, a gain of $14 million from the sale of the remaining assets associated with the shutdown of the Hefei plant in China and $13 million from the reversal of a contingent liability related to the Kazakhstan sale in 2008.
Gain on sale of investments of $909 million in 2008 consisted primarily of the sale in May 2008 of two wholly-owned subsidiaries in Kazakhstan, Ekibastuz and Maikuben for a net gain of $905 million.
(Loss) gain on sale of subsidiary stock
Loss on sale of subsidiary stock of $31 million in 2008 was the result of sales of AES Gener shares made by our wholly-owned subsidiary Cachagua. In November 2008, Cachagua sold 9.6% of its ownership in Gener to a third party reducing its ownership in Gener to 70.6%.
Gain on sale of subsidiary stock in 2007 of $134 million was a result of net gains recognized on sales approximating an 11% ownership interest in Gener reducing our ownership interest in Gener to 80.2%.
In accordance with the new accounting guidance for noncontrolling interests, future transactions of this type will be accounted for as equity transactions and will not result in a gain or loss on the sale.
Foreign currency transaction gains (losses) on net monetary position
The following table summarizes the gains (losses) on the Company’s net monetary position from foreign currency transaction activities:
(1) Includes $(39) million, $10 million and ($22) million of gains (losses) on foreign currency derivative contracts for the years ended December 31, 2009, 2008 and 2007, respectively.
The Company recognized foreign currency transaction gains of $33 million for the year ended December 31, 2009. These consisted primarily of gains in Chile, at The AES Corporation and in the Philippines partially offset by losses in Kazakhstan, Colombia, Argentina and Brazil.
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Gains of $65 million in Chile were primarily due to the appreciation of the Chilean Peso by 20% resulting in gains at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Peso, mainly cash and accounts receivables. This gain was partially offset by $14 million in losses on foreign currency derivatives.
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Gains of $13 million at The AES Corporation were primarily due to the settlement of the senior unsecured credit facility and the revaluation of notes receivable denominated in the Euro, partially offset by losses on debt denominated in British Pounds.
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Gains of $15 million in the Philippines were primarily due to the appreciation of the Philippine Peso of 3%, resulting in gains at Masinloc, a Philippine Peso functional currency subsidiary, on the remeasurement of U.S. Dollar denominated debt.
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Losses of $24 million in Kazakhstan were primarily due to net foreign currency transaction losses of $12 million related to energy sales denominated and fixed in the U.S. Dollar and $12 million of foreign currency transaction losses on debt and other liabilities denominated in currencies other than the Kazakh Tenge.
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Losses of $11 million in Colombia were primarily due to appreciation of the Colombian Peso by 9%, resulting in losses at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso denominated debt and losses on foreign currency derivatives.
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Losses of $10 million in Argentina were primarily due to the devaluation of the Argentine Peso by 10% in 2009, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt, partially offset by derivative gains.
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Losses of $9 million in Brazil were primarily due to energy purchases made by Eletropaulo denominated in U.S. Dollar, resulting in foreign currency transaction losses of $18 million, partially offset by gains of $9 million due to the appreciation in 2009 of the Brazilian Real by 25%, resulting in gains at Sul and Uruguaiana associated with U.S. Dollar denominated liabilities.
The Company recognized foreign currency transaction losses of $184 million for the year ended December 31, 2008. These consisted primarily of losses in Chile, the Philippines, Brazil and Argentina partially offset by gains at The AES Corporation and in Kazakhstan.
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Losses of $102 million in Chile were primarily due to the devaluation of the Chilean Peso by 28% in 2008, resulting in losses at Gener, a U.S. Dollar functional currency subsidiary, associated with its net working capital denominated in Chilean Pesos, mainly cash, accounts receivable and VAT receivables.
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Losses of $57 million in the Philippines were primarily due to remeasurement losses at Masinloc, a Philippine Peso functional currency subsidiary, on U.S. Dollar denominated debt resulting from depreciation of the Philippine Peso of 14% in 2008.
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Losses of $44 million in Brazil were primarily due to the realization of deferred exchange variance on past energy purchases made by Eletropaulo denominated in U.S. Dollar.
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Losses of $22 million in Argentina were primarily due to the devaluation of the Argentine Peso by 10% in 2008, resulting in losses at Alicura, an Argentine Peso functional currency subsidiary, associated with its U.S. Dollar denominated debt.
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Gains of $38 million at The AES Corporation were primarily due to debt denominated in British Pounds and gains on foreign exchange derivatives, partially offset by losses on notes receivable denominated in the Euro.
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Gains of $11 million in Kazakhstan were primarily due to net foreign currency transaction gains of $16 million related to energy sales denominated and fixed in the U.S. Dollar, offset by $5 million of foreign currency transaction losses on external and intercompany debt denominated in other than the Kazakh Tenge functional currency.
Foreign currency transaction gains of $29 million for the year ended December 31, 2007 primarily consisted of gains at The AES Corporation and in Kazakhstan, partially offset by losses in Argentina and Colombia.
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Gains of $31 million at The AES Corporation were primarily the result of favorable exchange rates for debt denominated in British Pounds and the Euro.
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Gains of $10 million in Kazakhstan were primarily due to $12 million of gains related to debt denominated in currencies other than the Kazakh Tenge functional currency, partially offset by $3 million of losses related to energy sales denominated and fixed in the U.S. Dollar.
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Losses of $8 million in Argentina were primarily due to the devaluation of the Argentine Peso by 3% in 2007, resulting in losses of $11 million at Alicura associated with its U.S. Dollar denominated debt.
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Losses of $7 million in Colombia were primarily due to the appreciation of the Colombian Peso by 11% in 2007 at Chivor, a U.S. Dollar function currency subsidiary.
Other non-operating expense
Other non-operating expense was $12 million in 2009, consisting primarily of an other-than-temporary impairment of a cost method investment. During the first quarter of 2009, the market value of the investee’s shares continued to decline due to the downward trends in the capital markets and management concluded that the $10 million decline was other-than-temporary.
Other non-operating expense was $15 million in 2008 and related primarily to an impairment of the Company’s investment in a company developing a “blue gas” (coal to gas) technology project. The Company made this investment in September 2007 and 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. Additionally, the Company recorded an other-than-temporary impairment charge of approximately $5 million related to its investments in other entities developing new energy technology and products.
Other non-operating expense was $57 million in 2007 and reflected the impairment in the Company’s investment in AgCert, a U.K. based corporation, publicly traded on the London Stock Exchange, that produces CER credits. The Company acquired its investment in AgCert in May 2006 and, similar to the circumstances stated above, the market value of the Company’s investment materially declined during the first half of 2007 and the Company recorded an other-than-temporary impairment charge of $52 million in 2007. An additional charge of $5 million was recognized for the decrease in value of the AgCert warrants also held by the Company. The Company began consolidating AgCert in January 2008 when it became the primary beneficiary.
Income taxes
Income tax expense on continuing operations decreased $172 million, or 22%, to $599 million in 2009. The Company’s effective tax rates were 26% for 2009 and 29% for 2008. The decrease in the 2009 effective tax rate was primarily due to tax benefit recorded in 2009 upon the release of valuation allowance at certain U.S. and Brazilian subsidiaries, $165 million of non-taxable income recorded at Brazil as a result of the “REFIS” program in 2009 and an increase in U.S. taxes on distributions from the Company’s primary holding company in the second quarter of 2008.
Income tax expense on continuing operations increased $95 million, or 14%, to $771 million in 2008. The Company’s effective tax rates were 29% for 2008 and 46% for 2007. The decrease in the 2008 effective tax rate was primarily due to the gain of $905 million recorded on the sale of the Kazakhstan businesses in the second quarter of 2008, offset by U.S. taxes on distributions from the Company’s primary holding company to facilitate early retirement of parent debt in 2008. The decrease was also attributable to the implementation of a tax planning strategy that mitigated the impact of the Mexico Flat Rate Business Tax (“IETU”) enacted in the fourth quarter of 2007. The strategy resulted in a reduction to deferred tax expense in 2008 of $24 million and $23 million at TEG and TEP, respectively.
Net equity in earnings of affiliates
Net equity in earnings of affiliates increased $59 million, or 179%, to $92 million in 2009 primarily due to a cash settlement received by Cartagena, in Spain, in June 2009 for liquidated damages received related to a construction delay from December 2005 to November 2006; increased earnings at Guacolda in Chile mainly due to lower cost of coal; increased earnings of Chigen affiliates from higher tariffs partially offset by lower volume and a valuation write-off in 2008 at an affiliate in Turkey. These increases were partially offset by decreased earnings at OPGC, in India, mainly due to lower tariff and a dividend distribution tax in March 2009 and increased expenses for an equipment overhaul at Elsta in the Netherlands.
Net equity in earnings of affiliates decreased $43 million, or 57%, to $33 million in 2008 primarily due to the impact of increased coal prices at Yangcheng, a coal-fired plant in China, a decrease as a result of development costs related to AES Solar, formed in March 2008, and an additional write-off of three projects in Turkey that were abandoned in December 2007. Additionally, earnings decreased due to the sale of an equity investment in a wind project in the fourth quarter of 2007, a decrease in earnings at OPGC, in India, and decreased earnings due to a discontinuance of hedge accounting for a number of interest rate swaps at Guacolda in Chile. These losses were partially offset by a decrease in net losses at Cartagena in Spain primarily from a write-off of deferred financing costs in 2007 that did not recur in 2008.
Income from continuing operations attributable to noncontrolling interests
Income from continuing operations attributable to noncontrolling interests increased $337 million, or 44%, to $1.1 billion in 2009 primarily due to increases in gross margin and other income, lower interest expense and a decrease in impairments in 2009 at our Brazilian businesses, and increases in gross margin and foreign currency transaction gains at our businesses in Chile. In addition, in the fourth quarter of 2009, income from continuing operations attributable to noncontrolling interests increased $44 million at certain of our wind generation businesses as a result of a charge related to the potential future taxes that could be deemed due in the calculation of the hypothetical liquidation value of certain of our wind tax equity partnerships.
Income from continuing operations attributable to noncontrolling interests increased $367 million, or 91%, to $770 million in 2008 primarily due to the decreased losses as a result of the impairment recognized at Uruguaiana during 2007, increased earnings at Eletropaulo, Gener, Itabo, Panama and Tietê, as well as an increase in noncontrolling interests from approximately 20% to approximately 29% as a result of the sale of shares in Gener in November 2008. These increases were partially offset by an impairment recognized in the Bahamas, a net loss at Masinloc, and decreased earnings at Ras Laffan, Sonel, and Caess-EEO & Clesa in El Salvador.
Discontinued operations
As further discussed in Note 21-Discontinued Operations and Held for Sale Businesses to the Consolidated Financial Statements included in Item 8 of this Form 10-K, Discontinued Operations includes the results of seven businesses: Lal Pir and Pak Gen, generation businesses in Pakistan, (held for sale in December 2009); Barka, a generation business in Oman, (held for sale in December 2009); Jiaozuo, a generation business in China, (sold in December 2008); La Electricidad de Caracas (“EDC”), a utility business in Venezuela, (sold in May 2007); Central Valley, a generation business in California (sold in July 2007); and Eden, a utility business in Argentina (sold in June 2007). Prior periods have been restated to reflect these businesses within Discontinued Operations for all periods presented.
In 2009, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $35 million and reflected the operations of our 35% stake in Barka, a combined cycle gas facility and water desalination plant in Oman, and our 55% stake in Pak Gen and Lal Pir, two oil-fired facilities in Pakistan which are under contract for sale in 2010. Loss on disposal of discontinued businesses, net of tax and loss attributable to noncontrolling interests was $105 million and represented the difference between the net book value of the Company’s interests in its Pakistan businesses and their estimated fair value.
In 2008, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $41 million and reflected the operations of Barka, Pak Gen, Lal Pir and Jiaozuo, a coal-fired generation facility in China sold in December 2008. The Company received $73 million for its 70% interest in the business. The net gain on the disposition was $7 million.
In 2007, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $112 million and reflected the operations of Barka, Pak Gen, Lal Pir, Jiaozuo, EDC, Central Valley and Eden. EDC, Eden, and Central Valley were sold in May, June and July 2007, respectively, therefore their results are reflected in the Company’s results of operations through their respective sales dates. Loss on the disposal of discontinued businesses net of tax and loss attributable to noncontrolling interests was $661 million and primarily related to the loss on the sale of EDC.
Critical Accounting Estimates
The Consolidated Financial Statements of AES are prepared in conformity with GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented.
AES’s significant accounting policies are described in Note 1-General and Summary of Significant Accounting Policies to the Consolidated Financial Statements included in Item 8 of this Form 10-K.
An accounting estimate is considered critical if:
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the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made;
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different estimates reasonably could have been used; or
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the impact of the estimates and assumptions on financial condition or operating performance is material.
Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could materially differ from the original estimates, requiring adjustments to these balances in future periods. Management has discussed these critical accounting policies with the Audit Committee, as appropriate. Listed below are the Company’s most significant critical accounting estimates and assumptions used in the preparation of the Consolidated Financial Statements.
Income Tax Reserves
We are subject to income taxes in both the United States and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certain of its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the provision for income taxes. Accounting guidance for uncertainty in income taxes prescribes a more-likely-than-not recognition threshold. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amount of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may exceed current reserves in amounts that could be material.
Goodwill
Effective January 1, 2009, the Company adopted the new accounting guidance on fair value measurement of nonfinancial assets and liabilities measured on a nonrecurring basis. We test goodwill at the reporting unit level for impairment annually on October 1 and whenever events or circumstances indicate it is more likely than not that impairment may have occurred. Such indicators could include a significant adverse change in the business climate or a decision to sell or dispose of all or a portion of a reporting unit. As discussed in detail in Note 1-General and Summary of Significant Accounting Policies, Goodwill and Other Intangibles included in Item 8 of this Form 10-K goodwill impairment is evaluated using a two-step process. The first step is to identify if a potential impairment exists by comparing the fair value of a reporting unit with its carrying value. Determining whether potential impairment exists requires us to estimate the fair value of the respective reporting unit. The new accounting guidance recommends three approaches to measure fair value: 1) Cost approach; 2) Market approach; and 3) Income approach. Historically, an internally developed discounted cash flow model based on the income approach was used to estimate the fair value of reporting units. The Company incorporated several changes in its internal valuation model to align its valuation approach with the new accounting guidance. In the revised valuation model, the fair value of a reporting unit is estimated using internal budgets and forecasts, adjusted for any market participants’ assumptions, discounted at the Weighted Average Cost of Capital (“WACC”). If the fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is not considered to be impaired and no further analysis is required. In determining the fair value, management relies primarily on the results of the income-based approach as most of the valuation assumptions used to derive the discount rate are market observable, directly or indirectly.
Under the income approach, the fair value is the result of the application of a significant number of assumptions related to the discount rate and cash flow forecasts. Many of discount rate-related assumptions are market observable; however, the assumptions underlying our cash flow forecasts involve considerable judgment by management. These include growth rate, terminal value, asset retirement obligations, and macro economic factors such as industry demand, inflation, exchange rates and commodity prices. The fair value of a reporting unit could be sensitive to one or more assumption and different reporting units could be sensitive to different assumptions. Management uses a market-based approach to corroborate the fair value estimated under the income approach and to determine the reasonableness of the fair value derived using the discounted cash flow analysis. As part of the impairment evaluation process, we analyze the sensitivity of a reporting unit’s fair value to underlying assumptions. The level of scrutiny increases as the gap between a reporting unit’s fair value and carrying value decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment of a reporting unit, which could be material. Our impairment analysis inherently involves uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.
If the carrying value exceeds the reporting unit’s fair value, this could indicate potential impairment and step two 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 fair value measurement accounting guidance requires measuring all assets and liabilities at fair value. This includes determining the fair value of unrecognized assets and liabilities not recognized on the books as would be done in a business combination. When a step two analysis must be completed, the fair value of individual assets and liabilities is determined using valuations (which in some cases may be based in part on the reports of external valuation specialists), or other observable sources of fair value, as appropriate.
In 2009, the Company recognized goodwill impairment of $122 million. This was a result of impairment at certain of our businesses in the United Kingdom and Ukraine. The most significant impairment was at Kilroot, our coal-fired generation business in the United Kingdom. Factors contributing to the recognition of impairment included: reduced profit expectations based on the latest estimates of future commodity prices and reduced expectations regarding 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.
Regulatory Assets and Liabilities
The Company accounts for certain of its regulated operations in accordance with the regulatory accounting standards. As a result, AES recognizes assets and liabilities that result from the regulated ratemaking process that would not be recognized under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or included in future rate initiatives. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.
Fair Value
Fair Value of Financial Instruments
A significant number of the Company’s financial instruments are carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period. The Company makes estimates regarding the valuation of assets and liabilities measured at fair value in preparing the Consolidated Financial Statements. These assets and liabilities include short and long-term investments in debt and equity securities, included in the balance sheet line items “Short-term investments” and “Other assets (Noncurrent)”, derivative
assets, included in “Other current assets” and “Other assets (Noncurrent)” and derivative liabilities, included in “Accrued and other liabilities (current)” and “Other long-term liabilities”. The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices are not available, valuation models are applied to estimate the fair value using the available observable inputs. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. Investments are generally fair valued based on quoted market prices or other observable market data such as interest rate indices. The Company’s investments are primarily certificates of deposit, government debt securities and money market funds. Derivatives are valued using observable data as inputs into internal valuation models. The Company’s derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 6-Fair Value of Financial Instruments.
Accounting for Derivative Instruments and Hedging Activities
We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity and foreign currency exposures. We do not enter into derivative transactions for trading purposes.
In accordance with the accounting standards for derivatives and hedging, we recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value except where derivatives qualify and are designated as “normal purchase/normal sale” transactions. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments are recognized in the same category as generated by the underlying asset or liability.
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 and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging.
The Company adopted the fair value measurement accounting standard for financial assets and liabilities on January 1, 2008. The standard provides additional guidance on the definition of fair value and defines fair value as 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 fair value measurement standard requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). These factors were not previously considered in the fair value calculation. Due to the nature of the Company’s interest rate swaps, which are typically associated with non-recourse debt, credit risk for AES is evaluated at the subsidiary level rather than at the Parent Company level. Nonperformance risk on the Company’s derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally developed valuation models that utilize observable market inputs.
As a result of uncertainty, complexity and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings (both ours and our counterparty’s), and exchange rates.
The fair value of our derivative portfolio is generally determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument 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 a financial instrument’s fair value. In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. Additionally, in the absence of quoted prices, we may rely on “indicative pricing” quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps. These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered observable market data. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.
Fair Value of Nonfinancial Assets and Liabilities
The Company adopted the fair value measurement accounting guidance for nonfinancial assets and liabilities effective January 1, 2009. The most significant of these estimates surround the fair value measurement of long-lived tangible and intangible assets when tested for impairment upon a triggering event or during the annual impairment evaluation for indefinite-lived intangible assets, including goodwill. These estimates include making assumptions regarding useful life, the impact of economic obsolescence and expected future cash flows. Additional factors considered for goodwill are discussed above in the Goodwill section.
Fair Value Hierarchy
The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices are not available, valuation models are applied to estimate the fair value using the available observable inputs. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for 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 standard creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. A financial instrument’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. For more information regarding the fair value hierarchy, see Note 1-General and Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this Form 10-K.
New Accounting Pronouncements
Effective January 1, 2009, we adopted new accounting provisions related to the following topics as a result of new accounting guidance issued by the Financial Accounting Standards Board (“FASB”).
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Fair Value Measurement of Nonfinancial Assets and liabilities on a Nonrecurring Basis. As explained above, we adopted the fair value accounting guidance for nonfinancial assets and liabilities.
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Noncontrolling Interests in Consolidated Financial Statements. This guidance changed our accounting and reporting for minority interests, which are now classified as a component of equity and referred to as noncontrolling interests. This guidance resulted in the reclassification of minority interest previously classified outside of equity into equity with their title renamed to “Noncontrolling Interests” in the accompanying consolidated balance sheets and statement 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 accompanying consolidated statements of operations and statements of changes in equity. Financial statements for all periods presented in this form have been reclassified to conform to the new presentation requirements, as required by SEC regulations.
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Business Combinations-This guidance has significantly changed how business acquisitions are accounted for at their acquisition date and in subsequent periods. The new guidance changes the accounting for the business combination at the acquisition date to a fair value based approach rather than the cost allocation approach previously used. Other differences include changes in the accounting for acquisition related costs, contingencies and income taxes. This new guidance is applicable prospectively for business combinations that occurred after January 1, 2009.
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Determination of the Useful Life of Intangible Assets. The new accounting guidance amended the factors we must consider when developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The new guidance requires a consistent approach between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of an asset as required under the business combination accounting guidance. In addition, enhanced disclosures are required when an intangible asset’s expected future cash flows are affected by an entity’s intent and/or ability to renew or extend the arrangement. The new guidance was applied prospectively and the adoption did not have a material impact on our financial condition, results of operations or cash flows.
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Equity Method Investment Accounting Considerations-The new accounting guidance clarified the accounting for certain transactions and impairment considerations involving equity method investments. The adoption of this guidance, which was applied prospectively, did not have a significant impact on our current practice.
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Fair Value Measurement and Disclosures for Liabilities-The new accounting guidance provided clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using either a valuation technique that uses the quoted price of the identical liability when traded as an asset or quoted prices for similar liabilities or similar liabilities when traded as assets or another valuation technique that is consistent with the fair value principles of the income approach or market approach. It also clarified that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs to reflect the existence of a restriction that prevents the transfer of the liability. The adoption of this guidance did not have a material impact on the Company’s financial statements.
Accounting Pronouncements Issued But Not Yet Effective
The following accounting standards have been issued, but as of December 31, 2009, are not yet effective for and have not been adopted by AES.
ASU No. 2009-17, Consolidations, Improvements to Financial Reporting by Enterprises involved with Variable Interest Entities (“ASU No. 2009-17”) (former FAS No. 167, Amendments to FASB Interpretation No. 46(R))
In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities (“VIEs”). The amendment requires an entity to qualitatively, rather than quantitatively, assess the determination of the primary beneficiary of a VIE. This determination should be 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: the requirement for an ongoing reconsideration of the primary beneficiary, the criteria 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 the expansion of the disclosures previously required. As a result of this guidance we will be required to consolidate the assets, liabilities and operating results of certain VIEs, including certain entities currently accounted for under the equity method of accounting, as further described below. It may also require the Company to deconsolidate certain VIEs that are currently consolidated. The impact of the adoption may be applied retrospectively with a cumulative-effect adjustment to retained earnings as of the beginning of the first year restated, or through a cumulative-effect adjustment on the date of adoption. This guidance is effective for fiscal years beginning after November 15, 2009, or January 1, 2010 for AES. Early adoption is prohibited.
Based on its review to date, the Company has determined that an entity that had not been previously consolidated will be required to be consolidated upon the adoption of the new standard. Cartagena, the Company’s generation business in Spain, in which it has a 71% equity interest, is currently accounted for under the equity method of accounting and expected to be consolidated upon the adoption of the new VIE accounting guidance beginning in 2010. Total assets and revenue for Cartagena as of and for the year ended December 31, 2009 were $929 million and $147 million, respectively. The Company is still in the process of quantifying the expected impact of the cumulative adjustment to be recorded upon adoption of the new VIE guidance. AES is in the process of completing its review of the potential impact of the adoption of this guidance and may identify additional entities to consolidate or deconsolidate upon adoption in the first quarter of 2010.
Capital Resources and Liquidity
Overview
As discussed in Highlights of 2009, the Company continued the initiatives started in 2007 to mitigate our refinancing risks and manage our liquidity at the Parent Company as well as our subsidiaries. These efforts included reducing our discretionary growth investments, amending certain of our credit facilities, issuing recourse debt, terminating our senior unsecured credit facility and reducing our planned spending for overhead and development expenses. In addition, in November 2009, the Company announced a binding stock purchase agreement with CIC, to sell 125.5 million shares of AES stock, representing a 15% ownership stake in the Company. The transaction is expected to close in the first half of 2010 and will generate $1.6 billion of new equity to fund future growth opportunities.
As of December 31, 2009, the Company had unrestricted cash and cash equivalents of $1.8 billion and short term investments of $1.6 billion. In addition, we had restricted cash and debt service reserves of $1.0 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $14.4 billion and $5.5 billion, respectively. Of the approximately $1.8 billion of our short-term non-recourse debt, $1.1 billion is presented as current because it is due in the next twelve months and $612 million relates to defaulted debt. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $214 million of our recourse debt matures within the next twelve months, which we expect to repay using cash on hand at the Parent Company or through net cash provided by operating activities. See further discussion of Parent Company Liquidity below.
The Company has two types of debt reported on its balance sheet: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for construction and acquisition of our electric power plants, wind projects and distribution facilities at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. Recourse
debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisition, including funding for equity investments or to provide loans to the Parent Company’s subsidiaries or affiliates. This Parent Company debt is with recourse to the Parent Company and is structurally subordinated to the debt of the Parent Company’s subsidiaries or affiliates, except to the extent such subsidiaries or affiliates guarantee the Parent Company’s debt.
We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks. For more information on our long-term debt, see Note 10-Debt to the Consolidated Financial Statements included in Item 8 of this Form 10-K.
Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. While the Company believes that this represents an economic hedge, the Company is required to mark-to-market all of these interest rate swaps and other derivatives. Presently, the Parent Company’s only exposure to variable interest rate debt relates to indebtedness under its senior secured credit facilities. On a consolidated basis, of the Company’s $19.9 billion of total debt outstanding as of December 31, 2009, approximately $4.0 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity with our subsidiaries or lenders. In such circumstances, if a subsidiary defaults on its payment or supply obligation, the Parent Company will be responsible for the subsidiary’s obligations up to the amount provided for in the relevant guarantee or other credit support. At December 31, 2009, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our subsidiaries, which were limited by the terms of the agreements, of approximately $410 million in aggregate (excluding investment commitments and those collateralized by letters of credit and other obligations discussed below).
As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other
liquidity needs. At December 31, 2009, we had $204 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. These letters of credit were provided under the senior secured credit facility. During 2009, the Company paid letter of credit fees ranging from 1.63% to 13.34% per annum on the outstanding amounts.
We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available or may not be available on economically attractive terms. See Global Recession discussion above. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.
Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.
As of December 31, 2009, the Company has approximately $301 million of trade accounts receivable related to some of its generation businesses in Latin America classified as other long-term assets. These consist primarily of trade accounts receivable that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond December 31, 2010, or one year past the balance sheet date. All payments are being received as scheduled and the Company expects all of these receivables to be fully collectible. Additionally, the current portion of these trade accounts receivable was $137 million at December 31, 2009.
AES Solar, one of our equity investments, was formed in March 2008 as a joint venture with Riverstone. Under the terms of the AES Solar joint venture agreement, the Company and Riverstone may each provide up to $500 million of capital through 2013. AES Solar has commitments to purchase solar panels for use in their business and, while the Company is not required to fund AES Solar’s obligations, it is possible that if we decide not to fund the joint venture in the future it could impact AES Solar’s development plans or operations.
On September 15, 2009, the Company filed a registration statement on Form S-3 with the SEC which will allow the Company to quickly access the capital markets to sell any of a variety of debt and/or equity securities in order to fund refinancings, new investments such as development projects and/or acquisitions, working capital or general corporate purposes. The Form S-3 may also be used to register the resale of securities offered in a private offering of securities.
Capital Expenditures
The Company spent $2.5 billion, $2.9 billion and $2.5 billion on capital expenditures in 2009, 2008 and 2007, respectively. A significant majority of these costs were funded with non-recourse debt consistent with our financial strategy. At December 31, 2009, the Company had a total of $1.1 billion of availability under long-term non-recourse construction credit facilities. As more fully described in Operational Challenges and Global Recession above, we have taken steps to decrease the amount of new discretionary capital spending. We expect to continue funding projects that are currently in the construction phase using existing capital provided by these non-recourse credit facilities as supplemented by internally generated cash flows, Parent Company liquidity, contribution from existing or new partners and other funding sources. As a result, property, plant and equipment and
long-term non-recourse debt are expected to increase over the next few years even though the rate of discretionary spending has been decreased. While we believe we have the resources to continue funding the projects in construction, there can be no assurances that we will continue to fund all these existing construction efforts.
As of December 31, 2009, the Parent Company had $91 million in commitments to invest in our subsidiaries projects under construction and to purchase related equipment, excluding $149 million of such obligations already included in the letters of credits discussed above. The Company expects to fund these net investment commitments over time according to the following schedule: $77 million in 2010, $14 million in 2011 and no investments in 2012. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.
Environmental Capital Expenditures
The Company continues to assess the possible need for capital expenditures associated with international, federal, regional and state regulation of GHG emissions from electric power generation facilities. Legislation and regulations regarding GHG emissions, if enacted, may place significant costs on GHG emissions from fossil fuel-fired electric power generation facilities, particularly coal-fired facilities, and in order to comply, CO2 emitting facilities may be required to purchase additional GHG emissions allowances or offsets under cap-and-trade programs, pay a carbon tax or install new pollution-control equipment to capture and reduce the amount of GHG emitted from the facilities, in the event that reliable technology to do so is developed. The capital expenditures required to comply with any future GHG legislation and regulations could be significant and unless such costs can be passed on to customers or counterparties, such regulations could impair the profitability of some of the electric power generation facilities operated by our subsidiaries or render certain of them uneconomical to operate, either of which could have a material adverse effect on our consolidated results of operations and financial condition.
With respect to our operations outside the United States, certain of the businesses operated by the Company’s subsidiaries are subject to compliance with EU ETS and the Kyoto Protocol in certain countries and other country-specific programs to regulate GHG emissions. To date, compliance with the Kyoto Protocol and EU ETS has not had a material adverse effect on the Company’s consolidated results of operations, financial condition and cash flows because of, among other factors, the cost of GHG emission allowances and/or the ability of our businesses to pass the cost of purchasing such allowances on to customers or counterparties. However, in the event that such counterparties or regulatory authorities challenge our ability to pass these costs on, there can be no assurance that the Company and/or the relevant subsidiary would prevail in any such dispute. Furthermore, even if the Company and/or the relevant subsidiary does prevail, it would be subject to the cost and administrative burden associated with such dispute.
As discussed in Item 1 - Business-Regulatory Matters-Environmental and Land Use Regulations, in the United States there presently are no federal laws or regulations regulating GHG emissions, although several legislative proposals are currently under consideration. In 2009, the Company’s subsidiaries operated businesses which had total approximate CO2 emissions of 74.2 million metric tonnes (ownership adjusted). Approximately 39.7 million metric tonnes of the 74.2 million metric tonnes were emitted in the U.S. (both figures ownership adjusted). Approximately 9.7 million metric tonnes were emitted in U.S. states participating in the RGGI. At this time, the federal legislative proposals under consideration applicable to electric power generation facilities generally incorporate market-based cap-and-trade programs which authorize facilities to comply through the acquisition of emissions allowances in lieu of capital expenditures. Certain of the states, either alone or as part of a regional initiative, in which our subsidiaries operate are in the process of developing programs to reduce GHG emissions, primarily CO2, from the electric power generation facilities through cap-and-trade programs, which would allow CO2 emitting facilities to comply by purchasing additional GHG emission allowances or offsets under cap-and-trade programs or by installing new pollution-control equipment to capture and reduce the amount of GHG emitted from the facilities, in the event that reliable technology to do so is developed. We believe that legislative or regulatory actions, if enacted, may require a material increase in capital expenditures at our subsidiaries.
In the future the actual impact on our subsidiaries’ capital expenditures from any potential federal program to regulate and reduce GHG emissions, if enacted, and the state and regional programs in the process of development, will depend on a number of factors, including among others, the GHG reductions required under any such legislation or regulations, the price and availability of offsets, the extent to which our subsidiaries would be entitled to receive GHG emission allowances without having to purchase them, the quantity of allowances which our subsidiaries would have to purchase, the price of allowances, our subsidiaries’ ability to recover or pass-through costs incurred to comply with any legislative or regulatory requirements that are ultimately imposed and the use of market-based compliance options such as cap-and-trade programs. Another factor is the success of our climate solutions business, which may generate credits that will help offset our GHG emissions. However, as set forth in the Risk Factor titled “Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges,” there is no guarantee that the climate solutions business will be successful. Even if our climate solutions business is successful, the level of benefit is unclear with regard to the impact of legislation or regulation concerning GHG emissions.
Potential Sources of Capital
On November 6, 2009 we entered into a stock purchase agreement with an affiliate of CIC in which the Company agreed to sell 125.5 million shares of the Company’s common stock for $12.60 per share, for an aggregate purchase price of $1.58 billion. After this sale, these shares will represent approximately a 15% interest in the Company. The closing of the sale is subject to certain regulatory approvals and is expected to close in the first half of 2010. Additionally, in November 2009, the Company announced the signing of a letter of intent with an affiliate of CIC to raise an additional $571 million of equity for an approximate 35% interest in our wind generation business.
In December 2009, the Company announced agreements to sell our entire interests in our businesses in Oman and Pakistan for approximately $200 million. These deals are expected to close in the first half of 2010.
Consolidated Cash Flows
At December 31, 2009, cash and cash equivalents increased $928 million from December 31, 2008 to $1.8 billion. The increase in cash and cash equivalents was due to $2.2 billion of cash provided by operating activities, $1.9 billion of cash used for investing activities, $610 million of cash provided by financing activities and the favorable effect of foreign currency exchange rates on cash of $22 million.
At December 31, 2008, cash and cash equivalents decreased $1.2 billion from December 31, 2007 to $881 million. The decrease in cash and cash equivalents was due to $2.2 billion of cash provided by operating activities, $3.6 billion of cash used for investing activities, $362 million of cash provided by financing activities and the unfavorable effect of foreign currency exchange rates on cash of $96 million.
Operating Activities
Net cash provided by operating activities increased $52 million to $2.2 billion during 2009 compared to $2.2 billion during 2008. This net increase was primarily due to the following:
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an increase of $238 million at our Latin American Generation businesses due to improved working capital management; and
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an increase of $188 million at our Asia Generation businesses due to improved working capital management and improved gross margin;
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an increase of $85 million at our Europe Generation businesses primarily due to the collection of the $80 million Kazakhstan management performance incentive bonus in the first quarter 2009; offset by
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a decrease of $391 million at our Latin American Utilities businesses due to increased working capital requirements, including the payment on the settlement of a swap agreement, increased tax payments associated with a tax amnesty program and increased payments related to the settlement of contingencies and energy purchases, partially offset by increased operating results; and
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a decrease of $77 million at our North America Generation businesses, primarily due to reduced operating results.
Investing Activities
Net cash used for investing activities decreased $1.7 billion to $1.9 billion during 2009 compared to net cash used of $3.6 billion during 2008. This decrease was largely attributable to the following:
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a decrease of $330 million in capital expenditures to $2.5 billion primarily from an overall decrease in expenditures of $227 million at Maritza in Bulgaria, $143 million for our U.S. wind generation projects, $74 million in Brazil, and $64 million in Jordan, partially offset by an increase of $161 million for plant construction at Gener;
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a decrease of $1.1 billion of acquisitions as a result of no acquisitions in 2009. In 2008, acquisitions consisted primarily of the purchase of Masinloc, a 660 gross MW coal-fired thermal power generation facility purchased during the second quarter of 2008 for approximately $930 million, as discussed in Note 22-Acquisitions and Dispositions to the Consolidated Financial Statements included in Item 8 of this Form 10-K. We also acquired Mountain View in the U.S. during the first quarter of 2008;
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a decrease of $1.3 billion in proceeds from the sales of businesses to $2 million in 2009. The proceeds in 2008 included $1.1 billion from the sale of Ekibastuz and Maikuben, $171 million in net proceeds from the sale of a 10% ownership interest in AES Gener and $73 million in proceeds from the sale of Jiaozuo;
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a decrease of $597 million from the sale of short-term investments, net of purchases, including increases in net sales of $553 million at our Brazilian subsidiaries, to fund dividend payments. In addition, there was an increase in net sales of $184 million and $78 million at Alicura in Argentina and Masinloc, respectively, due to maturities of investments and an increase in net sales of $79 million at IPALCO as a result of IPL’s variable rate demand notes being successfully remarketed. This was partially offset by a $317 million increase in net purchases at Gener related to the purchase of time deposits;
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a $302 million decrease in restricted cash in 2009 including decreases of $216 million at Gener from the use of the proceeds raised in the fourth quarter of 2008 that were restricted to use only for the purchase of additional shares in the first quarter of 2009 to fund future construction, $72 million at Chigen used for debt repayment, and $41 million in New York, partially offset by an increase of $39 million at Masinloc; and
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a $134 million reduction in cash used for advances to affiliate and equity investments, loan advances and other investing activities.
Financing Activities:
Net cash provided by financing activities increased $248 million to $610 million during 2009 compared to $362 million during 2008. This increase was primarily attributable to the following:
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a decrease in net borrowings under revolving credit facilities of $287 million primarily from increased net repayments of $172 million at Lal Pir/Pak Gen in Pakistan due to off-taker collections, $64 million due to increased net repayments at IPALCO to pay off a line of credit in 2009, and a $22 million reduction in net borrowings at Panama for project financing;
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a decrease of $283 million from issuances of recourse and non-recourse debt primarily due to decreases in the issuance of non-recourse debt of $603 million at Masinloc, $262 million at IPL, and $10 million at our wind development projects at our U.S. businesses in 2009. These decreases were partially offset by increases in the issuance of non-recourse debt of $347 million at Eletropaulo and $316 million at Gener;
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a $1,135 million decrease in repayments of recourse debt and non-recourse debt, predominantly due to decreases in repayments of recourse debt of $883 million at the Parent Company and non-recourse debt of $257 million at IPL; partially offset by
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a $249 million increase in distributions to noncontrolling interests, primarily due to $120 million higher dividends distributions at Eletropaulo and $110 million higher dividends declared to noncontrolling interests at Brasiliana Energia; and
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a $220 million decrease in contributions from noncontrolling interests primarily due to a reduction of $201 million at our U.S. wind generation projects.
Contractual Obligations
A summary of our contractual obligations, commitments and other liabilities as of December 31, 2009 is presented in the table below (in millions):
(1) Includes recourse and non-recourse debt presented on the Consolidated Financial Statements. Non-recourse debt borrowings are not a direct obligation of AES, the Parent Company. Recourse debt represents the direct borrowings of AES, the Parent Company. See Note 10-Debt to the Consolidated Financial Statements included in Item 8 of this Form 10-K which provides additional disclosure regarding these obligations. These amounts exclude capital lease obligations which are included in the capital lease category, see (3) below.
(2) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2009 and do not reflect anticipated future refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2009.
(3) Several AES subsidiaries have leases for operating and office equipment and vehicles that are classified as capital leases within Property, Plant and Equipment. Minimum contractual obligations include $129 million of imputed interest.
(4) The Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. These amounts exclude amounts related to the sale/leaseback discussed below in item (5).
(5) Sale/Leaseback Obligations-represent a sales/leaseback with operating lease treatment at one of our New York subsidiaries.
(6) Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties.
(7) Operating subsidiaries of the Company have entered into fuel purchase contracts subject to termination only in certain limited circumstances.
(8) Amounts relate to other contractual obligations where the Company has an enforceable and legally binding agreement to purchase goods or services that specifies all significant terms, including: quantity, pricing, and approximate timing. These amounts include planned capital expenditures that are contractually obligated.
(9) These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on the items excluded. Derivatives (See Note 5-Derivative Instruments) and incentive compensation are excluded as the Company is not able to reasonably estimate the timing or amount of the future payments. In addition, the amounts do not include: (1) regulatory liabilities (See Note 9-Regulatory Assets and Liabilities), (2) contingencies (See Note 12-Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 13-Benefit Plans) or (4) any taxes (See Note 20-Income Taxes) except for uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the “Other” column of the table above as the Company is not able to reasonably estimate the timing of the future payments.
Parent Company Liquidity
The following discussion of “Parent Company Liquidity” has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP, as a measure of liquidity. Cash and cash equivalents are disclosed in the Consolidated Statements of Cash Flows and the parent only unconsolidated statements of cash flows in Schedule I of this Form 10-K. Parent Company liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are:
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dividends and other distributions from our subsidiaries, including refinancing proceeds;
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proceeds from debt and equity financings at the Parent Company level, including borrowings under our credit facilities; and
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proceeds from asset sales.
Cash requirements at the Parent Company level are primarily to fund:
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interest;
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principal repayments of debt;
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acquisitions;
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construction commitments;
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other equity commitments;
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taxes; and
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Parent Company overhead and development costs.
The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents” at December 31, 2009 and 2008 as follows:
Recourse Debt Transactions:
On March 26, 2009, the Parent Company and certain subsidiary guarantors amended the Parent Company’s existing senior secured credit facility pursuant to the terms of Amendment No. 1 (“Amendment No. 1”) to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008 (the “senior secured credit facility”). The senior secured credit facility previously included a $200 million term loan facility maturing on August 10, 2011 and a $750 million revolving credit facility maturing on June 23, 2010 (the “revolving credit facility”).
The principal modification set forth in Amendment No. 1 was a one-year extension of $570 million of revolving credit facility commitments from an original maturity date of June 23, 2010 to July 5, 2011. In addition, certain lenders determined that they would increase their commitment under the revolving credit facility by $35 million from March 26, 2009 through July 5, 2011. Accordingly, Amendment No. 1 increased the size of the revolving credit facility from $750 million to $785 million through June 23, 2010. From June 23, 2010 through July 5, 2011, the revolving credit facility size will be $605 million. No modifications were made to the amount or maturity date of the $200 million term loan facility.
The extended commitments from this amendment were subject to new pricing that included an upfront fee of 1.25% for participating in the extensions and an increase in undrawn commitment fees from 50 to 100 basis points. The annual interest rate on the drawn loans was also increased by 200 basis points to LIBOR plus 3.50%. Pricing and all other material terms remain unchanged for the revolving credit facility commitments which have not been extended.
On April 2, 2009 the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes due 2016 in a private placement. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce the size of its $600 million senior unsecured credit facility among the Parent Company, Merrill Lynch Bank USA and the banks party thereto (the “senior unsecured credit facility”). The majority of the letters of credit issued under the facility supported a project under construction in Bulgaria. On October 7, 2009, the Parent Company voluntarily reduced all of the remaining commitments available under the senior unsecured credit facility and terminated the facility agreement. As a result of the termination, the Company recognized a foreign currency transaction gain of $20 million in the fourth quarter of 2009 related to the sale of Euro purchased as collateral at the inception of the facility. The outstanding letters of credit under the senior unsecured credit facility were transferred to the senior secured credit facility.
Recourse Debt:
Our recourse debt at year-end was approximately $5.5 billion, $5.2 billion, and $5.6 billion in 2009, 2008 and 2007, respectively. The following table sets forth our Parent Company contingent contractual obligations as of December 31, 2009:
As of December 31, 2009, the Company had $91 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding $149 million of such obligations already included in the letters of credit discussed above. The Company expects to fund these net investment commitments over time according to the following schedule: $77 million in 2010, $14 million in 2011 and no investments in 2012. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.
We have a diverse portfolio of performance related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, supplies support and liquidated damages under power sales agreements for projects in development, in operation and under construction. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2010 or beyond, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.
While we believe that our sources of liquidity will be adequate to meet our needs 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 markets (see “Operational Challenges” and “Global Recession”), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See

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ITEM 1A. RISK FACTORS

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ITEM 1B. UNRESOLVED STAFF COMMENTS

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS

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ITEM 4. RESERVED

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 we are exposed to volatility in the exchange rate 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.
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 the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold. The portion of our sales and fuel 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 2010, we project approximate pre-tax earnings exposure of $15 million for a $10/barrel move in oil, $50 million for $1/mmbtu move in natural gas and $20 million for a $10/ton shift in coal prices. These 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 corporation’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. Generating costs can be directly affected by movements in prices 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 regulator 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 the North American businesses of Eastern Energy, Deepwater and wholesale power sales of IPL; the Latin American businesses in Chile, Argentina, the Dominican Republic and Panama and the Masinloc business in Asia.
In North America, the variance is due to “dark spread” to the extent a portion of 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. 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 which limits commodity risk. Oil-fired generators set power prices for some periods so lower oil prices can erode margins on spot power market sales. Gener has been adding coal-fired generation in response to the Argentine gas crisis increasing its exposure to dark spreads on un-hedged volumes. Gener also owns natural gas/diesel, hydropower and biomass generating facilities.
In other Latin American markets, the businesses have commodity exposure on open 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 generation and oil-fired generation and other factors.
Our Masinloc business is a coal-fired 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 risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk 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 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 2009, we entered into hedges to partially mitigate the exposure of earnings translated into U.S. Dollar to foreign exchange volatility. Given a 10% U.S. Dollar appreciation, 2010 pre-tax earnings attributable to foreign subsidiaries exposed to movements in the exchange rates of the Argentinean Peso, Brazilian Real, Colombian Peso, and Euro (the earnings attributable to subsidiaries exposed to Cameroonian Franc movements are included under Euro due to the fixed exchange rate of Cameroonian Franc to Euro) relative to the U.S. Dollar are projected to be $5 million, $35 million, $9 million and $10 million respectively. Total AES pre-tax earnings for 2010 would be reduced by approximately $60 million on a correlated basis. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to exposed pre-tax earnings for 2010 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 impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses and the correlation effect is based on historical foreign exchange rate movement over a period equal in length to the period over which the simulated move occurs. 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, 2009, the portfolio’s 2010 pre-tax earnings exposure (adjusted to reflect non-controlling interests) to a 100 basis point increase in Brazilian Real, British Pound, Colombian Peso, Euro, Hungarian Forint, Philippine Peso, Ukraine Hryvnia and U.S. Dollar interest rates is approximately $20 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, Hungarian Forint, Philippine Peso, Ukraine Hryvnia and U.S. Dollar-denominated debt for 2010, which together account for more than 99% of the portfolio’s floating-rate debt which is primarily non-recourse financing. The numbers do not take into account the historical correlation between these interest rates.
Value at Risk
We have performed a company wide value at risk analysis (“VaR”) of all of our material financial assets, liabilities and derivative instruments. VaR measures the potential loss in a portfolio’s value due to market volatility, over a specified time horizon, stated with a specific degree of probability and is calculated based on volatilities and correlations of the different risk exposures of the portfolio. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. VaR is not necessarily indicative of actual results that may occur. Additionally, VaR represents changes in fair value of financial instruments and not the economic exposure to AES and its affiliates.
Because of the inherent limitations of VaR, including those specific to Analytic VaR, in particular the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform sensitivity and scenario analyses to estimate the economic impact of market changes to our portfolio of businesses. We use these results to complement the VaR methodology.
In addition, the relevance of the VaR described herein as a measure of economic risk, is limited and needs to be considered in light of the underlying business structure. Embedded derivatives are not appropriately measured here and are excluded since VaR is not representative of the overall contract valuation. The VaR calculation incorporates numerous variables that could impact the fair value of our instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. The interest rate component of VaR is due to changes in the fair value of our fixed rate debt instruments and interest rate swaps. These instruments themselves would expose a holder to market risk; however, utilizing these fixed rate debt instruments as part of a fixed price contract generation business mitigates the overall exposure to interest rates. Similarly, our foreign exchange rate sensitive instruments are often part of businesses which have revenues denominated in the same currency, thus offsetting the exposure.
We express Analytic VaR herein as a dollar amount of the potential loss in the fair value of our portfolio based on a 95% confidence level and a one-day holding period. Our commodity analysis is a VaR calculation within the commodity transaction management system and is reported for financially settled derivative products at our Eastern Energy business in New York State and physically settled derivative products at AES Deepwater, Inc. in Pasadena, Texas as these are the only businesses with commodity transactions that are deemed derivatives. These commodity transactions are marked to market on a daily basis. Collateral is then posted or
recalled for any changes in exposures at Eastern Energy. However, not every transaction requires Eastern Energy to post collateral, as several counterparties have caps defined in their transaction agreements. For those counterparties that do require Eastern Energy to post collateral, two facilities that are non-recourse to The AES Corporation in the amounts of $75 million and $350 million are used to issue letters of credit. As of December 31, 2009, $19 million and $68 million have been utilized under these facilities. AES Deepwater is not required to post collateral for these commodity transactions.
For the year ended December 31, 2009, our one-day VaR at fourth quarter end for foreign exchange rate-sensitive instruments was $66 million compared to $125 million for the year ended December 31, 2008. This amount includes foreign currency denominated debt and hedge instruments. The decrease in VaR was driven primarily by the decline in volatilities of currencies in our portfolio, notably the Brazilian Real, Chilean Peso, Euro and Philippine Peso.
For the year ended December 31, 2009, our one-day VaR at fourth quarter end for interest rate-sensitive instruments was $108 million compared to $188 million for the year ended December 31, 2008. This amount includes the financial instruments that serve as hedges and the underlying hedged items. The largest component of interest rate VaR is from U.S. dollar-denominated, fixed-rate debt and the decrease in VaR was due to the decrease in volatilities of bond yields.
For the year ended December 31, 2009, our one-day VaR at fourth quarter end for commodity price sensitive instruments was $8 million compared to $7 million for the year ended December 31, 2008. For Eastern Energy, these amounts include the financial instruments that serve as hedges and do not include the underlying physical assets or contracts that are not permitted to be settled in cash. The VaR for Eastern Energy was $7 million compared to $7 million for the year ended December 31, 2008. For Deepwater, the reported VaR includes the physically settled derivative products that serve as hedges. The VaR for Deepwater was $450,000. Starting in the second quarter of 2009, the commodity VaR disclosure includes both AES Eastern Energy and AES Deepwater.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON THE FINANCIAL STATEMENTS
The Board of Directors and Stockholders of The AES Corporation:
We have audited the accompanying consolidated balance sheets of The AES Corporation and its subsidiaries as of December 31, 2009 and December 31, 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the two years in the period ended December 31, 2009. Our audits also included the financial statement schedules for each of the two years in the period ended December 31, 2009 listed in the accompanying Index to 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 its subsidiaries at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules for each of the two years in the period ended December 31, 2009, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
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, 2009, 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, 2010 expressed an unqualified opinion thereon.
/s/: Ernst & Young LLP
McLean, Virginia
February 25, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON THE FINANCIAL STATEMENTS
To the Board of Directors and Stockholders of
The AES Corporation
Arlington, VA
We have audited the accompanying consolidated statements of operations, changes in equity, and cash flows of The AES Corporation and subsidiaries (the “Company”) for the year ended December 31, 2007. Our audit also included the 2007 information in the financial statement schedules listed in the index on page S-1. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our 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 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 statement. 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 audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of The AES Corporation and subsidiaries for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As also discussed in Notes 1, 15, 17 and 21 to the consolidated financial statements, the accompanying 2007 financial statements have been adjusted for the retroactive application of accounting for noncontrolling interests, which was adopted by the Company on January 1, 2009, and for the changes in reportable segments that occurred in 2009.
/s/ Deloitte & Touche LLP
McLean, Virginia
March 14, 2008
(February 25, 2010 as to the Discontinued Operations and Reclassification section of Note 1 and the December 2009 paragraph of Note 21, and the changes in reportable segments described in Note15, September 11, 2009 as to the effects of the adoption of a new accounting standard described in the Noncontrolling Interests section of Note 1, the first paragraph of Note 17, and changes in reportable segments, and February 26, 2009 as to the December 2008 paragraph of Note 21).
THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2009 AND 2008
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007
See Accompanying Notes to these Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009, 2008, AND 2007
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.
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 provided by any parties 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.
The Company is considered the primary beneficiary of a VIE and thus consolidates the VIE when the Company absorbs a majority of expected losses of the VIE, receives a majority of expected residual returns of the VIE (unless another enterprise absorbs the majority of expected losses), or both. Where it is not clear which variable interest holder is the primary beneficiary the Company performs computations and allocations of expected losses and expected residual returns as necessary to determine the primary beneficiary. The primary beneficiary determination has not historically required significant judgments or assumptions to be made.
The Company determines if it is the primary beneficiary when it becomes involved in the VIE. If the Company is the primary beneficiary, it reconsiders this decision when it sells or otherwise disposes of all or part of our variable interests to unrelated parties or if the VIE issues new variable interests to parties other than the Company or its related parties. Conversely, if the Company is not the primary beneficiary, it reconsiders this decision when it acquires additional variable interests in these entities.
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 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-Certain immaterial prior period amounts have been reclassified within the Consolidated Financial Statements to conform to current year presentation. Additionally, in December 2009, the Company entered into agreements to sell its entire interests in two oil-fired generation plants, Lal Pir and Pak Gen, in Pakistan and a combined gas-fired generation and water
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
desalination facility, Barka, in Oman. In accordance with the accounting standards on the impairment or disposal of long-lived assets, these operations were considered to be held for sale as of December 31, 2009 and the prior period Consolidated Financial Statements in this Form 10-K have been restated to reflect these businesses as discontinued operations, as discussed in Note 21-Discontinued Operations and Held for Sale Businesses.
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 adopted the fair value measurement accounting guidance for financial assets and liabilities on January 1, 2008 and for nonfinancial assets and liabilities measured on a non-recurring basis on January 1, 2009. This guidance was applied prospectively and the adoption did not materially impact the Company’s financial condition, results of operations, or cash flows. The Company applies the fair value measurement accounting guidance 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 assets (noncurrent)” and derivative liabilities, included in “Accrued and other liabilities (current)” and “Other long-term liabilities”.
The fair value measurement accounting guidance requires that the Company make assumptions market participants would use in pricing an asset or liability based on the best information available. Reporting entities are required to consider factors that were not previously measured when determining the fair value of financial instruments. 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 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. A financial instrument’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. The fair value of most investments in marketable securities is based on quoted market prices.
Level 2-pricing inputs other than quoted market prices included in Level 1 that 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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 some investments in marketable securities qualify as level 2.
Level 3-pricing inputs that are unobservable, or less observable, from objective sources. Unobservable inputs should only be 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 the annual goodwill impairment assessment qualifies as level 3.
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 the financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves and others, as well as restrictions imposed by long-term power purchase agreements (“PPA”).
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.
The Company adopted the new accounting guidance related to investments in debt and equity securities that became effective during the year. The new guidance improved the presentation and disclosure of other-than-temporary impairment on debt and equity securities in the financial statements and changed the accounting requirements related to the recognition of other-than-temporary impairment of debt securities. The new guidance identifies two components of an other-than-temporary impairment: 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. The new guidance was effective for new and existing securities held by an entity as of the beginning of the period adopted and required a cumulative adjustment to the opening balance of retained earnings in the period of adoption with a corresponding adjustment to AOCI.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The adoption of the new guidance did not have a material impact on the Company’s financial condition, results of operations or cash flows. The Company has incorporated the additional disclosure requirements in this Form 10-K.
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 6-Fair Value of Financial Instruments 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.
ALLOWANCE FOR DOUBTFUL ACCOUNTS-The Company maintains an allowance for doubtful accounts for estimated uncollectible accounts receivable. The allowance is based on the Company’s assessment of known delinquent accounts, historical experience and other currently available evidence of the collectibility and the aging of accounts receivable.
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 cost, which 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”) or average cost 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.
PROPERTY, PLANT AND EQUIPMENT-Property, plant and equipment are stated at cost net of accumulated depreciation. The cost of renewals and betterments that extend the useful life of property, plant and equipment are capitalized.
Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs 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 each asset 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 part is considered a component, it is depreciated over its useful life after the part is placed in service. If the 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.
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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 value 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 OTHER INTANGIBLES-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. Assets and liabilities are allocated to a reporting unit if assets will be employed by or a liability relates to the operations of a reporting unit or would be considered in determining its fair value. Two or more components are combined into a single reporting unit if they share the economic similarity criteria prescribed by the accounting guidance. The goodwill impairment evaluation is performed in two steps. In step 1, the carrying value of a reporting unit is compared to its fair value and if the fair value exceeds the carrying value, step 2 is unnecessary. When the carrying value of a reporting unit exceeds its fair value, step 2 is performed to determine the implied fair value of goodwill. To estimate the implied fair value of goodwill, the fair values of individual assets and liabilities of the reporting unit are determined as if it were a business combination. An impairment loss is recognized if the carrying amount of goodwill exceeds its implied fair value.
Most of the Company’s reporting units are not publicly traded and the Company has estimated the fair value of its reporting units using internal valuation models based on discounted cash flow principles. Effective January 1, 2009, the Company adopted the fair value measurement guidance for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. The adoption resulted in the introduction of several modifications to the Company’s internal valuation model to align it with the new accounting guidance. Most notably, the new accounting guidance 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 was estimated using internal budgets and forecasts, adjusted for any market participants’ assumptions and discounted at the rate of return
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
required by a market participant. When estimating the fair value of its reporting units, 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. The adoption of this guidance did not have a material impact on the Company’s financial condition or results of operations.
Intangible Assets:
Finite-lived intangible assets are amortized over their useful lives which range from 2 - 95 years. The Company accounts for emission allowances as intangible assets and charges them to expense when sold or used; granted allowances are valued at zero. The Company’s indefinite-lived intangible assets, which include items such as land use rights, are tested for impairment on an annual basis in accordance with applicable accounting guidance for 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. As discussed in Note 20-Income Taxes, in June 2006, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance related to uncertainty in income taxes, which applied to our financial statements beginning January 1, 2007. This new accounting guidance applies to all tax positions accounted for in accordance with the accounting standards for income taxes and requires the Company’s tax positions to be evaluated under a more-likely-than-not recognition threshold and measurement analysis before they can be recognized for financial statement reporting. The Company adopted this new accounting guidance on January 1, 2007 and recognized a cumulative effect of $53 million as an adjustment to beginning retained earnings.
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 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. The adoption of year-end measurement date requirements at December 31, 2008 resulted in a cumulative adjustment to retained earnings of $1 million.
NONCONTROLLING INTERESTS-Effective January 1, 2009, the Company adopted the new accounting guidance for noncontrolling interests, which changed the accounting for and the reporting of minority interest, now referred to as noncontrolling interests, in the Company’s consolidated financial statements. This resulted in the reclassification of minority interest amounts, previously classified as a separate component of equity, to “Noncontrolling Interests”, a component within permanent equity, in the accompanying 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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
income in the accompanying Consolidated Statements of Operations and Statements of Changes in Equity. The new accounting guidance also requires that any change in ownership of a subsidiary while the controlling financial interest is retained should be accounted for as an equity transaction between the controlling and noncontrolling interests. Gains or losses from such transactions are no longer recognized in net income and the carrying values of the subsidiary’s assets (including goodwill) and liabilities are not adjusted. Previous SEC guidance provided an option in certain circumstances for a parent to recognize a gain or loss on the sale of stock by a subsidiary or account for the sale as an equity transaction. In certain transactions, AES had previously elected the option to recognize a gain or loss. Under the revised guidance, this option is no longer available.
Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero. Previously, losses that otherwise would have been attributed to the noncontrolling interests were allocated to the controlling interest after the associated noncontrolling interests’ basis was reduced to zero. The Company had no material losses that it did not allocate to noncontrolling interests prior to the adoption of the new noncontrolling interests accounting guidance and the adoption did not have a material impact on the Company’s financial position or results of operations.
Although in general, the noncontrolling ownership interest in earnings is calculated based on ownership percentage, certain of our wind businesses use the HLBV method in consolidation. HLBV uses a balance sheet approach, which measures equity in income or loss by calculating the change in the amount of net worth partners are legally able to claim based on a 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 ventures which contain agreements designating different allocations of value among investors, where the allocations change in form or percentage over the life of the venture. In the fourth quarter of 2009, net income attributable to noncontrolling interests and income tax expense increased $44 million and decreased $16 million, respectively. Accordingly, net income and income from continuing operations increased $16 million and net income attributable to The AES Corporation decreased $28 million, or $0.04 per share, for the year ended December 31, 2009, as a result of a charge related to the potential future taxes that could be deemed to be due in the calculation of the hypothetical liquidation value of certain of our wind equity partnerships.
LONG-LIVED ASSETS-In accordance with the accounting standards for the impairment or disposal of long-lived assets, the Company evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under the relevant accounting standards. These events or circumstances may include the relative pricing of wholesale electricity by region, anticipated demand and cost of fuel. If the carrying amount is not recoverable, an impairment charge is recognized for the amount by which the carrying value of the long-lived asset exceeds its fair value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if recovery through approved rates was probable. For non-regulated assets, an impairment charge is recognized as a charge against earnings.
In connection with the periodic evaluation of long-lived assets in accordance with the accounting standards on impairment or disposal of long-lived assets, the fair value of the asset can vary if different estimates and assumptions would have been used in our applied valuation techniques. In cases of impairment described in Note 19-Asset Impairment Expense, we made our best estimate of fair value using valuation methods based on the most current information available at that time. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the 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.
FOREIGN CURRENCY TRANSLATION-A business’ functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is other than the U.S. Dollar translate their assets and liabilities into U.S. Dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. Dollars at the average exchange rates that prevailed during the period. Translation adjustments are included in AOCI. Gains and losses on intercompany foreign currency transactions which are long-term in nature, which the Company does not intend to settle in the foreseeable future, are also 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 the Utilities business 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 equity or liability instruments 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, 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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 gains or losses on 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 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 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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
See Note 6-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, 2009 are not yet effective for and have not been adopted by AES.
ASU No. 2009-17, Consolidations, Improvements to Financial Reporting by Enterprises involved with Variable Interest Entities (“ASU No. 2009-17”) (former FAS No. 167, Amendments to FASB Interpretation No. 46(R))
In June 2009, the Financial Accounting Standards Board (“FASB”) issued an amendment to the accounting and disclosure requirements for the consolidation of VIEs. The amendment requires an entity to qualitatively, rather than quantitatively, assess the determination of the primary beneficiary of a VIE. This determination should be 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: the requirement for an ongoing reconsideration of the primary beneficiary, the criteria 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 the expansion of the disclosures previously required. The impact of ASU No. 2009-17 will require the Company to consolidate the assets, liabilities and operating results of certain VIEs, including certain entities currently accounted for under the equity method of accounting that AES does not currently consolidate; see further discussion below. It may also require the Company to deconsolidate certain VIEs that are currently consolidated. The impact of the adoption may be applied retrospectively with a cumulative-effect adjustment to retained earnings as of the beginning of the first year restated, or through a cumulative-effect adjustment on the date of adoption. The new accounting guidance for VIEs is effective for fiscal years beginning after November 15, 2009, or January 1, 2010 for AES. Early adoption is prohibited.
Based on its review to date, the Company has determined that an entity that had not been previously consolidated will be required to be consolidated upon the adoption of the new standard. Cartagena, the Company’s generation business in Spain, is currently accounted for under the equity method of accounting and is expected to be consolidated upon the adoption of the new VIE accounting guidance. Total assets and revenue for Cartagena as of and for the year ended December 31, 2009 were $929 million and $147 million, respectively. The Company is still in the process of quantifying the expected impact of the cumulative adjustment to be recorded upon adoption of the new VIE guidance. AES is in the process of completing its review of the potential impact from the adoption of this guidance and may identify additional entities to consolidate or deconsolidate upon adoption in the first quarter of 2010.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
2. INVENTORY
As of December 31, 2009, 84% of the inventory was determined using average cost, 15% was determined using the FIFO method and the remaining were valued using the specific identification method. The following table summarizes our inventory balances as of December 31, 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 and Barka of $346 million and $522 million as of December 31, 2009 and 2008, respectively, are excluded from the table above and are included in the noncurrent assets of held for sale and discontinued businesses.
The following table summarizes interest capitalized during development and construction on qualifying assets for the years ended December 31, 2009, 2008 and 2007:
Recoveries of liquidated damages from construction delays and government subsidies are reflected as a reduction in the related projects’ construction costs. Approximately $13 billion of property, plant and equipment, net of accumulated depreciation, was mortgaged, pledged or subject to liens as of December 31, 2009.
Depreciation expense, including the amortization of assets recorded under capital leases, was $1,005 million, $953 million and $880 million for the years ended December 31, 2009, 2008 and 2007, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
Net electric generation and distribution assets and other include unamortized internal use software costs of $182 million and $104 million as of December 31, 2009 and 2008, respectively. Amortization expense associated with software costs was $48 million, $41 million and $20 million for the years ended December 31, 2009, 2008 and 2007.
The following table summarizes regulated and non-regulated generation and distribution facilities property, plant and equipment and accumulated depreciation as of December 31, 2009 and 2008:
The following table summarizes the amounts recognized, which were related to asset retirement obligations, for the years ended December 31, 2009 and 2008:
The Company’s 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 $87 million as of December 31, 2009 and less than $1 million as of December 31, 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
4. 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, 2009 and 2008 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. These securities 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 securities and their placement within the fair value hierarchy levels.
(1) Amortized cost approximated fair value at December 31, 2009 and 2008, with the exception of the common stock discussed below.
(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) During the year ended December 31, 2009, an investment of the Company with a cost basis of $5 million, previously accounted for under the cost method, underwent an initial public offering (“IPO”). Subsequent to the IPO, the Company’s investment in common stock became marketable. Beginning in the third quarter,
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
the common stock was accounted for as available-for-sale and was accordingly adjusted to fair value at each subsequent reporting date. As a result, an unrealized gain of $11 million was recognized in other comprehensive income.
(4) Held-to-maturity securities are not measured at fair value on a recurring basis.
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 quarter 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.
As of December 31, 2009, all available-for-sale debt securities had stated maturities within 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 as of December 31, 2009.
The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for the years ended December 31, 2009, 2008 and 2007. There were no realized losses on the sale of available-for-sale securities or gains included in earnings that relate to trading securities held at the reporting date. Gains and losses on the sale of investments are determined using the specific identification method.
There was no other-than-temporary impairment of marketable securities recognized in the years ended December 31, 2009 and 2008. The Company recognized other-than-temporary impairment charges on a marketable security of $52 million for the year ended December 31, 2007 related to the Company’s investment in AgCert International (“AgCert”). The Company acquired a 9.9% ownership interest in AgCert for $52 million in May 2006 and, in accordance with the accounting standards for investments, classified these securities as “available-for-sale”. At that time, our investment in the stock, which was traded on the London Stock Exchange, was classified as a long-term available-for-sale investment. There was a material decline in the market value of these securities, based on a continual decline in the traded market price during the year ended December 31, 2007, and the Company recognized an other-than-temporary impairment charge of $52 million. The Company began consolidating AgCert in January 2008 when it became the primary beneficiary.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following table sets forth the Company’s investments in marketable debt securities classified as held-to-maturity as of December 31, 2009 and 2008:
(1) At December 31, 2009 and 2008, $2 million and $14 million, respectively, of investments classified as held-to-maturity were restricted or pledged as collateral for certain debt or other arrangements.
The amortized cost approximated fair value of the held-to-maturity investments at December 31, 2009 and 2008. As of December 31, 2009, all held-to-maturity debt securities, including restricted investments, had stated maturities within one year.
5. 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 fuels 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 will apply hedge accounting for all contracts so long as they are eligible under the accounting standards for derivatives and hedging. Derivative transactions are not entered into for trading purposes.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 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 that index as of December 31, 2009 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, 2009 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 in USD.
(2) Excludes variable-rate debt tied to other indices where the Company has no interest rate derivatives.
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, 2009 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, 2009:
(1) Represent the remaining tenor of our cross currency swaps weighted by the corresponding notional in USD.
(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, 2009, 2008, AND 2007
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 forwards, swaps and options 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, 2009 regardless of whether the derivative instruments are in qualifying hedging relationships:
(1) Represent 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 in USD.
(1) Represents the remaining tenor of our foreign currency forwards weighted by the corresponding notional in USD.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 currencies other than their own functional currencies 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, 2009:
(1) Represents the remaining tenor of our foreign currency embedded derivatives weighted by the corresponding notional in USD.
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 (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, fuels 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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
We also enter into short-term contracts for the supply of 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. The portion of our sales and fuel purchases that are not subject to such agreements will be exposed to commodity price risk. Eastern Energy in New York and Deepwater in Texas, two of our North America generation businesses, sell electricity into the power pools managed by the New York Independent System Operator (“NYISO”) and the Electric Reliability Council of Texas (“ERCOT”), respectively. In addition, Eastern Energy has hedged a portion of its power exposure for 2010 by entering into hedges of natural gas prices, as movements in natural gas prices affect power 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 derivative instruments at Eastern Energy and Deepwater and the percentage of forecasted sales of electricity hedged as of December 31, 2009 for 2010 and 2011:
In addition, certain of our subsidiaries have entered into PPAs and fuel supply agreements that have been assessed as derivatives or contain embedded features that have been assessed as embedded derivatives. These contracts range in maturity through 2024. The following table sets forth by type of commodity, the Company’s outstanding notional for the remaining term of its commodity derivative (excluding Eastern Energy and Deepwater) and embedded derivative instruments as of December 31, 2009:
(1) Represents the remaining tenor of our commodity and embedded derivatives weighted by the corresponding volume.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
Accounting and Reporting
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, 2009 and 2008, we held $8 million and $0 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. Also, at December 31, 2009 and 2008, we had no cash collateral posted with (held by) counterparties to our derivative positions.
As of December 31, 2009, approximately $(124), $0, $(2) and $19 million of the pre-tax accumulated other comprehensive (loss) income related to interest rate derivative instruments, cross currency derivative instruments, foreign currency derivative instruments and commodity derivative instruments, respectively, is expected to be recognized as a (decrease) increase to income from continuing operations before income taxes over the next twelve months. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for interest rate hedges and cross currency swaps, as depreciation is recognized for interest rate hedges during construction, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure, and as electric sales and fuel purchases are recognized for hedges of forecasted electric 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. Additionally, $1 million of pre-tax accumulated other comprehensive (loss) income is expected to be recognized as an increase to income from continuing operations before income taxes over the next twelve months. This amount relates to a power purchase agreement that was dedesignated as a cash flow hedge because the normal purchase normal sale scope exception from derivative accounting was elected as of December 31, 2008.
For the years ended December 31, 2009, 2008 and 2007, pre-tax gains (losses) of $7, $(1) and $(2) 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, 2009, 2008, AND 2007
The following table sets forth the Company’s investments in derivative instruments as of December 31, 2009 by type of derivative and by level within the fair value hierarchy. 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 assessments 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, 2009, 2008, AND 2007
The following table sets forth, by type of derivative, the financial statement location and fair value of derivative instruments as of December 31, 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following tables set forth, by type of derivative, the financial statement location and amount of 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 year ended December 31, 2009:
(1) Excludes $22 million of losses for the year ended December 31, 2009 reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting.
(2) De minimis amount of losses reclassified from AOCL.
Amounts recognized in AOCL due to derivative instruments that currently are, or previously were (but no longer are), in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, after income taxes, during the years ended December 31, 2008 and 2007, respectively, are as follows:
The following table sets forth, by type of derivative, the financial statement location and amount of 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 year ended December 31, 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The Company recognized after-tax (losses) gains of $(45) million and $3 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 years ended December 31, 2008 and 2007, respectively.
The following table sets forth by type of derivative, the financial statement location and amount of gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the year ended December 31, 2009:
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. For the year ended December 31, 2009, the change in the fair value of these derivatives resulted in a decrease in regulatory assets of $2 million and a decrease in regulatory liabilities of $5 million on the accompanying consolidated balance sheet.
The Company recognized after-tax gains (losses) of $10 million and $(21) 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 years ended December 31, 2008 and 2007, respectively.
Credit Risk-Related Contingent Features
Certain of our 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 the 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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 they were in a net liability position. 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.
In December 2007, Gener entered into cross currency swap agreements with a counterparty to swap the 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 $12 million at December 31, 2009. As of December 31, 2009, Gener had posted $25 million in the form of a letter of credit to support these swaps.
6. FAIR VALUE
The fair value of current financial assets and liabilities, debt service reserves and other deposits is estimated to be equal to 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 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.
In general, the Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis include goodwill; intangible assets, such as sales concessions, land rights and emissions allowances; and long-lived tangible assets including property, plant and equipment. The Company recognized material goodwill impairment during the year ended December 31, 2009 as a result of the annual goodwill impairment evaluation as of October 1, but this impairment was not a result of the adoption of the new fair value measurement provisions. This is further described in Note 8-Goodwill and Other Intangible Assets. Although the adoption of the new fair value measurement and disclosure accounting guidance did not materially impact our financial condition, results of operations or cash flows, additional disclosures about fair value measurements are included in this Form 10-K.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following table summarizes the carrying and fair value of certain of the Company’s financial assets and liabilities as of December 31, 2009 and 2008:
(1) See Note 4-Investments in Marketable Securities for additional information regarding the classification of marketable securities in the Fair Value Hierarchy.
(2) See Note 5-Derivative Instruments and Hedging Activities for additional information regarding the fair value of derivatives.
(3) See Note 10-Debt for additional information regarding the fair value of the Company’s recourse and non-recourse debt.
Valuation Techniques:
The fair value measurement accounting guidance describes three main approaches to measuring the fair value of assets and liabilities: (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 uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on the value indicated by current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company does not currently determine the fair value of any of our financial assets and liabilities using the cost approach. Financial assets and liabilities that are measured at fair value on a recurring basis at AES fall into two broad categories: investments and derivatives.
Our investments are generally measured at fair value using the market approach and our derivatives are valued using the income approach.
Investments
The Company’s investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are adjusted to 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. The implementation of the fair value measurement guidance did not result in a material change in the fair value of these investments due to the fact that these investments are primarily issued by highly-rated institutions and governmental agencies and therefore, the consideration of counterparty credit risk did not have a
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
material impact on the determination of fair value. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to LIBOR), Selic (overnight borrowing rate) or IGPM (inflation) rates in Brazil and are adjusted based on the banks’ assessment of the specific businesses. Fair value is determined based on comparisons to market data obtained for similar assets and are considered Level 2 inputs. The Company holds some auction rate securities through IPL. The fair value of these securities was $2 million as of December 31, 2009. Based on the current credit environment, these were evaluated for potential impairment and were determined to not be impaired at this time. For more detail regarding the fair value of investments see Note 4-Investments in Marketable Securities.
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 fluctuations in commodity prices, and embedded derivatives associated with commodity contracts. The Company’s subsidiaries are counterparties to various interest rate swaps, interest rate options, foreign currency swaps and commodity and embedded derivatives in certain agreements, generally PPAs. The fair value of our derivative portfolio was determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The primary pricing inputs used in determining the fair value of our interest rate swaps and our foreign currency exchange swaps are forward LIBOR curves and forward foreign exchange curves with the same duration as the instrument as reported in published information provided by pricing services. For each derivative, the projected forward curves are used to determine the stream of cash flows over the remaining term of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value. 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 included in Level 2.
In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve which result in the use of unobservable inputs. In certain instances the financial or physical instrument is traded in an inactive market requiring us to use unobservable inputs. Additionally, in certain instances the nonperformance risk or credit risk adjustment for contracts is based on unobservable inputs. Where the use of such unobservable inputs are significant, these contracts are classified as Level 3.
Fair Value Considerations:
In determining the fair value of our financial instruments, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty to the contract and risk of nonperformance of itself. The conditions and criteria used to assess these factors are:
Sources of market assumptions:
The Company derives most of its financial instrument 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 a financial instrument’s fair value.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
Market liquidity:
Market liquidity is evaluated by the Company based on criteria as to 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 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 upon 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 risk 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 forwards, swaps, and options 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 is 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, 2009, 2008, AND 2007
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, 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 following table presents a reconciliation of all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2009:
(1) Derivative assets and (liabilities) are presented on a net basis.
(2) See Note 5-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) Of the assets transferred out of Level 3 during the year ended December 31, 2009, $187 million represents a PPA that was dedesignated as a cash flow hedge because it qualified for the normal purchase normal sale scope exception as of December 31, 2008. As such, the agreement was measured at fair value using significant unobservable inputs at December 31, 2008, but is subsequently being
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
amortized and is no longer adjusted for subsequent changes in fair value. The remainder of assets transferred out of Level 3 were primarily a result of a decrease in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments.
(4) Liabilities transferred out of Level 3 were primarily a result of a decrease in the significance of unobservable inputs to calculate the credit valuation adjustments of these derivative instruments.
(5) 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 available to measure the fair value.
Nonfinancial Assets and Liabilities on a Nonrecurring Basis
For the purpose of impairment evaluation, the Company measured goodwill and intangibles assets, long-lived assets, and discontinued operations and assets held for sale at fair value under the new fair value measurement accounting guidance. As the majority of significant assumptions used for these valuations were not observable, management believes that all of these valuation are level 3 measurements in the fair value hierarchy.
As noted in Note 19-Asset Impairment Expense, long-lived assets held and used with a carrying amount of $26 million were written down to their fair value of $2 million, resulting in an asset impairment charge of $24 million, which was included in net income for the year.
As noted in Note 8-Goodwill and Other Intangible Assets, goodwill with an aggregate carrying amount of $122 million was written down to its implied fair value of $0 million, resulting in goodwill impairment of $122 million, which was included in net income for the year.
As noted in Note 21-Discontinued Operations and Held for Sale Businesses, long-lived assets held for sale with a carrying amount of $275 million were written down to their fair value of $130 million, less cost to sell of $5 million (or $125 million), resulting in a loss of $150 million, which was included in net income for the year.
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, 2009 and 2008.
(1) Represent VIEs in which we hold a significant variable interest.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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, 2009 and 2008 other long-term liabilities included $54 million and $49 million, respectively, related to this debt agreement.
Cartagena Energia-The Company owns 71% of Cartagena Energia (“Cartagena”) a 1,219 MW power plant in Cartagena, Spain completed in November 2007. The Company’s initial investment in Cartagena was approximately $29 million. Cartagena was determined to be a VIE and the Company is not the primary beneficiary due to the fact that the sole customer of the plant absorbs the majority of the commodity price risk. In December 2008, the Company’s basis in its investment in Cartagena was reduced to zero and the equity method of accounting was suspended. In June 2009, Cartagena received a cash settlement of $53 million for liquidated damages including legal costs incurred related to the construction delay from December 2005 to November 2006 of the generation plant. Cartagena used the settlement proceeds to repay a portion of the participative loans outstanding to its investors including AES. In June 2009, the Company received its proportionate share of the settlement, $35 million, which was recognized as “net equity in earnings of affiliates” because the distribution was in excess of the Company’s current investment balance of zero and AES does not have an obligation or intent to fund future cash flow requirements of Cartagena. As a result of the new accounting guidance issued in the fourth quarter of 2009 regarding VIEs, the Company believes at this time that upon the January 1, 2010 effective date, Cartagena will no longer be accounted for under the equity method of accounting, and will at that time become a consolidated subsidiary. See further discussion of the new accounting guidance in Item 7.-Management’s Discussion and Analysis of Financial Condition,-Accounting Pronouncements Issued, but not yet Effective and Note 1-General and Summary of Significant Accounting Policies.
CEMIG-The Company, through it’s Brazilian subsidiary, Southern Electric Brasil Participações Ltda. (“SEB”), a VIE, has a 14.8% voting interest in Companhia Energética de Minas Gerais (“CEMIG”), an integrated utility in Minas Gerais, Brazil. Although our interest in CEMIG is below the 20% threshold for significant influence, AES has 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 the CEMIG investment. The total amount of these charges, net of tax, was $587 million. As a result, the Company’s investment in CEMIG is a $484 million net liability at December 31, 2009 included in the Other Long-Term Liabilities line item on the Consolidated Balance Sheet. The Company has discontinued the application of the equity method in accordance with its accounting policy regarding equity method investments. In November 2009, SEB entered into a share purchase and sale agreement with Andrade Gutierrez Concessões S.A. and an affiliated company (jointly referred to as, “AG”) for the sale of SEB’s shares in CEMIG. In consideration for SEB’s shares in CEMIG, AG will pay to SEB a total purchase price equal to the sum of (i) $25 million plus (ii) the assumption by AG of SEB’s debt (the “BNDES Loan”) with Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”). The sale is subject to the resolution of all outstanding debts and claims relating to the BNDES Loan and is contingent upon SEB obtaining a full release from any claims of BNDES, the restructuring of the BNDES Loan and the ratification of the settlement by the judicial system of the restructuring of the BNDES Loan assumed by AG and the sale of SEB’s shares in CEMIG to AG.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 will develop 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 will each provide up to $500 million of capital over the next five years. As of December 31, 2009, AES had invested approximately $247 million in the joint venture.
Guohua AES (Huanghua) Wind Power Co., Ltd-In May 2007, the Company acquired a 49% interest in Guohua AES (Huanghua) Wind Power Co., Ltd. (“AES Huanghua”), a joint venture that is primarily engaged to develop, construct, own and operate wind projects in China. The project went live in the third quarter of 2009. Also, in the second and third quarter of 2008, the Company acquired a 49% interest in three separate wind projects in China-Guohua AES (“Hulunbeier”) Wind Power Co., Ltd.; Guohua AES (“Chenba’erhu”) Wind Power Co., Ltd.; and Guohua AES (“Xinba’erhu”) Wind Power Co., Ltd. The Company invested approximately $16 million in the aforementioned projects in 2009, bringing the cumulative investment to $50 million.
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, 2009, retained earnings included $156 million related to the undistributed earnings of the Company’s 50%-or-less owned affiliates. Distributions received from these affiliates were $35 million, $50 million and $59 million for the years ended December 31, 2009, 2008 and 2007, 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, 2009, 2008, AND 2007
8. GOODWILL AND OTHER INTANGIBLE ASSETS
The accounting guidance for goodwill requires that goodwill be evaluated for impairment at the reporting unit level. A reporting unit is an operating segment, as defined by the segment reporting accounting guidance, or a component or combination of components within an operating segment with similar economic characteristics that are one level below an operating segment. Generally, each AES business constitutes a reporting unit. In the event that more than one reporting unit is acquired in a single acquisition, goodwill is assigned to the reporting units that benefit from the goodwill on a relative fair value basis.
The following table summarizes the changes in the carrying amount of goodwill, by segment as of December 31, 2009, 2008 and 2007. There was no goodwill associated with our North America-Utilities segment during the years ended December 31, 2009, 2008 and 2007.
(1) Represents goodwill acquired for the period of $65 million related to the acquisition of Masinloc.
The Company conducts its annual goodwill impairment analysis as of October 1st each year. The fair value of the reporting units was determined using the income approach based on a discounted cash flow valuation model as current quoted market prices were not always available. In 2009, Kilroot, our subsidiary in the United Kingdom, reported in the Europe Generation segment, incurred 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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 years ended December 31, 2008 and 2007, the Company had no goodwill impairment.
The following tables summarize the balances comprising other intangibles in the accompanying Consolidated Balance Sheets for the years ended December 31, 2009 and 2008:
(1) Intangible assets subject to amortization.
(2) Includes $50 million land use rights that are not subject to amortization at December 31, 2009 and 2008. The remaining balance is subject to amortization.
(3) Acquired or purchased emission allowances are expensed when utilized or sold and included in net income for the year.
(4) Represents various intangible assets subject to amortization relating to an asset acquisition in the state of New York in 1999, which were not separately identified.
(5) Consists of various intangible assets including PPAs subject to amortization, none of which is individually significant.
In 2009, the Company reclassified $42 million from other assets into the intangible asset at one subsidiary in Latin America. In 2009, the Company acquired intangible assets of $22 million. The acquired intangible assets included $1 million which were subject to amortization with an average amortization period of 35 years and $21 million of intangible assets not subject to amortization. In 2008, the Company acquired intangible assets of $85 million, the largest of which was the acquisition of landfill gas rights in El Salvador. The acquired intangible assets included $59 million which were subject to amortization with an average amortization period of 20 years and $26 million of intangible assets not subject to amortization.
The following table summarizes the estimated amortization expense, broken down by intangible asset category, for 2010 through 2014:
Intangible asset amortization expense was $24 million, $19 million and $23 million for the years ended December 31, 2009, 2008 and 2007, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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, 2009, 2008, AND 2007
(1) Past expenditures on which the Company does not earn a rate of return.
(2) 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.
(3) 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.
(4) Includes assets with and without a rate of return. All current regulatory assets earned a rate of return as of December 31, 2009. Other current regulatory assets that did not earn a rate of return were $9 million as of December 31, 2008. Other noncurrent regulatory assets that did not earn a rate of return were $90 million and $83 million, as of December 31, 2009 and 2008, respectively. Those without a rate of return that are recoverable based on specific rate orders primarily consist of the following:
•
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.
Other Current and Noncurrent Regulatory Liabilities consist of:
•
Deferred fuel costs: expected to be refunded to customers through 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 permitted to recover underestimated fuel and purchased power costs in future rates.
•
Penalties and fees from regulators at our Brazil subsidiaries and financial transmission rights used to hedge exposure in the Midwest ISO market that are credited per specific rate orders.
•
Free Energy is the cost incurred by electricity generators due to variance in energy prices during rationing periods. Our Brazilian subsidiaries are authorized to reclaim or refund this cost associated with monthly energy price variances between the whole sale 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.
(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. The decrease in the regulatory asset of $64 million at December 31, 2009 is primarily a result of a higher than expected return on assets in 2009.
(6) Probable of reversal through future rates, based upon established regulatory practices, which permit the reversal 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 recovered as part of the IRT.
(8) Non-legal asset retirement obligations for removal costs which do not have an associated legal retirement obligation as defined by the accounting standards on asset retirement obligations.
(9) 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 maturity term is established by ANEEL whose settlement shall occur when the concession ends.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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, 2009 and 2008:
The following table summarizes regulatory liabilities by region as of December 31, 2009 and 2008:
10. DEBT
The Company has two types of debt reported on its balance sheet: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for the construction and acquisition of our electric power plants, wind projects and distribution companies at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisition and functions as equity investments or loans to the affiliates. This debt is with recourse to the Parent Company and is structurally subordinated to the affiliates’ non-recourse debt.
Recourse and non-recourse debt is carried at amortized cost. The following table summarizes the carrying amount and estimated fair values of the Company’s recourse and non-recourse debt as of December 31, 2009 and 2008:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The fair value of non-recourse debt, excluding capital leases, is estimated differently based upon the type of loan. The fair value of fixed rate loans is estimated using quoted market prices 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 AES Corporation. For subsidiaries located in countries with credit ratings lower than The AES Corporation, we used the appropriate country specific yield curve. For variable rate loans, carrying value typically approximates fair value. At December 31, 2008, credit spreads were significantly above historic levels. For the U.S. Dollar, Euro and British Pound markets where the Company believed the expanded credit spread was material, fair value was estimated using a discounted cash flow analysis. The increase in credit spreads was calculated as the difference between composite fair value curves, published by pricing services for the relevant issuer credit rating, and London Inter-Bank Offered Rate (“LIBOR”). For all other currencies, the Company continued to assume the carrying value was equal to fair value. During the second half of 2009, credit spreads returned to a typical range for all currencies and the Company concluded that carrying value approximated fair value for all of our variable rate debt as of December 31, 2009. The estimated fair value was determined using available market information as of December 31, 2009 and 2008. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2009.
NON-RECOURSE DEBT
The following table summarizes the carrying amount and terms of non-recourse debt of the Company as of December 31, 2009 and 2008:
(1) Weighted average interest rate at December 31, 2009.
(2) The Company has interest rate swaps and interest rate option agreements in an aggregate notional principal amount of approximately $4.2 billion on non-recourse debt outstanding at December 31, 2009. 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 1.93% 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 2010 through 2027.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
(3) Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
(4) Non-recourse debt of $329 million and $401 million as of December 31, 2009 and 2008, respectively, related to Lal Pir, Pak Gen and Barka 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, 2009 is scheduled to reach maturity as set forth in the table below:
As of December 31, 2009, AES subsidiaries with facilities under construction had a total of approximately $1.1 billion of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $1.6 billion 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 5.25% at December 31, 2009. In addition to the committed credit lines described above, an operating subsidiary of the Company in Brazil had credit commitments from banks to lend up to $574 million at December 31, 2009. This credit commitment is subject to certain conditions and can only be used if the Company decides to exercise its preemptive rights to acquire the noncontrolling interest shares of Brasiliana held by a third-party in response to a decision by the partner to sell and exercise its preemptive rights to include our ownership portion in the sale.
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, 2009 and 2008, approximately $653 million and $689 million, respectively, of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within restricted cash and debt service reserves and other deposits in the accompanying Consolidated Balance Sheets.
Various lender and governmental provisions restrict the ability of the Company’s subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $5.8 billion at December 31, 2009.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of December 31, 2009 and is included in the current portion of non-recourse debt unless otherwise indicated:
(1) Ebute, our subsidiary in Nigeria, has received a waiver of default which gives Ebute until December 31, 2010 to cure the breached covenants; however, as this waiver does not extend beyond the Company’s current reporting cycle and the probability of curing the default cannot be determined, the debt was classified as current.
None of the subsidiaries that are currently in default is a material subsidiary under AES’s corporate debt agreements whose acceleration of debt or bankruptcy would trigger an event of default or permit acceleration under such indebtedness. At December 31, 2009, none of our subsidiaries that are currently in default met the definition of material subsidiary under our recourse senior secured credit facility or other debt agreements. All of the subsidiary guarantors under our recourse secured credit facilities are defined as material subsidiaries under those agreements. The bankruptcy or acceleration of material amounts of debt at these entities would cause a cross default under the recourse secured credit facilities. The subsidiary guarantors include the subsidiaries which own AES Eastern Energy, AES Warrior Run, AES Shady Point and AES Hawaii. 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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
RECOURSE DEBT
The following table summarizes the carrying amount and terms of recourse debt of the Company as of December 31, 2009 and 2008:
Recourse debt as of December 31, 2009 is scheduled to reach maturity as set forth in the table below:
On March 26, 2009, the Parent Company and certain subsidiary guarantors amended the Parent Company’s existing senior secured credit facility pursuant to the terms of Amendment No. 1 (“Amendment No. 1”) to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008 (the “senior secured credit facility”). The senior secured credit facility previously included a $200 million term loan facility maturing on August 10, 2011 and a $750 million revolving credit facility maturing on June 23, 2010 (the “revolving credit facility”).
The principal modification set forth in Amendment No. 1 was a one-year extension of $570 million of revolving credit facility commitments from an original maturity date of June 23, 2010 to July 5, 2011. In addition, certain lenders determined that they would increase their commitment under the revolving credit facility by $35 million from March 26, 2009 through July 5, 2011. Accordingly, Amendment No. 1 increased the size of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
the revolving credit facility from $750 million to $785 million through June 23, 2010. From June 23, 2010 through July 5, 2011, the revolving credit facility size will be $605 million. No modifications were made to the amount or maturity date of the $200 million term loan facility.
The extended commitments from this amendment were subject to new pricing that included an upfront fee of 1.25% for participating in the extensions and an increase in undrawn commitment fees from 50 to 100 basis points. The annual interest rate on the drawn loans was also increased by 200 basis points to LIBOR plus 3.50%. Pricing and all other material terms remain unchanged for the revolving credit facility commitments which have not been extended.
On April 2, 2009 the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes due 2016 in a private placement. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce the size of its $600 million senior unsecured credit facility. The majority of the letters of credit issued under the facility supported a project under construction in Bulgaria. On October 7, 2009, the Parent Company voluntarily reduced all of the remaining commitments available under the senior unsecured credit facility and terminated the facility agreement. As a result of the termination, the Company recognized a foreign currency transaction gain of $20 million related to the sale of Euros purchased as collateral at the inception of the facility. The outstanding letters of credit under the senior unsecured credit facility were transferred to the senior secured credit facility.
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 Shady Point, Hawaii, Warrior Run and Eastern Energy businesses. The Company’s obligations under the senior secured credit facility and Second Priority Senior Secured Notes 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
(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. 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. In the case of sales of assets of or equity interests in IPALCO Enterprises (“IPALCO”) or any of its subsidiaries, any net cash proceeds of the asset sale remaining after application to the Term Loan facility must be used to reduce commitments under the Revolver, unless the supermajority of banks otherwise agree or unless the facilities are rated at least Ba1 from Moody’s and AES’ corporate credit rating from S&P is at least BB-.
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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 8.5× at December 31, 2009.
The terms of the Company’s Senior Unsecured Notes, senior secured credit facility, and Second Priority Secured Notes 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 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 Junior Subordinated 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.
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. AES has not exercised the option to defer any dividends at this time. 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. All dividends due under the Trust have been paid.
AES Trust III is a VIE under the relevant consolidation accounting guidance. AES’s obligations under the Junior Subordinated Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by AES of the TECON Trusts’ obligations under the trust securities issued by the respective trust. Accordingly, AES consolidates the results of AES Trust III. As of December 31, 2009 and 2008, the sole assets of AES Trust III are the Junior Subordinated Debentures.
11. COMMITMENTS
OPERATING LEASES-As of December 31, 2009, 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, 2009, 2008 and 2007 was $63 million, $74 million and $64 million, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The table below sets forth the future minimum lease commitments under these operating leases as of December 31, 2009 for 2010 through 2014 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, 2009 and 2008 was $106 million and $95 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, 2009 for 2010 through 2014 and thereafter:
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, $34 million and $42 million for the years ended December 31, 2009, 2008 and 2007, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following table summarizes the future minimum lease commitments under the sale/leaseback arrangement as of December 31, 2009 for 2010 through 2014 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 2010 through 2042. Purchases in the years ended December 31, 2009, 2008 and 2007 were approximately $2.1 billion, $1.5 billion and $2.2 billion, respectively.
The table below sets forth the future commitments under these electricity purchase contracts at December 31, 2009 for 2010 through 2014 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. Purchases in the years ended December 31, 2009, 2008 and 2007 were $1.4 billion, $1.3 billion and $1.3 billion, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The table below sets forth the future commitments under these fuel contracts as of December 31, 2009 for 2010 through 2014 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, 2009, 2008 and 2007 were $2.8 billion, $1.9 billion and $840 million, respectively.
The table below sets forth the future commitments under these other purchase contracts as of December 31, 2009 for 2010 through 2014 and thereafter:
12. CONTINGENCIES
ENVIRONMENTAL
The Company reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of December 31, 2009, the Company has recognized liabilities of $28 million for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information and analysis, the Company believes that it is reasonably possible that costs associated with such liabilities or as yet unknown liabilities may exceed current reserves in amounts that could be material but cannot be estimated as of December 31, 2009.
THE AES CORPORATION
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The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including 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 by-products), and certain air emissions, such as SO2, NOx, particulate matter and mercury. Such risks and uncertainties include risks and uncertainties related to increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations.
To date, the primary regulation of GHG emissions affecting the Company’s U.S. plants 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 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, as noted in Item 1.-Business-Regulatory Matters-Environmental and Land Use Regulations of this Form 10-K.
The primary international agreement concerning GHG emissions is the Kyoto Protocol which became effective on February 16, 2005 and requires the industrialized countries that have ratified it to significantly reduce their GHG emissions. The vast majority of the developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements. Many of the countries in which the Company’s subsidiaries operate have no reduction obligations under the Kyoto Protocol. In addition, of the 29 countries in which Company’s subsidiaries operate in, all but one-the United States (including Puerto Rico)-have ratified the Kyoto Protocol.
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”). The European Union has announced that it intends to keep the European Union Emissions Trading System (“EU ETS”) in place after the potential expiration of the Kyoto Protocol in 2012. The Company’s subsidiaries operate seven 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. 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 Energía Cartagena S.R.L. 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 will prevail, or that the cost and administrative burden associated with any such dispute will not be significant.
In 2009, a key development in the area of GHG legislation was the passage of H.R. 2454, The American Clean Energy and Security Act of 2009 (“ACESA”) by the U.S. House of Representatives on June 26, 2009. The full U.S. Senate may consider similar legislation in 2010. ACESA contemplates a nationwide cap and trade program to reduce U.S. emission of CO2 and other greenhouse gases starting in 2012. A summary of key features of ACESA is set forth below:
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A planned target to reduce by 2020 GHG emissions by 17% from 2005 levels and to reduce GHG emissions by 83% from 2005 levels by 2050;
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A requirement that certain GHG emitting companies, including most power generators, surrender on an annual basis one ton of CO2 equivalent allowances or GHG offset credits for each ton of annual CO 2 equivalent emissions. Such companies will be required to meet allowance surrender requirements via the allocations of free allowances if available from the U.S. Environmental Protection Agency (“EPA”) or purchases in the open market at auctions if free allowances are not allocated, or otherwise;
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A mechanism under which the EPA would initially issue a capped and steadily declining number of tradable free emissions allowances to certain sections of affected industries, including certain generators and utilities in the electricity sector, with such free distribution of allowances to the electricity sector phasing out over a five year period from 2026 through 2030;
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A provision permitting up to two billion tons of GHG offset credits in the aggregate, if available, to be purchased annually by all emitters to satisfy the requirements above;
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A provision precluding the EPA from regulating GHG emissions under the existing provisions of the Clean Air Act (“CAA”);
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A temporary prohibition on the implementation of similar State or regional GHG cap and trade programs, with a six year moratorium (2012 to 2017) on the implementation or enforcement of similar GHG emission caps; and
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The establishment of a combined energy efficiency and renewable electricity standard (“RES”) that would require retail electric utilities to receive 6% of their power from renewable sources by 2012, with such requirement increasing to 20% by 2020. In certain circumstances, a portion of this requirement for renewable energy could be satisfied through measures intended to increase energy efficiency.
The Senate introduced similar legislation on September 30, 2009 with draft bill S. 1733, the Clean Energy Jobs and American Power Act (“CEJAPA”). CEJAPA contemplates a planned target to reduce by 2020 GHG emissions by 20% from 2005 levels and by 83% from 2005 levels by 2050. CEJAPA has been voted out of the Environment and Public Works Committee, but it has not been set for debate on the Senate floor. It is uncertain whether CEJAPA, in a modified form or its current form, will be voted upon by the full Senate or if the Senate will pursue less comprehensive legislation concerning GHG emissions.
At this time, if ACESA or CEJAPA were to be enacted into law, or some reconciled version of ACESA or CEJAPA were to be enacted, the impact on the Company’s consolidated results of operations cannot be accurately predicted because of a number of uncertainties with respect to the specific terms and implementation of any such potential legislation, including, among other provisions:
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The number of free allowances that will be allocated to subsidiaries of the Company;
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The cost to purchase allowances in an auction or on the open market, and the cost of purchasing GHG offset credits;
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The extent to which our utility business (IPL) will be able to recover compliance costs from its customers;
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The benefits to our renewables businesses from the RES provision, if any;
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The benefits to our GHG Emissions Reduction Projects from the potentially increased demand for GHG offset credits arising from GHG legislation, if any;
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The benefits from the temporary moratorium on state or regional GHG cap and trade programs, if any; and
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Whether such legislation would preempt EPA from regulating GHG emissions from electric generating units.
The EPA has proposed to regulate GHG emissions from motor vehicles in 2010 in accordance with the decision by the Supreme Court concluding that GHG emissions could be considered a “pollutant” under the CAA, and subject to regulation under the CAA. Pursuant to that decision, the EPA has a duty to determine whether CO2 emissions contribute to climate change or to provide some reasonable explanation why it will not exercise its authority. In order for the EPA to regulate CO2 and other GHG emissions under Section 202 of the CAA, the EPA must determine that such emissions “endanger public health and welfare” under the CAA. On April 17, 2009, the EPA released proposed findings for comment which included a proposed finding that atmospheric concentrations of six greenhouse gases, including CO2, “endanger public health and welfare within the meaning of Section 202(a) of the CAA.” On December 7, 2009, after review of the public comments to the proposed finding, the EPA issued the endangerment finding.
Also, in response to the Supreme Court’s decision, on July 11, 2008, the EPA issued an Advanced Notice of Proposed Rulemaking to solicit public input on whether CO2 emissions should be regulated from both mobile and stationary sources under Section 202 of the CAA. On September 28, 2009, the EPA proposed a rule to regulate GHG emissions from automobiles, a mobile source of emissions. If such rule is ultimately enacted with respect to a mobile source, one effect would be to subject stationary sources of GHG emissions (including power plants) to regulation under various sections of the CAA. The most important impact on stationary sources would be a requirement that all new sources of GHG emissions of over 250 tons per year, and existing sources planning physical changes that would increase their GHG emissions, obtain “new source review” permits from the EPA prior to construction. Such sources would be required to apply “best available control technology” to limit the emission of GHGs. On September 30, 2009, the EPA proposed a rule that would limit such regulation of stationary sources to those stationary sources emitting the CO2 equivalent of over 25,000 tons per year of GHGs. The Company’s coal and gas-fired U.S. power plants emit over 25,000 tons per year of GHGs and would fall within the scope of this proposed rule if they were to undertake physical changes that would increase their GHG emissions. In September of 2009 the EPA also finalized a rule mandating the widespread reporting and tracking of GHG emissions. Although this tracking and reporting rule does not mandate reductions in GHG emissions, data generated from its implementation may facilitate the further development of federal GHG policy, which may include mandatory GHG emissions limits.
Our subsidiaries conduct business in a number of countries that have ratified the Kyoto Protocol, an international agreement concerning GHG emissions. The Kyoto Protocol is currently expected to expire at the end of 2012. In December 2009, the annual United Nations conference of the parties to the Kyoto Protocol (called COP 15) was held in Copenhagen, Denmark to focus on establishing an international agreement or framework to succeed the Kyoto Protocol when it expires at the end of 2012. COP 15 did not result in any legally binding successor agreement to the Kyoto Protocol, but countries did agree to continue to work towards a successor international agreement on GHG reductions by the next annual conference. Countries also agreed to submit non-binding emission targets and climate change plans by January 31, 2010, although many countries have not yet submitted such targets or plans. The United States did submit such a non-binding target of reducing GHG emissions by 17% from 2005 levels by 2020. At present, the Company cannot predict whether compliance with the Kyoto Protocol or any successor agreements will have a material adverse effect on the Company’s consolidated results of operations, financial condition, and cash flows in future periods.
THE AES CORPORATION
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There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law, whether the EPA will regulate GHG emissions, and whether a new international agreement to succeed the Kyoto Protocol will be reached, and there is additional uncertainty regarding the final provisions and implementation of any potential U.S. federal GHG legislation, any EPA rules regulating GHG emissions and any international agreement to succeed the Kyoto Protocol. In light of these uncertainties, the Company cannot accurately predict the impact on its consolidated results of operations or financial condition from potential U.S. federal GHG legislation, EPA regulation of GHG emissions or any new international agreement on such emissions, or make a reasonable estimate of the potential costs to the Company associated with any such legislation, regulation or international agreement; however, the impact from any such legislation, regulation or international agreement could have a material adverse effect on certain of our U.S. or international subsidiaries and on the Company and its consolidated results of operations.
In additional to the risks and uncertainties related to potential GHG regulations or legislation, the Company faces risk and uncertainties related to regulations or legislation concerning other types of air emissions, such as SO2, NOx, particulate matter (“PM”) and mercury. In the U.S., the Clean Air Act (“CAA”) and various state laws and regulations regulate emissions of air pollutants, including SO2, NOx, PM and mercury. The applicable rules and the steps taken by the Company to comply with the rules are discussed in further detail below.
The U.S. EPA finalized two rules that are relevant to emissions of SO2, NO x, PM and mercury from our U.S. coal-fired power plants. The first rule, the “Clean Air Interstate Rule” (“CAIR”), was promulgated by the EPA on March 10, 2005, and required allowance surrender for SO2 and NOx emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR contemplated two implementation phases. The first phase was to begin in 2009 and 2010 for NOx and SO2, respectively. A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission allowance-based “cap-and-trade” programs. CAIR was subsequently challenged in federal court and on July 11, 2008, the U.S. Court of Appeals for the D.C. Circuit issued an opinion striking down CAIR. On December 23, 2008, in response to motions from EPA and other petitioners, the Court issued an opinion and remanded the rule to EPA without vacatur to enable EPA to remedy CAIR’s flaws in accordance with the Court’s July opinion. EPA plans to issue a proposed revision to CAIR in the spring of 2010. In the interim, until EPA finalizes a new rule to replace CAIR, the Company and a number of its subsidiaries are operating subject to the remanded CAIR.
The second rule, the Clean Air Mercury Rule (“CAMR”), was promulgated on March 15, 2005 and as proposed required reductions of mercury emissions from coal-fired power plants in two phases. However, on February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit ruled that CAMR as promulgated violated the CAA and vacated the rule. The EPA is obligated under the CAA, and the District of Columbia Circuit court ruling, to develop a rule requiring pollution controls for hazardous air pollutants (“HAPs”), including mercury, from coal and oil-fired power plants. EPA has entered into a consent decree under which it is obligated to propose the rule by October 2010 and to finalize the rule by November 2011. Under the CAA, compliance is required within three years of the effective date of the rule; however, the compliance date may be extended by the state permitting authorities (for one additional year) or through a determination by the President (for up to two additional years). The CAA requires EPA to establish maximum achievable control technology (“MACT”) standards for each hazardous air pollutant regulated under the CAA. 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 EPA may propose as MACT, the rule will likely 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 U.S. coal-fired plants have acid gas scrubbers or comparable control technologies, but it is possible that EPA regulations will require
THE AES CORPORATION
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improvements to such control technologies at some of our plants. While the exact impact and cost of CAIR, any new federal mercury rules, including MACT standards for HAPs, and any related state proposals cannot be established until they are promulgated, and in the case of CAIR, until the states complete the process of assigning emission allowances to our affected facilities, there can be no assurance that any such new rules will not have a material adverse effect on the Company’s business, financial conditions or results of operations.
The New York State Department of Environmental Conservation (“NYSDEC”) previously promulgated regulations requiring electric generators to reduce SO2 emissions by 50% below current CAA standards. The SO2 regulations began to be phased in beginning on January 1, 2006 with implementation to have been completed by January 1, 2008. These regulations also establish stringent NOx reduction requirements during the non-ozone season, rather than just during the summertime ozone season. NYSDEC has announced that both programs will be phased out due to the federal CAIR programs. On December 23, 2009 NYSDEC published a notice of proposed rulemaking requiring the application of Reasonably Available Control Technology (“RACT”) for reductions in NOx emissions from electric utility and industrial boilers, combustion turbines and internal combustion engines. The proposed regulations establish that sources subject to the new emission limits must demonstrate compliance by July 1, 2012. While the exact impact and cost of the RACT for NOx cannot be established until the rules are promulgated, there can be no assurance that the Company’s business, financial conditions or results of operations would not be materially and adversely affected by any such mandatory reductions in emissions.
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. The Regional Haze Rule was further amended on October 6, 2006 when EPA promulgated a rule allowing states to impose alternatives to BART, including emissions trading, if such alternatives were demonstrated to be more effective than BART. States were required to submit their regional haze state implementation plans (“SIPs”) to the EPA by December 2007. Only 13 states met this deadline. EPA has yet to approve any state’s Regional Haze state implementation plan. The statute requires compliance within 5 years after EPA approves the relevant SIP.
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.
In Chile, a draft regulation has been published by the national environmental regulatory agency (“CONAMA”) that calls for limits on certain emissions from thermal power plants, such as NOx, SO2, metals and PM. The draft regulation is currently undergoing a public hearing process under which interested parties can provide comments to CONAMA which will decide on possible further changes before the regulation is finalized and ultimately submitted to the President for approval. If such regulation were to be enacted in its current form,
THE AES CORPORATION
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the Company’s subsidiaries in Chile may need to acquire and install additional pollution control technologies over a period of three to four years. While the exact impact and cost of any such regulation cannot be determined until it is finalized, there can be no assurance that the Company’s business, financial conditions or results of operations would not be materially or adversely affected by any such mandatory reductions in emissions.
The Company also faces certain risks and uncertainties related to environmental laws and regulations pertaining to water discharges. The Company’s facilities are subject to a variety of rules governing water discharges. In particular, the Company is subject to the U.S. 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 U.S. 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 U.S. EPA. In November 2007, three industry petitioners sought review of the Second Circuit’s decision by the U.S. Supreme Court and this review was granted by the U.S. Supreme Court in April 2008. In its April 2009 decision, the U.S. Supreme Court granted the EPA authority to use a cost-benefit analysis when setting technology-based requirements under the Section 316(b) of the Clean Water Act and expressed no view on the remaining bases for the Second Circuit’s remand. New draft 316(b) regulations are expected to be issued by EPA later this year, and 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 EPA. 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.
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”), its wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCB, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities include CCB, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl (“PCB”) contaminated liquids and solids. The Company endeavors to ensure that all 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 and EPA is expected to issue a proposed rule shortly regarding CCB storage and management. EPA is also evaluating
THE AES CORPORATION
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whether CCB should be regulated as a hazardous waste under the Resource Conservation and Recovery Act (“RCRA”). If EPA promulgates a rule that deems CCB to be a hazardous waste under Subtitle C of the RCRA then ash disposal costs for the Company’s U.S. coal plants would likely increase significantly. Also, many of the Company’s U.S. coal plants currently sell CCB to third parties undertaking “beneficial use” projects in which the CCB is recycled, such as for use in concrete and other building materials. If CCB were deemed to be a hazardous waste under Subtitle C of the RCRA, it could pose a significant hurdle for companies that currently sell CCB as a raw material for beneficial use. Third parties are likely to be less willing or unable to continue using CCB in their products and the Company’s U.S. coal plants may no longer be able to generate revenue from the sale of such CCB. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are promulgated, there can be no assurance that the Company’s business, financial conditions 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 and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a subsidiary on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish the subsidiaries’ intended business purposes. 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. At December 31, 2009, these letters of credit at our consolidated subsidiaries totaled approximately $1.8 billion.
The following table summarizes the Parent Company’s contingent contractual obligations as of December 31, 2009:
Most of the contingent obligations primarily relate to future performance commitments which the Company or its subsidiaries expect to fulfill within the normal course of business. Amounts presented in the above table represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure to the Parent Company as of December 31, 2009. Guarantee termination provisions vary from less than one year to greater than 20 years. Some result from the end of a contract period, assignment, asset sale, and change in credit rating or elapsed time. The amounts above include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of subsidiaries of $49 million.
The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power purchase
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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 2009 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 2009, the Company paid letter of credit fees ranging from 1.63% to 13.34% 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 believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. However, 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 but cannot be 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 $482 million and $389 million as of December 31, 2009 and 2008, respectively.
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$1.0 billion ($577 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 ruled that Eletropaulo was not a proper party to the litigation because any alleged liability was 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 have been dismissed. Eletrobrás has requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo has consented to the appointment of such an expert, subject to a reservation of rights. After the amount of the alleged debt is determined, Eletrobrás may 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. 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. 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.
THE AES CORPORATION
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In September 1999, a state appellate court in Minas Gerais, Brazil, granted a temporary injunction suspending the effectiveness of a shareholders’ agreement between Southern Electric Brasil Participacoes, Ltda. (“SEB”) and the state of Minas Gerais concerning CEMIG, an integrated utility in Minas Gerais. The Company’s investment in CEMIG is through SEB. This shareholders’ agreement granted SEB certain rights and powers with respect to the management of CEMIG (“Special Rights”). In March 2000, a lower state court in Minas Gerais held the shareholders’ agreement invalid where it purported to grant SEB the Special Rights and enjoined the exercise of the Special Rights. In August 2001, the state appellate court denied an appeal of the decision and extended the injunction. In October 2001, SEB filed appeals against the state appellate court’s decision with the SCJ and the Supreme Court. The state appellate court denied access of these appeals to the higher courts, and in August 2002 SEB filed interlocutory appeals against such denial with the SCJ and the Supreme Court. In December 2004, the SCJ declined to hear SEB’s appeal. In December 2009, the Supreme Court also declined to hear SEB’s appeal. In February 2010, SEB filed an appeal with the Supreme Court Collegiate. There can be no assurances that SEB will be successful in any such appeal. Failure to prevail in this matter will preclude SEB from obtaining management control of CEMIG under the Special Rights.
In August 2000, the FERC announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. 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 past five 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, subject to FERC approval, 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. In July 2009, FERC approved the settlement as submitted. In excess of 97% 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 July 2009, one non-settling party, the Sacramento Municipal Utility District (“SMUD”), requested that the FERC rehear its order approving the settlement. The FERC denied SMUD’s request in September 2009. In November 2009, SMUD filed an appeal of the FERC’s approval of the settlement with the U.S. Court of Appeals for the District of Columbia Circuit, which was later transferred to the Ninth Circuit. The settlement agreement is still effective and will continue to remain effective unless it is vacated by the Ninth Circuit.
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.
THE AES CORPORATION
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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. The Company subsequently filed an application to recover its costs of the arbitration, which is under consideration by the tribunal. In addition, 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”), 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. 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
THE AES CORPORATION
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various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of Sao 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. (“Light”) 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. MPF likely will appeal. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and 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 ($3 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
THE AES CORPORATION
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DECEMBER 31, 2009, 2008, AND 2007
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 ($8 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 April 2004, BNDES filed a collection suit against SEB, a subsidiary of the Company, to obtain the payment of R$3.8 billion ($2.2 billion), which includes principal, interest and penalties under the loan agreement between BNDES and SEB, the proceeds of which were used by SEB to acquire shares of CEMIG. In May 2004, the 15th Federal Circuit Court (“Circuit Court”) ordered the attachment of SEB’s CEMIG shares, which were given as collateral for the loan, as well as dividends paid by CEMIG to SEB. At the time of the attachment, the shares were worth approximately R$762 million ($439 million). In December 2006, SEB’s defense was ruled groundless by the Circuit Court. The Federal Court of Appeals affirmed that decision in February 2009. SEB intends to file further appeals. BNDES has seized a total of approximately R$760 million ($438 million) in attached dividends to date, with the approval of the Circuit Court, and is seeking to recover additional attached dividends. Also, BNDES has filed a plea to seize the attached CEMIG shares. The Circuit Court will consider BNDES’s request to seize the attached CEMIG shares after the net value of the alleged debt is recalculated in light of BNDES’s seizure of dividends. SEB 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
THE AES CORPORATION
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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 complaint 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 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 heard oral arguments in November 2008. In October 2009, the Fifth Circuit 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. The Company has filed a petition seeking en banc review at the Fifth Circuit. 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 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 18 billion KZT ($122 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 783 million KZT ($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 will appeal. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 1.8 billion KZT ($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 Nurenergorservice, the Antimonopoly Agency may attempt to seize Nurenergoservice’s remaining assets, which are immaterial to the Company’s consolidated financial statements. The Compensation Committee’s successor, 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 claims and defenses; however, there can be no assurances that it will prevail in these proceedings.
THE AES CORPORATION
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In December 2008, the Antimonopoly Agency ordered Ust-Kamenogorsk HPP (“UK HPP”), a hydroelectric plant under AES concession, to pay approximately 1.1 billion KZT ($7 million) for alleged antimonopoly violations in February through November 2007. The economic court of first instance has issued an injunction to secure UK HPP’s alleged liability, among other things freezing UK HPP’s bank accounts. Also, in March 2009, the economic court affirmed the Antimonopoly Agency’s order. UK HPP’s subsequent appeal to the court of appeals (first panel) was dismissed in April 2009. In June 2009, UK HPP paid the alleged damages and thus the economic court thereafter canceled the injunction on UK HPP’s assets. UK HPP filed an appeal with the Kazakhstan Supreme Court, which was rejected. Furthermore, the Antimonopoly Agency has initiated administrative proceedings against UK HPP for its alleged antimonopoly violations. In May 2009, the administrative court of first instance ordered UK HPP to pay approximately 99 million KZT ($665,000) in administrative fines, which UK HPP did in June 2009.
In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of UK HPP and Shulbinsk HPP, another hydroelectric plant under AES concession (collectively, the “Hydros”), in January through February 2009. The investigation has been suspended pending the outcome of judicial proceedings concerning the inclusion of the Hydros on the list of dominant suppliers in Eastern Kazakhstan and the legality of the underlying Antimonopoly Agency investigation. If the Hydros fail to prove in those proceedings that they are not dominant suppliers and/or that the Antimonopoly Agency’s investigation is groundless, the Antimonopoly Agency’s investigation will resume. The Hydros believe they have meritorious defenses and will assert them vigorously in any formal proceeding concerning the investigation; 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 pending the outcome of judicial proceedings concerning UKT’s challenge of the underlying Antimonopoly Agency investigation. Those judicial proceedings are ongoing. If UKT fails to prevail in those proceedings, the administrative court likely will proceed to order UKT 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 September 2007, the New York Attorney General issued a subpoena to the Company seeking documents and information concerning the Company’s analysis and public disclosure of the potential impacts that GHG legislation and climate change from GHG emissions might have on the Company’s operations and results. The Company produced documents and information in response to the subpoena. In November 2009, the parties executed an Assurance of Discontinuance (“AOD”) ending the New York Attorney General’s inquiry and requiring the Company, among other things, to continue disclosing certain greenhouse gas emissions issues in its Forms 10-K for the four years following the AOD’s execution.
In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees, (the “Complainants”), filed a complaint at the Indiana Utility Regulatory Commission (“IURC”) seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL’s basic rate case. The Complainants requested that the IURC conduct an investigation of IPL’s failure to fund the Voluntary Employee Beneficiary Association Trust (“VEBA Trust”) at a level of
THE AES CORPORATION
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approximately $19 million per year. The VEBA Trust was spun off to an independent trustee in 2001. The complaint sought an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which it allegedly would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The complaint also sought an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties sought summary judgment in the IURC proceeding. In May 2009, the IURC issued an order granting summary judgment in favor of IPL and in June 2009, the Complainants filed an appeal of the IURC’s May 2009 order with the Indiana Court of Appeals. On January 29, 2010, the appellate court affirmed the IURC’s determination. Absent a petition for reconsideration, the Complainants have 30 days to petition for transfer to the Indiana Supreme Court. IPL believes it has meritorious defenses to the Complainants’ claims and it will continue to assert them vigorously in all proceedings; however, there can be no assurances that it will be successful in its efforts.
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 are destroying 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 alleged damages from the defendants, which are not quantified. 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 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 June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant has stopped as a consequence of the Supreme Court’s decision. In September 2009, the Municipality of Puchuncaví issued an order to demolish the Plant on the basis of other permitting issues. In October 2009, EEC and AES Gener filed a judicial claim against the Municipality of Puchuncaví before the Civil Judge of the City of Quintero, seeking to revoke the demolition order and asking for an immediate stay of said order. At the request of EEC and Gener, the Civil Judge of Quintero agreed to suspend the order until a final decision on the order is issued. In December 2009, Chilean authorities approved new land use regulations that entitle EEC to reapply for a new environmental permit. Such permit request was requested on January 14, 2010. The new land use regulations were challenged by local groups and this challenge was rejected by the Court of Appeals of Santiago. The local groups have filed a motion to reconsider in the same court. On February 22, 2010, Chilean environmental authorities approved a new environmental permit for EEC. EEC may now request the construction permits so that the Plant’s construction can resume. However, while we believe that any challenges to a new permit would be without merit, it is possible that third parties may attempt to challenge any new permit issued by the corresponding authorities. EEC and the construction contractor have agreed on a path forward while construction work stoppage is ongoing. However, if EEC is unable to complete the project, AES may be required to record an impairment of the Campiche project proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investments through December 31, 2009 and potential termination costs, AES could incur an impairment of approximately $189 million. In the event an impairment charge is recognized with regard to the project, the amount of such impairment will depend on a number of factors, including EEC’s ability to recover project costs.
A public civil action has been asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near
THE AES CORPORATION
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Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of Sao Paulo in 2006 found that Eletropaulo should either repair the alleged environmental damage by demolishing certain construction and reforesting the area, pursuant to a project which would cost approximately $628,000, or pay an indemnification amount of approximately $5 million. Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.
In 2007, a lower court issued a decision related to a 1993 claim that was filed by the Public Attorney’s office against Eletropaulo, the São 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 Pinheiros River into 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 $230 million for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. 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 October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from EPA pursuant to CAA Section 113(a). The Notice 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 New Source Review (“NSR”) programs 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 projects on coal-fired electric generating units. A similar outcome in this case could have a material impact to IPL. IPL would seek recovery through customer rates of any operating or capital expenditures related to pollution control technology projects or otherwise to reduce regulated emissions; however, there can be no assurances that it would be successful in that regard.
In November 2007, the U.S. Department of Justice (“DOJ”) notified AES Thames, LLC (“AES Thames”) that the EPA had requested that the DOJ file a federal court action against AES Thames for alleged violations of the CAA, the CWA, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”), in particular alleging that AES Thames had violated (i) the terms of its Prevention of Significant Deterioration (“PSD”) air permits in the calculation of its steam load permit limit; and (ii) the CWA, CERCLA and EPCRA in connection with two spills of chlorinating agents that occurred in 2006. The DOJ subsequently indicated that it would like to settle this matter prior to filing a suit and negotiations are ongoing. During such discussions, the DOJ and EPA have accepted AES Thames method of operation and have asked AES Thames to seek a minor permit modification to clarify the air permit condition in a manner that is consistent with AES Thames’ historical method of operation. On October 21, 2008, the DOJ proposed a civil penalty of $245,000 for the alleged violations. The Company believes that it has meritorious defenses to the claims asserted against it and if a settlement cannot be achieved, the Company will defend itself vigorously in any lawsuit.
In December 2008, the National Electricity Regulatory Entity of Argentina (“ENRE”) filed a criminal action in the National Criminal and Correctional Court of Argentina against the board of directors and administrators of EDELAP. ENRE’s action concerns certain bank cancellations of EDELAP debt in 2006 and 2007, which were
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
accomplished through transactions between the banks and related AES companies. ENRE claims that EDELAP should have reflected in its accounts the alleged benefits of the transactions that were allegedly obtained by the related companies. EDELAP believes that the allegations lack merit; however, there can be no assurances that its board and administrators will prevail in the action.
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 Cayuga and/or Somerset, their results of operation or their financial position.
On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation 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 and submitted a demonstration plan to the agency and discussions between the parties are ongoing. Cayuga is awaiting a response from the New York State Department of Environmental Conservation. While at this time it is not possible to predict what impact, if any, this matter may have on Cayuga, its results of operation or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.
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. The IACHR heard arguments by the communities and Panama on the merits of the petition 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 AES Cartagena’s revenues should be reduced by roughly the value of the free CO2 allowances granted to AES Cartagena for 2007, 2008, and the first half of 2009, and that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately 20 million ($29 million) for 2007-2008 and an amount to be determined for the first half of 2009. On September 17, 2009, AES Cartagena received invoices for 523,548 ($750,000) for 2007 and 19,907,248 ($29 million) for 2008. In October 2009, AES Cartagena filed an administrative appeal against both such invoices with the Spanish Ministry of Industry and also applied for a stay of its obligation to pay the invoices pending the hearing of that appeal. In November 2009, the appeal was unsuccessful and the application for stay was rejected. AES Cartagena subsequently filed an appeal with the Spanish Court. There can be no assurances that the judicial appeal will be successful. AES Cartagena has demanded indemnification from GDF-Suez in relation to the CNE invoices and any future such 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 and a determination that GDF-Suez is responsible for procuring
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
and bearing the cost of CO2 allowances that are required to offset the emissions of AES Cartagena’s power plant, which is also in dispute between the parties. 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 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. The Public Defender’s Office is expected to appeal. If the dismissal is 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 ($692 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.
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 for Company matching contributions in Company stock, other Company contributions at the discretion of the Compensation Committee of the Board of Directors in Company stock and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company’s matching contributions. Participants vest in other Company contributions ratably over a five-year period ending on the fifth anniversary of their hire date. Company contributions to the plans were approximately $22 million, $21 million, and $22 million for the years ended December 31, 2009, 2008, and 2007, 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 25 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, 2009, 2008, AND 2007
The following table reconciles the Company’s funded status, both domestic and foreign, as of December 31, 2009 and 2008:
The following table summarizes the amounts recognized on the Consolidated Balance Sheets, both domestic and foreign, as of December 31, 2009 and 2008:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following table summarizes the Company’s accumulated benefit obligation, both domestic and foreign, as of December 31, 2009 and 2008:
The table below demonstrates 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, 2009 and 2008:
A subsidiary of the Company has a defined benefit obligation of $549 million and $528 million as of December 31, 2009 and 2008, respectively, and uses salary bands to determine future benefit costs rather than a rate of compensation increases. Rates of compensation increases in the table above do not include amounts related to this specific defined benefit plan.
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, 2009, 2008, AND 2007
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 our recognized expense in such future periods.
Sensitivity of our pension funded status and stockholders’ equity to the indicated increase or decrease in the discount rate 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 2009. 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, 2009 funded status is affected by the December 31, 2009 assumptions. Pension expense for 2009 is affected by the December 31, 2008 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, 2009 through 2007:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following table summarizes the amounts reflected in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet as of December 31, 2009 that have not yet been recognized as components of net periodic benefit cost:
The following table summarizes the Company’s target allocation for 2009 and pension plan asset allocation, both domestic and foreign, as of December 31, 2009 and 2008:
The U.S. plans seek to achieve the following long-term investment objectives:
•
Maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;
•
Long-term rate of return in excess of the annualized inflation rate;
•
Long-term rate of return (net of relevant fees that meet or exceed the assumed actuarial rate);
•
Long-term competitive rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to control 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 summaries the Company’s U.S. plan assets by category of investment and level within the fair value hierarchy as of December 31, 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. Our assumed asset allocation uses a lower exposure to equities to closely match market conditions and near term forecasts. The following table summaries the Company’s foreign plan assets by category of investment and level within the fair value hierarchy as of December 31, 2009:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
(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 year ended December 31, 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 November 6, 2009, the Company entered into a stock purchase agreement (the “Stock Purchase Agreement”) with Terrific Investment Corporation (“Investor”), a wholly-owned subsidiary of China Investment Corporation (“CIC”), pursuant to which the Company agreed to issue and sell to Investor 125,468,788 shares of the Company’s common stock for $12.60 per share, for an aggregate purchase price of $1.58 billion. Following the issuance of the shares of common stock, Investor’s ownership in the Company’s common stock will be approximately 15% percent of the Company’s total outstanding shares of common stock on a fully diluted basis.
The closing of the sale of the shares of common stock of the Company to Investor is subject to certain closing conditions including, the receipt of various regulatory approvals and no occurrence of a material adverse change prior to closing with respect to the Company. The transaction is expected to close in the first half of 2010.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
At the closing of the transaction, the Company and Investor would enter into a stockholder agreement (the “Stockholder Agreement”). 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 nominate one representative 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 such shares in its discretion. Further, under the Stockholder Agreement, Investor will be subject to a customary standstill restriction which generally prohibits Investor from purchasing additional securities of the Company beyond the 15% fully diluted ownership level acquired by it under the Stock Purchase Agreement. 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.
STOCK REPURCHASE
On August 7, 2008, the Company’s Board of Directors approved a share repurchase plan for up to $400 million of its outstanding common stock. The Board authorization permitted the Company to repurchase shares over a six month period ending 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 shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 9,534,580 and 10,691,267 shares were held in treasury stock at December 31, 2009 and 2008, respectively. At December 31, 2007, there were no shares of common stock held in treasury stock. No shares of common stock were repurchased subsequent to December 31, 2008 and the Board authorization of the plan expired on February 7, 2009. The Company did not retire any shares of treasury stock during the years ended December 31, 2009 or 2008.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
COMPREHENSIVE INCOME
The components of comprehensive income for the years ended December 31, 2009, 2008 and 2007 were as follows:
(1) Reflects the income (loss) attributed to noncontrolling interests in the form of common securities and dividends on preferred stock of subsidiary.
The following table summarizes the balances comprising accumulated other comprehensive loss, net of tax, as of December 31, 2009 and 2008:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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. 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 and Africa Generation 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. Additionally, AES Wind Generation is managed within our North America region and the Company’s climate solutions projects (“Climate Solutions”) are managed within the region in which they are located. Key climate solutions initiatives include investments in GHG initiatives, projects to create emissions offsets for the voluntary U.S. market and projects that produce certified emission reduction credits (“CERs”). Despite the management of AES Wind Generation by the North America region and Climate Solutions within the regions, AES Wind Generation and Climate Solutions are reported within “Corporate and Other” because they do not meet the aggregation criteria to be combined into the respective region’s Generation or Utilities segments or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. 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. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. “Corporate and Other” also includes costs related to business development efforts, which with certain exceptions, the Company manages centrally through a development group; 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 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. In 2009, the Company changed the segment performance measures disclosed to align with how management internally reviews the results and assesses the performance of the business. Accordingly, previously reported segment information has been revised to reflect our new measure of segment performance, Adjusted Gross Margin, to conform to current year presentation.
Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No inter-segment revenue relationships exist between other segments. Corporate allocations include certain management fees and self insurance activity which are reflected within segment
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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, 2009 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, 2009 through 2007:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The table below presents information, by country, about the Company’s consolidated operations for each of the years ended December 31, 2009 through 2007 and as of December 31, 2009 and 2008, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
(1) Acquired in April 2008; 2008 revenue represents results for a partial year.
(2) Currently under development; facility is not operational at this time.
(3) Excludes revenue of $470 million, $607 million and $396 million for the years ended December 31, 2009, 2008 and 2007, respectively, and property, plant and equipment of $36 and $204 million as of December 31, 2009 and 2008, respectively, related to Lal Pir and Pak Gen, which are reflected as discontinued operations and businesses held for sale in the accompanying consolidated statements of operation and consolidated balance sheets.
(4) Excludes revenue of $101 million, $105 million and $105 million for the years ended December 31, 2009, 2008 and 2007, respectively, and property, plant and equipment of $311 million and $321 million as of December 31, 2009 and 2008, respectively, related to Barka, which are reflected as discontinued operations and businesses held for sale in the accompanying consolidated statements of operation and consolidated balance sheets.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 2009, 2008 and 2007 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, 2009, approximately 16 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 market prices of both the traded options and the underlying share are measured at a similar point in time to each other 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 the years ended December 31, 2009, 2008, and 2007. 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 AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The Company does not discount the grant date fair values determined 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 $4.08, $7.65 and $8.49, for the years ended December 31, 2009, 2008, and 2007, 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, 2009, 2008 and 2007. As of December 31, 2009, $10 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, 2009.
A summary of the option activity for year ended December 31, 2009 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 2009 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, 2009. The amount of the aggregate intrinsic value will change based on the fair market value of the Company’s stock.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2009, AES has estimated a forfeiture rate of 19.42% and 11.62% for stock options granted in 2009 to non-officer employees and officer employees of AES, respectively. Those estimates shall 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 $6 million on a straight-line basis over a three year period (approximately $2 million per year) related to stock options granted during the year ended December 31, 2009.
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 redeemed for shares, and thus become transferable.
For the years ended December 31, 2009, 2008, and 2007, 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, 2009, 2008, and 2007 had grant date fair values per RSU of $6.71, $18.87 and $22.28, respectively. The total grant date fair value of RSUs granted without a market condition was $12 million during the year ended December 31, 2009.
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 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, 2009, 2008 and 2007. As of December 31, 2009, $13 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 1.6 years. There were no modifications to RSU awards during the year ended December 31, 2009.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
A summary of the RSUs activity for the year ended December 31, 2009 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, 2009, 2008 and 2007 (number of RSUs in thousands):
(1) Net of shares withheld for taxes of 238,000 in the year ended December 31, 2009. No shares were withheld for taxes during the year ended December 31, 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 redeemed for 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, 2009. A discount of 0.5% 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, 2009. RSUs that included a market condition granted during the year ended December 31, 2009 and 2008 had a grant date fair value per RSU of $6.68 and $16.23, respectively. The total grant date fair value of RSUs with a market condition granted during the year ended December 31, 2009 was $4.9 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 year ended December 31, 2009 would have increased by an immaterial amount.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 financial statements:
(1) Amount represents fair market value on the date of conversion.
(2) RSUs granted in 2006 with a market condition did not vest in 2009 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, 2009, 2008 and 2007. As of December 31, 2009, $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 1.8 years. There were no modifications to RSU awards during the year ended December 31, 2009.
A summary of the restricted stock unit activity for the year ended December 31, 2009 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 2009, 2008 and 2007 (number of RSUs in thousands):
(1) Net of shares withheld for taxes of 153,000 during the year ended December 31, 2009.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
17. SUBSIDIARY STOCK
The Company held $60 million of cumulative preferred stock of a subsidiary at December 31, 2009 and 2008. 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, 2009 and 2008. 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 full 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 non-controlling 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.
In May and October 2007, Cachagua sold a 0.9% and 10.2% ownership interest, respectively, in AES Gener for $330.9 million. The sale reduced the Company’s ownership percentage of AES Gener to 80.2%. The Company recorded a pre-tax gain on the sale of $134.2 million, including $8.3 million of related fees.
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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
Other income of $466 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 $377 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.
Other income of $358 million for the year ended December 31, 2007 included a $135 million contract settlement gain at Eastern Energy in New York, a $93 million gross receipts tax recovery at Eletropaulo and Tiete, and favorable legal settlements at Eletropaulo and Red Oak in New Jersey.
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 $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 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 connection with the refinancing in June 2008, as further discussed in Note 10-Long Term Debt, and IPALCO associated with a $375 million refinancing in April 2008, and losses on disposal of assets primarily at Eletropaulo in Brazil.
Other expense of $253 million for the year ended December 31, 2007 included a loss of $90 million on the retirement of Senior Secured Notes at the parent company, a $28 million charge related to an increase in contingencies in Kazakhstan and losses on sales and disposals of assets at Eletropaulo and Sul in Brazil.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
19. ASSET IMPAIRMENT EXPENSE
Asset impairment expense for the years ended December 31, 2009, 2008 and 2007 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.
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 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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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.
During the fourth quarter of 2007, the combination of gas curtailments and increases in the spot market price of energy triggered an impairment analysis of Uruguaiana’s long-lived assets for recoverability. Based on the accounting guidance for the impairment or disposal of long-lived assets, management concluded that an impairment occurred during fourth quarter 2007 due to the carrying amount of its long-lived asset exceeding its fair value. The expected present value of future cash flows was used to estimate fair value. As a result of this impairment analysis, a pre-tax impairment charge of $352 million was recognized which represents a full impairment of the fixed assets. Uruguaiana is a thermoelectric plant located in Brazil and is reported in the Latin America Generation segment.
In August 2007, Placerita, a gas-fired combined cycle generation plant located in the United States, sustained property damage to the compressor section in one of its gas turbines. This event triggered an impairment analysis of the plant’s long-lived assets, which resulted in a pre-tax impairment charge of approximately $25 million, which represents the net book value of the plant. It was determined that no future net cash flows would be received from the use of this long-lived asset and it was fully impaired. Placerita is reported in the North America Generation segment.
In May 2006, AES advanced AgCert, a United Kingdom based corporation that produces emission reduction credits, cash of $52 million. AES recognized this prepayment as a long-term asset as consideration for future CER credits and AgCert stock warrants. The asset was revalued each period based on current exchange rates. In the fourth quarter of 2007, AgCert notified AES that it was not able to meet its contractual obligations to deliver CERs, which triggered an analysis of the asset’s recoverability. AgCert’s financial information indicated a significant decrease in liquidity. As a result of the decline in liquidity and AgCert’s inability to fulfill its contractual obligations for future delivery of the CERs, the Company recognized a pre-tax impairment charge of $14 million using the net present value of forecasted operations. This investment and long-term asset are reported in “Corporate and Other”.
Other Impairments
In addition to the asset impairment expense discussed above, other-than-temporary impairments of cost method investments of $12 million and $15 million were recorded in the years ended December 31, 2009 and 2008, respectively. These impairment charges primarily related to the Company’s investment in 2007 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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 recorded.
There was no other-than-temporary impairment of cost method investments in the year ended December 31, 2007.
20. INCOME TAXES
INCOME TAX PROVISION
The following table summarizes the expense for income taxes on continuing operations, for the years ended December 31, 2009, 2008 and 2007:
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, 2009, 2008 and 2007:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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, 2009 and 2008:
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 carry forwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.
As of December 31, 2009, the Company had federal net operating loss carry forwards for tax purposes of approximately $2.1 billion expiring in years 2020 to 2029. Due to a transaction undertaken in the second quarter of 2009, the federal net operating loss carryforward now includes a U.S. entity that previously was not included in the U.S. consolidated tax group. Approximately $68 million of the net operating loss carry forward related to stock option deductions will be recognized in additional paid-in capital when realized. The Company also had federal general business tax credit carry forwards of approximately $18 million expiring primarily from 2021 to 2029, and federal alternative minimum tax credits of approximately $14 million that carry forward without expiration. The Company had state net operating loss carry forwards as of December 31, 2009 of approximately $3.4 billion expiring in years 2012 to 2029. As of December 31, 2009, the Company had foreign net operating loss carry forwards of approximately $4.3 billion that expire at various times beginning in 2010 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $36 million, $3 million of which expire in 2010 to 2012, $14 million of which expire in 2013 to 2020 and $19 million of which carry forward without expiration.
Valuation allowances increased by $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.
Valuation allowances decreased by $210 million during 2008 to $1.4 billion at December 31, 2008. This net decrease was primarily the result of decreases in deferred tax assets at certain Brazilian subsidiaries that required corresponding decreases in the valuation allowances.
The Company believes that it is more likely than not that the remaining deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income. The Company is monitoring the utilization of its deferred tax asset for its
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
U.S. consolidated net operating loss carry forward. 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 carry forwards, such realization is not assured.
The following table summarizes the deferred tax assets and liabilities, as of December 31, 2009 and 2008:
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.
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 $47 million, $35 million and $42 million for the years ended December 31, 2009, 2008 and 2007, 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, 2009, 2008 and 2007:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
UNCERTAIN TAX POSITIONS
Uncertain tax positions have been classified as non-current 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, 2009 and 2008, the total amount of gross accrued income tax related interest included in the Consolidated Balance Sheets was $21 million and $25 million, respectively. The total amount of gross accrued income tax related penalties included in the Consolidated Balance Sheets as of December 31, 2009 and 2008 was $5 million and $5 million, respectively.
The total expense for interest related to unrecognized tax benefits for the years ended December 31, 2009, 2008 and 2007 amounted to $4 million, $2 million and $15 million, respectively. For the years ended December 31, 2009, 2008 and 2007, the total expense (benefit) for penalties related to unrecognized tax benefits amounted to $- million, $(2) million and $4 million, respectively.
We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitation 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, 2009, 2008 and 2007, the total amount of unrecognized tax benefits was $511 million, $555 million and $590 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2009, 2008 and 2007 is $484 million, $527 million and $533 million, respectively, of which $55 million, $131 million and $144 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 of unrecognized tax benefits within 12 months of December 31, 2009 is estimated to be between $4 million and $5 million.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2009, 2008 and 2007:
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 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, 2009. 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, 2009, 2008 and 2007:
In December 2009, the Company entered into agreements to sell its interests in three generation businesses located in Pakistan and Oman, reported in the Asia Generation segment. The businesses, Lal Pir and Pak Gen,
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
located in Pakistan, and Barka, located in Oman, will be sold to two separate buyers. The sales are expected to close in the first half of 2010. Upon completion of the transactions, the company will sell its 55% ownership in Lal Pir and Pak Gen, two oil-fired facilities with respective generation capacities of 362 MW and 365 MW. Further, the company will also sell its 35% ownership interest in Barka, a 456MW combined cycle gas facility and water desalination plant and its 100% ownership interest in two Barka related service companies. The Company will receive proceeds upon the closing of the two transactions of approximately $200 million before purchase price adjustments. The Company recognized an impairment after noncontrolling interests of $105 million against its share of Lal Pir and Pak Gen, which represents the net book value of the Company’s investment in Lal Pir and Pak Gen less the fair value.
In December 2008, the Company reached an agreement to sell its 70% equity interest in Jiaozuo AES Wanfang Power Co., Ltd. (“Jiaozuo”), which is reported in the Asia Generation segment, for approximately $73 million net of any withholding taxes. The AES Board of Directors approved the sale of Jiaozuo which closed on December 15, 2008 and 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. This gain is included in the 2008 gain (loss) from disposal of discontinued businesses line item on the consolidated Statement of Operations for the year ended December 31, 2008.
On February 22, 2007, the Company entered into a definitive agreement with Petróleos de Venezuela, S.A., (“PDVSA”) to sell all of its shares of EDC, a distribution business reported in the Latin America Utilities segment, for $739 million, net of any withholding taxes. In addition, the agreement provided for the payment of a $120 million dividend in 2007 which was declared on March 1, 2007 payable to the EDC shareholders of record as of March 9, 2007. A wholly-owned subsidiary of the Company was the owner of 82.14% of the outstanding shares of EDC, and therefore, on May 31, 2007, received approximately $97 million in dividends (representing approximately $99 million in gross dividends offset by fees). The sale of EDC and the payment of the purchase price occurred on May 16, 2007. EDC is classified as “discontinued operations” and reflected as such on the face of the Consolidated Financial Statements for all periods presented. During the first quarter of 2007, the Company recognized an impairment charge of approximately $638 million related to this sale. As a result of the final disposition of EDC in May 2007, the Company recognized an additional impairment charge of approximately $42 million, net of income and withholding taxes. The total impairment charge of $680 million represented the net book value of the Company’s investment in EDC less the selling price. The Company impaired the carrying value of EDC’s electric generation and distribution assets to their net realizable value. The impairment expense was included in the loss from disposal of discontinued businesses line item on the Consolidated Statement of Operations for the year ended December 31, 2007.
In July 2007, the Company’s wholly-owned subsidiary, Central Valley, sold 100% of its indirect interest in two biomass fired power plants located in central California (the 50 MW Delano facility and the 25 MW Mendota facility) for $51 million. These facilities, along with an associated management company (together, the “Central Valley Businesses”) were included in the North America Generation segment. Central Valley is classified as “discontinued operations” in the Company’s Consolidated Financial Statements for all periods presented. The Company recognized a gain on the sale of approximately $20 million net of income and withholding taxes.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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. Total consideration for the transaction was approximately $1.1 billion with potential earn-out provisions up to an additional $381 million over a three-year period. These businesses generated total revenue of $114 million and $106 million, and net income (loss) of $61 million and $(35) million for the years ended December 31, 2008 and 2007, respectively, excluding intercompany transactions. The sale was completed on May 30, 2008. As a result of AES’s 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
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. Environmental clean-up costs have been estimated pending a detailed study. Including transaction costs and completion of the planned upgrade program to improve environmental and operational performance, the total project cost is estimated to be $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.
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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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” in the Company’s condensed consolidated statement of operations during the first quarter of 2009. The cash was received by the Company in April 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 credit worthy 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 condensed 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 in 2009 and generated revenue of $114 million and $106 million for the years ended December 31, 2008 and 2007, respectively.
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, after giving effect to stock splits. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restrictive stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
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 excluded 18,035,813, 11,150,853 and 5,740,727 options outstanding at December 31, 2009, 2008 and 2007, 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 2008, all convertible debentures were included in the earnings per share calculation. In 2009 and 2007, all convertible debentures were omitted from the earnings per share calculation because they were antidilutive.
24. RISKS AND UNCERTAINTIES
AES is a global power producer in 29 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 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 to 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, 2009, the Company had $1.8 billion of unrestricted cash and cash equivalents.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
During 2009, approximately 82% 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. While our growth strategy evolved as 2009 progressed, to focus on targeted projects in order to maintain our liquidity, 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;
•
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;
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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;
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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.
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 devaluations 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;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
•
changes in the definition or determination of controllable or non-controllable costs;
•
adverse changes in tax law;
•
changes in the definition of events which may or may not qualify as changes in economic equilibrium;
•
changes in the timing of tariff increases;
•
other changes in the regulatory determinations under the relevant concessions; or
•
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 environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. The Company’s financial position and results of operations have been significantly affected by fluctuations in the value of the 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 37 years. No single customer accounted for 10% or more of total revenue in 2009, 2008, or 2007.
The cash flows and results of operations of such plants are dependent on the credit quality of the purchasers and the continued ability of their customers and suppliers to meet their obligations under the relevant power sales contract. If a substantial portion of the Company’s long-term power sales contracts were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company’s business, results of operations and financial condition.
25. OFF-BALANCE SHEET ARRANGEMENTS AND RELATED PARTY TRANSACTIONS
IPL, a consolidated subsidiary of the Company, formed IPL Funding Corporation (“IPL Funding”) in 1996 as a special purpose entity to purchase, on a revolving basis, the receivables originated by IPL. IPL Funding is not a qualified special purpose entity and is consolidated by IPL and IPALCO. IPL Funding entered into a sale facility with unrelated parties (“the Purchasers”) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, interests in the pool of receivables purchased from IPL up to the lesser of (1) an amount determined pursuant to the sale facility that takes into account certain eligibility requirements and reserves relating to the receivables, or (2) $50 million. Historically that amount has remained at $50 million, but during the fourth quarter of 2009, IPL’s eligible receivables balance was below $50 million and IPL was required to repay the Purchasers the shortfall, which was approximately $10 million as of December 31, 2009. As collections reduce accounts receivable included in the pool, IPL Funding sells ownership interests in additional receivables acquired from IPL to return the ownership interests sold to the maximum amount permitted by the sale facility. During the second quarter of 2009, this agreement was extended through May 25, 2010. Accounts receivable on the Company’s consolidated balance sheets are stated net of the $40 million and $50 million sold
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
as of December 31, 2009 and 2008, respectively and include $88 million and $87 million as of December 31, 2009 and 2008, respectively, related to IPL Funding’s accounts receivable.
IPL retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, the Purchasers assume the risk of collection on the purchased receivables without recourse to IPL in the event of a loss. While no direct recourse to IPL exists, it risks loss in the event collections are not sufficient to allow for full recovery of its retained interests. No servicing asset or liability is recognized since the servicing fee paid to IPL approximates a market rate.
The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses, the selection of discount rates and expected receivables turnover rate. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20% unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.
The losses recognized on the sales of receivables were $1 million, $2 million and $3 million for the years ended December 31, 2009, 2008 and 2007, respectively. These losses are included in other expense on the consolidated statements of operations. The amount of the losses recognized depends on the previous carrying amount of the financial assets involved in the transfer, allocated between the assets sold and the interests that continue to be held by the transferor based on their relative fair value at the date of transfer, and the proceeds received.
There were no proceeds from new securitizations for each of the years ended December 31, 2009 and 2008. IPL Funding pays IPL annual service fees totaling $1 million, which is financed by capital contributions from IPL to IPL Funding.
The following table shows the receivables sold and retained interests as of December 31, 2009 and 2008:
The following table shows the cash flows for the years ended December 31, 2009, 2008 and 2007:
IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of, or otherwise relating to, the sale facility, subject to certain limitations as defined in the sale facility.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
Under the sale facility, if IPL fails to maintain certain financial covenants including, but not limited to interest coverage and debt to capital ratios, it would constitute a “termination event.” As of December 31, 2009, IPL was in compliance with such covenants. In the event that IPL’s credit rating falls below a threshold identified in the sale facility, the facility agent has the ability to replace IPL as the collection agent and declare a “lock-box” event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. In addition, a termination event would also give the facility agent the option to take control of the lock-box account, give the Purchasers the option to discontinue the purchase of new receivables, and require all proceeds to be used to reduce the Purchaser’s investment and pay other amounts owed to the Purchasers and the facility agent. This could reduce the operating capital available to IPL by the aggregate amount of any purchased receivables up to $50 million.
Our generation businesses in Panama are partially owned by the Government of Panama (the “Government”). The Government, in turn, partially owns the distribution companies within Panama. For the years ended December 31, 2009, 2008 and 2007, our Panamanian businesses recognized electricity sales to the Government totaling $143 million, $203 million and $168 million, respectively. For the same period, our Panamanian businesses purchased electricity, which excludes transmission charges from the Government, totaling $25 million, $27 million and $24 million, respectively. As of December 31, 2009 and 2008, our Panamanian businesses owed the Government $7 million and $2 million, respectively, payable on normal trade terms. For the same period, the Government owed our Panamanian businesses $25 million and $29 million, respectively, payable on normal trade terms.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
26. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data
The following tables summarize the unaudited quarterly statements of operations for the Company for 2009 and 2008. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2009, 2008, AND 2007
27. SUBSEQUENT EVENTS
Subsequent events have been evaluated through the date of issuance of this Form 10-K.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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, 2009, 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, 2009. 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, 2009.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, 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, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
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, 2009, 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 at Item 9A. 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, 2009, 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 its subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the two years in the period ended December 31, 2009 of The AES Corporation and our report dated February 25, 2010 expressed an unqualified opinion thereon.
/s/: Ernst & Young LLP
McLean, Virginia
February 25, 2010

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION.
None.
PART III

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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following information is incorporated by reference from the 2010 Proxy Statement, File No. 001-12291, which will be filed on or around March 9, 2010 (the 2010 Proxy Statement):
•
Information regarding the directors required by this item found under the heading Board of Directors
•
Information regarding AES’s 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’s 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 Proxy Statement for the 2010 Annual Meeting of Shareholders and is hereby incorporated by reference.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The following information is contained in the 2010 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.

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ITEM 12. SECURITY OWNERSHIP
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 2010 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 2010 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.
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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information regarding related party transactions required by this item is included in the 2010 Proxy Statement found under the headings Transactions with Related Persons, Proposal I: Election of Directors and The Committees of the Board are incorporated by reference.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information concerning principal accountant fees and services included in the 2010 Proxy Statement contained under the heading Information Regarding The Independent Registered Public Accounting Firm’s Fees, Services and Independence is incorporated by reference.
PART IV

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements.
Financial Statements and Schedules:
Page
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
Schedules
S-2-S-8
(b) Exhibits.
3.1
Sixth Restated Certificate of Incorporation of The AES Corporation is incorporated by reference to Exhibit 3.1 of the Company’s Form 10-K for the year ended December 31, 2008.
3.2
By-Laws of The AES Corporation, as amended and incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on August 11, 2009.
There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request. Since these documents are not required filings under Item 601 of Regulation S-K, the Company has elected to file certain of these documents as Exhibits 4(a)-4(o).
4.(a)
Junior Subordinated Indenture, dated as of March 1, 1997, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated by reference to Exhibit 4.(a) of the Company’s Form 10-K for the year ended December 31, 2008.
4.(b)
Third Supplemental Indenture, dated as of October 14, 1999, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated by reference to Exhibit 4.(b) of the Company’s Form 10-K for the year ended December 31, 2008.
4.(c)
Senior Indenture, dated as of December 8, 1998, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated by reference to Exhibit 4.01 of the Company’s Form 8-K filed on December 11, 1998.
4.(d)
Form of Second Supplemental Indenture, dated as of June 11, 1999, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated by reference to Exhibit 4.01 of the Company’s Form 8-K filed on June 11, 1999.
4.(e)
Third Supplemental Indenture, dated as of September 12, 2000, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated by reference to Exhibit 4.(e) of the Company’s Form 10-K for the year ended December 31, 2008.
4.(f)
Form of Fifth Supplemental Indenture, dated as of February 9, 2001, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed on February 8, 2001.
4.(g)
Form of Sixth Supplemental Indenture, dated as of February 22, 2001, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association is incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed on February 21, 2001.
4.(h)
Ninth Supplemental Indenture, dated as of April 3, 2003, between The AES Corporation and Wells Fargo Bank, National Association (as successor by consolidation to Wells Fargo Bank Minnesota, National Association) is incorporated by reference to Exhibit 4.6 of the Company’s Form S-4 filed on December 7, 2007.
4.(i)
Form of Tenth Supplemental Indenture, dated as of February 13, 2004, between The AES Corporation and Wells Fargo Bank, National Association (as successor by consolidation to Wells Fargo Bank Minnesota, National Association) is incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed on February 13, 2004.
4.(j)
Eleventh Supplemental Indenture, dated as of October 15, 2007, between The AES Corporation and Wells Fargo Bank, National Association is incorporated by reference to Exhibit 4.7 of the Company’s Form S-4 filed on December 7, 2007.
4.(k)
Twelfth Supplemental Indenture, dated as of October 15, 2007, between The AES Corporation and Wells Fargo Bank, National Association is incorporated by reference to Exhibit 4.8 of the Company’s Form S-4 filed on December 7, 2007.
4.(l)
Thirteenth Supplemental Indenture, dated as of May 19, 2008, between The AES Corporation and Wells Fargo Bank, National Association is incorporated by reference to Exhibit 4.(l) of the Company’s Form 10-K for the year ended December 31, 2008.
4.(m)
Fourteenth Supplemental indenture, dated as of April 2, 2009, between The AES Corporation and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K filed on April 2, 2009.
4.(n)
Senior Indenture, dated as of May 8, 2003, between The AES Corporation and Wells Fargo Bank, National Association (as successor by consolidation to Wells Fargo Bank Minnesota, National Association) is incorporated by reference to Exhibit 4.(m) of the Company’s Form 10-K for the year ended December 31, 2008.
4.(o)
First Supplemental Indenture, dated as of May 28, 2008, between The AES Corporation and Wells Fargo Bank, National Association is incorporated by reference to Exhibit 4.(n) of the Company’s Form 10-K for the year ended December 31, 2008.
10.1
The AES Corporation Profit Sharing and Stock Ownership Plan are incorporated herein by reference to Exhibit 4(c)(1) of the Registration Statement on Form S-8 (Registration No. 33-49262) filed on July 2, 1992.
10.2
The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 of the Company’s Form 10-K for the year ended December 31, 1995.
10.3
Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 of the Registration Statement on Form S-1 (Registration No. 33-40483).
10.4
Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 of Amendment No. 1 to the Registration Statement on Form S-1(Registration No. 33-40483).
10.5
Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.9 of the Company’s Form 10-Q for the quarter ended March 31, 1998.
10.6
The AES Corporation Stock Option Plan for Outside Directors as amended is incorporated herein by reference to Appendix C of the Registrant’s 2003 Proxy Statement filed on March 25, 2003.
10.7
The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.63 of the Company’s Form 10-K for the year ended December 31, 1994.
10.7A
Amendment to The AES Corporation Supplemental Retirement Plan, dated March 13, 2008 is incorporated herein by reference to Exhibit 10.9.A of the Company’s Form 10-K for the year ended December 31, 2007.
10.8
The AES Corporation 2001 Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company’s Form 10-K for the year ended December 31, 2000.
10.9
Second Amended and Restated Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.13 of the Company’s Form 10-K for the year ended December 31, 2000.
10.10
The AES Corporation 2001 Non-Officer Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company’s Form 10-K for the year ended December 31, 2002.
10.10A
Amendment to the 2001 Stock Option Plan and 2001 Non-Officer Stock Option Plan, dated March 13, 2008 is incorporated herein by reference to Exhibit 10.12.A of the Company’s Form 10-K for the year ended December 31, 2007.
10.11
The AES Corporation 2003 Long Term Compensation Plan, as amended and restated on April 24, 2008, is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on April 24, 2008.
10.11.A
Form of Nonqualified Stock Option Award Agreement Pursuant to the AES Corporation 2003 Long Term Compensation Plan is incorporated by reference to Exhibit 10.13A to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2004.*
10.11.B
Form of Performance Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan is incorporated by reference to Exhibit 10.13B to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2004.*
10.11.C
Form of Restricted Stock Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan is incorporated by reference to Exhibit 10.13C to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2004.*
10.12
The AES Corporation Amended and Restated Employment Agreement with Paul Hanrahan is incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K filed on December 31, 2008.
10.13
The AES Corporation Amended and Restated Employment Agreement with Victoria D. Harker is incorporated herein by reference to Exhibit 99.2 of the Company’s Form 8-K filed on December 31, 2008.
10.14
The AES Corporation Employment Agreement with Andres Gluski is incorporated herein by reference to Exhibit 99.3 of the Company’s Form 8-K filed on December 31, 2008.
10.15
The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, dated December 29, 2008 is incorporated by reference to Exhibit 10.15 of the Company’s Form 10-K for the year ended December 31, 2008.
10.16
The AES Corporation International Retirement Plan, as amended and restated on December 29, 2008 is incorporated by reference to Exhibit 10.16 of the Company’s Form 10-K for the year ended December 31, 2008.
10.17
The AES Corporation Severance Plan, as amended and restated on December 29, 2008 is incorporated by reference to Exhibit 10.17 of the Company’s Form 10-K for the year ended December 31, 2008.
10.18
The AES Corporation Performance Incentive Plan, as amended and restated, dated December 29, 2008 is incorporated by reference to Exhibit 10.18 of the Company’s Form 10-K for the year ended December 31, 2008.
10.19
Second Amended and Restated Pledge Agreement dated as of December 12, 2002 between AES EDC Funding II, L.L.C. and Citicorp USA, Inc., as Collateral Agent is incorporated herein by reference to Exhibit 99.3 of the Company’s Form 8-K filed on December 17, 2002.
10.20
Fourth Amended And Restated Credit And Reimbursement Agreement dated as of July 29, 2008 among The AES Corporation, a Delaware corporation, the Subsidiary Guarantors listed therein, the Banks listed on the signature pages thereof, Citigroup Global Markets Inc., as Lead Arranger and Book Runner, Banc of America Securities LLC, as Lead Arranger and Book Runner and as Co-Syndication Agent, Deutsche Bank Securities Inc, as Lead Arranger and Book Runner, Union Bank of California, N.A., as Co-Syndication Agent and as Lead Arranger and Book Runner and as Syndication Agent, Lehman Commercial Paper Inc., as Co-Documentation Agent, UBS Securities LLC, as Co-Documentation Agent, Société Générale, as Co-Documentation Agent, Credit Lyonnais New York Branch, as Co-Documentation Agent, Citicorp USA, Inc., as Administrative Agent for the Bank Parties and Citibank, N.A., as Collateral Agent for the Bank Parties is incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K filed on July 31, 2008.
10.20.A
Appendix I, Revolving Credit Loan Facility pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.A of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.B
Appendix II, Initial Term Loan Facility pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.B of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.C
Appendix III, Existing Letters of Credit pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.C of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.D
Schedule I, Pledged Subsidiaries pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.D of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.E
Schedule II, Assigned Agreements pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.E of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.F
Schedule III, Non-Pledged Subsidiaries pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.F of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.G
Schedule IV, Excluded AES Entities pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.G of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.H
Schedule 5.15, Existing Agreements with Affiliates pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.H of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.I
Schedule V, Qualified Holding Companies pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.I of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.J
Schedule VI, Existing Debt pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.J of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.K
Schedule VII, Revolving Fronting Banks pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.K of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.L
Exhibit A-1, Form of Revolving Credit Loan Note pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.L of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.M
Exhibit A-2, Form of Term Loan Note pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.M of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.N
Exhibit B-1, Form of Opinion of the General Counsel of the Borrower pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to Exhibit 10.1.N of the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.O
Exhibit B-2, Form of Opinion of Davis Polk & Wardwell, Special Counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.P
Exhibit B-3, Form of Opinion of Special Counsel for certain Subsidiaries of the Borrower pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.Q
Exhibit B-4, Form of Opinion of Morris, Nichols, Arsht & Tunnell, Delaware counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.R
Exhibit B-5, Form of Opinion of Maples and Calder, Cayman Islands counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.S
Exhibit B-6, Form of Opinion of Conyers Dill & Pearman, British Virgin Islands counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.T
Exhibit B-7, Form of Opinion of Shearman & Sterling, Special Counsel for the Agent pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.U
Exhibit C-1, Form of Revolving Credit Loan Facility Assignment and Assumption Agreement pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.V
Exhibit C-2, Form of Term Loan Facility Assignment and Assumption Agreement pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.W
Exhibit C-3, Form of Third Party Fronting Bank Assignment and Assumption Agreement pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20.X
Exhibit D, Form of Revolving Fronting Bank Agreement pursuant to the Fourth Amended and Restated Credit Agreement is incorporated herein by reference to the Company’s Form 10-Q for the period ended June 30, 2009.
10.20A
Amendment No. 1 to the Fourth Amended and Restated Credit and Reimbursement Agreement dated as of March 26, 2009 among the Company, the subsidiary guarantors, Citicorp USA, Inc., as Administrative Agent, Citibank N.A. as Collateral Agent and various lenders named therein is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on March 26, 2009.
10.21
The definitive agreement between Petroleos de Venezuela S.A. and The AES Corporation and AES Shannon Holdings B.V. dated February 15, 2007 is incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K filed on February 27, 2007.
10.22
Collateral Trust Agreement dated as of December 12, 2002 among The AES Corporation, AES International Holdings II, Ltd., Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, an individual trustee is herein incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on December 17, 2002.
10.23
Security Agreement dated as of December 12, 2002 made by The AES Corporation to Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is herein incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed on December 17, 2002.
10.24
Charge Over Shares dated as of December 12, 2002 between AES International Holdings II, Ltd. and Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is herein incorporated by reference to Exhibit 4.4 of the Company’s Form 8-K filed on December 17, 2002.
10.25
The AES Corporation Severance Agreement with William Luraschi, dated May 14, 2008 is incorporated by reference to Exhibit 10.28 of the Company’s Form 10-K for the year ended December 31, 2008.
10.26
The AES Corporation Severance Agreement with Jay Kloosterboer, dated November 26, 2008 is incorporated by reference to Exhibit 10.29 of the Company’s Form 10-K for the year ended December 31, 2008.
10.27
The AES Corporation Severance Agreement with David Gee, dated February 26, 2009 is incorporated by reference to Exhibit 10.30 of the Company’s Form 10-K for the year ended December 31, 2008.
10.28
Stock Purchase Agreement between The AES Corporation and Terrific Investment Corporation dated November 6, 2009 is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on November 11, 2009.
Statement of computation of ratio of earnings to fixed charges (filed herewith).
Letter from Deloitte & Touche LLP addressed to the Securities and Exchange Commission relating to auditor dismissal dated December 13, 2007 is incorporated by reference to Exhibit 16.1 of the Company’s Form 8-K filed on December 13, 2007.
Subsidiaries of The AES Corporation (filed herewith).
23.1
Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP (filed herewith).
23.2
Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP (filed herewith).
Power of Attorney (filed herewith).
31.1
Rule13a-14(a)/15d-14(a) Certification of Paul Hanrahan (filed herewith).
31.2
Rule 13a-14(a)/15d-14(a) Certification of Victoria D. Harker (filed herewith).
32.1
Section 1350 Certification of Paul Hanrahan (filed herewith).
32.2
Section 1350 Certification of Victoria D. Harker (filed herewith).
The following materials from The AES Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009 formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Operations, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Changes in Equity, (v) the Notes to the Consolidated Financial Statements, tagged as block text.
(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.
THE AES CORPORATION
(Company)
Date: February 25, 2010
By:
/S/ PAUL HANRAHAN
Name:
Paul Hanrahan President,
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
Name
Title
Date
*
Paul Hanrahan
President, Chief Executive Officer (Principal Executive Officer) and Director
February 25, 2010
*
Samuel W. Bodman, III
Director
February 25, 2010
*
Tarun Khanna
Director
February 25, 2010
*
John A. Koskinen
Director
February 25, 2010
*
Philip Lader
Director
February 25, 2010
*
John B. Morse
Director
February 25, 2010
*
Sandra O. Moose
Director
February 25, 2010
*
Philip A. Odeen
Chairman of the Board and Lead Independent Director
February 25, 2010
*
Charles O. Rossotti
Director
February 25, 2010
*
Sven Sandstrom
Director
February 25, 2010
/S/ VICTORIA D. HARKER
Victoria D. Harker
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
February 25, 2010
/S/ MARY WOOD
Mary Wood
Vice President and Controller (Principal Accounting Officer)
February 25, 2010
*BY:
/S/ BRIAN A. MILLER
Attorney-in-fact
February 25, 2010
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
(IN MILLIONS)
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-Effective January 1, 2007, the Company adopted the provisions set forth in the accounting guidance for uncertainty in income taxes. Under the guidance, 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, 2009 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, 2009, by the terms of the agreements, to an aggregate of approximately $410 million representing 31 agreements with individual exposures ranging from less than $1 million up to $53 million.
LETTERS OF CREDIT-At December 31, 2009, the Company had $204 million in letters of credit outstanding representing 26 agreements with individual exposures ranging from less than $1 million up to $120 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. During 2009, the Company paid letter of credit fees ranging from 1.63% to 13.34% per annum on the outstanding amounts.
S-7
THE AES CORPORATION
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(IN MILLIONS)
S-8

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Stock Performance Metrics:
Return: -0.0008547204197384417
1-Day Return: $1_day_return
3-Day Return: $3_day_return
5-Day Return: $5_day_return
10-Day Return: $10_day_return
20-Day Return: $20_day_return
40-Day Return: $40_day_return
60-Day Return: $60_day_return
80-Day Return: $80_day_return
100-Day Return: $100_day_return
150-Day Return: $150_day_return
252-Day Return: $252_day_return