ITEM 1. BUSINESS
Overview
We were incorporated in 1981 and are a diversified power generation and utility company organized into six market-oriented SBUs:
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US (United States),
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Andes (Chile, Colombia, and Argentina),
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Brazil,
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MCAC (Mexico, Central America and Caribbean),
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Europe (formerly EMEA), and
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Asia.
Item 1.-Business is an outline of our strategy and our businesses by SBU, including key financial drivers. Additional items that may have an impact on our businesses are discussed in Item 1A.
ITEM 1A. RISK FACTORS
You should consider carefully the following risks, along with the other information contained in or incorporated by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. If any of the following events actually occur, our business, financial results and financial condition could be materially adversely affected.
We routinely encounter and address risks, some of which may cause our future results to be different, sometimes materially different, than we presently anticipate. The categories of risk we have identified in Item 1A.-Risk Factors of this Form 10-K include the following:
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risks related to our high level of indebtedness;
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risks associated with our ability to raise needed capital;
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external risks associated with revenue and earnings volatility;
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risks associated with our operations; and
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risks associated with governmental regulation and laws.
These risk factors should be read in conjunction with Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related notes included elsewhere in this report.
Risks Related to our High Level of Indebtedness
We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations.
As of December 31, 2014, we had approximately $20.9 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings under The AES Corporation’s senior secured credit facility are secured by certain of our assets, including the pledge of capital stock of many of The AES Corporation’s directly held subsidiaries. Most of the debt of The AES Corporation’s subsidiaries is secured by substantially all of the assets of those subsidiaries. Since we have such a high level of debt, a substantial portion of cash flow from operations must be used to make payments on this debt. Furthermore, since a significant percentage of our assets are used to secure this debt, this reduces the amount of collateral that is available for future secured debt or credit support and reduces our flexibility in dealing with these secured assets. This high level of indebtedness and related security could have other important consequences to us and our investors, including:
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making it more difficult to satisfy debt service and other obligations at the holding company and/or individual subsidiaries;
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increasing the likelihood of a downgrade of our debt, which could cause future debt costs and/or payments to increase under our debt and related hedging instruments and consume an even greater portion of cash flow;
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increasing our vulnerability to general adverse industry and economic conditions, including but not limited to adverse changes in foreign exchange rates and commodity prices;
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reducing the availability of cash flow to fund other corporate purposes and grow our business;
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limiting our flexibility in planning for, or reacting to, changes in our business and the industry;
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placing us at a competitive disadvantage to our competitors that are not as highly leveraged; and
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limiting, along with the financial and other restrictive covenants relating to such indebtedness, among other things, our ability to borrow additional funds as needed or take advantage of business opportunities as they arise, pay cash dividends or repurchase common stock.
The agreements governing our indebtedness, including the indebtedness of our subsidiaries, limit, but do not prohibit the incurrence of additional indebtedness. To the extent we become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flows may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets, raise equity or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. See Note 12-Debt included in Item 8. of this Form 10-K for a schedule of our debt maturities.
The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.
The AES Corporation is a holding company with no material assets other than the stock of its subsidiaries. All of The AES Corporation’s revenue is generated through its subsidiaries. Accordingly, almost all of The AES Corporation’s cash flow is generated by the operating activities of its subsidiaries. Therefore, The AES Corporation’s ability to make payments on its indebtedness and to fund its other obligations is dependent not only on the ability of its subsidiaries to generate cash, but also on the ability of the subsidiaries to distribute cash to it in the form of dividends, fees, interest, tax sharing payments, loans or otherwise.
However, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation. Most of the subsidiaries are obligated, pursuant to loan agreements, indentures or non-recourse financing arrangements, to satisfy certain restricted payment covenants or other conditions before they may make distributions to The AES Corporation. In addition, the payment of dividends or the making of loans, advances or other payments to The AES Corporation may be subject to other contractual, legal or regulatory restrictions or may be prohibited altogether. Business performance and local accounting and tax rules may limit the amount of retained earnings that may be distributed to us as a dividend. Subsidiaries in foreign countries may also be prevented from distributing funds to The AES Corporation as a result of foreign governments restricting the repatriation of funds or the conversion of currencies. Any right that The AES Corporation has to receive any assets of any of its subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of The AES Corporation’s indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary’s creditors (including trade creditors and holders of debt issued by such subsidiary).
The AES Corporation’s subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of The AES Corporation’s indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other payments.
Even though The AES Corporation is a holding company, existing and potential future defaults by subsidiaries or affiliates could adversely affect The AES Corporation.
We attempt to finance our domestic and foreign projects primarily under loan agreements and related documents which, except as noted below, require the loans to be repaid solely from the project’s revenues and provide that the repayment of the loans (and interest thereon) is secured solely by the capital stock, physical assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as non-recourse debt or “non-recourse financing.” In some non-recourse financings, The AES Corporation has explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take the form of guarantees, indemnities, letter of credit reimbursement agreements and agreements to pay, in certain circumstances, the project lenders or other parties.
As of December 31, 2014, we had approximately $20.9 billion of outstanding indebtedness on a consolidated basis, of which approximately $5.3 billion was recourse debt of The AES Corporation and approximately $15.6 billion was non-recourse debt. In addition, we have outstanding guarantees, indemnities, letters of credit, and other credit support commitments which are further described in this Form 10-K in Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Parent Company Liquidity.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in our consolidated balance sheets related to such defaults was $0.9 billion as of December 31, 2014. While the lenders under our non-recourse financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults thereunder can still have important consequences for The AES Corporation, including, without limitation:
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reducing The AES Corporation’s receipt of subsidiary dividends, fees, interest payments, loans and other sources of cash since the project subsidiary will typically be prohibited from distributing cash to The AES Corporation during the pendency of any default;
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under certain circumstances, triggering The AES Corporation’s obligation to make payments under any financial guarantee, letter of credit or other credit support which The AES Corporation has provided to or on behalf of such subsidiary;
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causing The AES Corporation to record a loss in the event the lender forecloses on the assets;
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triggering defaults in The AES Corporation’s outstanding debt and trust preferred securities. For example, The AES Corporation’s senior secured credit facility and outstanding senior notes include events of default for certain bankruptcy related events involving material subsidiaries. In addition, The AES Corporation’s senior secured credit facility includes certain events of default relating to accelerations of outstanding material debt of material subsidiaries or any subsidiaries that in the aggregate constitute a material subsidiary;
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the loss or impairment of investor confidence in the Company; or
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foreclosure on the assets that are pledged under the non-recourse loans, therefore eliminating any and all potential future benefits derived from those assets.
None of the projects that are currently in default are owned by subsidiaries that individually or in the aggregate meet the applicable standard of materiality in The AES Corporation’s senior secured credit facility or other debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of future mix of distributions, write-down of assets, dispositions and other matters that affect our financial position and results of operations, it is possible that one or more of these subsidiaries, individually or in the aggregate, could fall within the applicable standard of materiality and thereby upon an acceleration of such subsidiary’s debt, trigger an event of default and possible acceleration of the indebtedness under The AES Corporation’s senior secured credit facility or other indebtedness of The AES Corporation.
Risks Associated with our Ability to Raise Needed Capital
The AES Corporation, or the Parent Company, has significant cash requirements and limited sources of liquidity.
The AES Corporation requires cash primarily to fund:
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principal repayments of debt;
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interest and preferred dividends;
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acquisitions;
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construction and other project commitments;
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other equity commitments, including business development investments;
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equity repurchases and/or cash dividends on our common stock;
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taxes; and
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Parent Company overhead costs.
The AES Corporation’s principal sources of liquidity are:
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dividends and other distributions from its subsidiaries;
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proceeds from debt and equity financings at the Parent Company level; and
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proceeds from asset sales.
For a more detailed discussion of The AES Corporation’s cash requirements and sources of liquidity, please see Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity of this Form 10-K.
While we believe that these sources will be adequate to meet our obligations at the Parent Company level for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital or commercial lending markets, the operating and financial performance of our subsidiaries, exchange rates, our ability to sell assets, and the ability of our subsidiaries to pay dividends. Any number of assumptions could prove to be incorrect, and, therefore there can be no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than expected. For example, in recent years, certain financial institutions have gone bankrupt. In the event that a bank who is party to our senior secured credit facility or other facilities goes bankrupt or is otherwise unable to fund its commitments, we would need to replace that bank in our syndicate or risk a reduction in the size of the facility, which would reduce our liquidity. In addition, our cash flow may not be sufficient to repay at maturity the entire principal outstanding under our credit facility and our debt securities and we may have to refinance such obligations. There can be no assurance that we will be successful in obtaining such refinancing on terms acceptable to us or at all and any of these events could have a material effect on us.
Our ability to grow our business could be materially adversely affected if we were unable to raise capital on favorable terms.
From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Our ability to arrange for financing on either a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:
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general economic and capital market conditions;
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the availability of bank credit;
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investor confidence;
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the financial condition, performance and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing as well as companies in our industry or similar financial circumstances; and
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changes in tax and securities laws which are conducive to raising capital.
Should future access to capital not be available to us, we may have to sell assets or decide not to build new plants or expand or improve existing facilities, either of which would affect our future growth, results of operations or financial condition.
A downgrade in the credit ratings of The AES Corporation or its subsidiaries could adversely affect our ability to access the capital markets which could increase our interest costs or adversely affect our liquidity and cash flow.
If any of the credit ratings of The AES Corporation or its subsidiaries were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs could increase. Furthermore, depending on The AES Corporation’s credit ratings and the trading prices of its equity and debt securities, counterparties may no longer be as willing to accept general unsecured commitments by The AES Corporation to provide credit support. Accordingly, with respect to both new and existing commitments, The AES Corporation may be required to provide some other form of assurance, such as a letter of credit and/or collateral, to backstop or replace any credit support by The AES Corporation. There can be no assurance that such counterparties will accept such guarantees or that AES could arrange such further assurances in the future. In addition, to the extent The AES Corporation is required and able to provide letters of credit or other collateral to such counterparties, it will limit the amount of credit available to The AES Corporation to meet its other liquidity needs.
We may not be able to raise sufficient capital to fund developing projects in certain less developed economies which could change or in some cases adversely affect our growth strategy.
Part of our strategy is to grow our business by developing businesses in less developed economies where the return on our investment may be greater than projects in more developed economies. Commercial lending institutions sometimes refuse to provide non-recourse project financing in certain less developed economies, and in these situations we have sought and will continue to seek direct or indirect (through credit support or guarantees) project financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such project financing available, the
lending institutions may also require governmental guarantees of certain project and sovereign related risks. There can be no assurance, however, that project financing from the international financial agencies or that governmental guarantees will be available when needed, and if they are not, we may have to abandon the project or invest more of our own funds which may not be in line with our investment objectives and would leave less funds for other projects.
External Risks Associated with Revenue and Earnings Volatility
Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance.
Some of our businesses sell electricity in the spot markets in cases where they operate at levels in excess of their power sales agreements or retail load obligations. Our businesses may also buy electricity in the wholesale spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. The open market wholesale prices for electricity can be volatile and often reflect the fluctuating cost of fuels such as coal, natural gas or oil in addition to other factors described below. Consequently, any changes in the supply and cost of coal, natural gas, or oil may impact the open market wholesale price of electricity.
Volatility in market prices for fuel and electricity may result from among other things:
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plant availability in the markets generally;
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availability and effectiveness of transmission facilities owned and operated by third parties;
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competition;
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electricity usage;
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seasonality;
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foreign exchange rate fluctuation;
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availability and price of emission credits;
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hydrology and other weather conditions;
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illiquid markets;
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transmission or transportation constraints or inefficiencies;
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availability of competitively priced renewables sources;
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increased adoption of distributed generation;
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available supplies of natural gas, crude oil and refined products, and coal;
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generating unit performance;
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natural disasters, terrorism, wars, embargoes, and other catastrophic events;
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energy, market and environmental regulation, legislation and policies;
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geopolitical concerns affecting global supply of oil and natural gas;
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general economic conditions in areas where we operate which impact energy consumption; and
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bidding behavior and market bidding rules.
Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.
Our exposure to currency exchange rate fluctuations results primarily from the translation exposure associated with the preparation of the Consolidated Financial Statements, as well as from transaction exposure associated with transactions in currencies other than an entity’s functional currency. While the Consolidated Financial Statements are reported in U.S. Dollars, the financial statements of many of our subsidiaries outside the United States are prepared using the local currency as the functional currency and translated into U.S. Dollars by applying appropriate exchange rates. As a result, fluctuations in the exchange rate of the U.S. Dollar relative to the local currencies where our subsidiaries outside the United States report could cause significant fluctuations in our results. In addition, while our expenses with respect to foreign operations are generally denominated in the same currency as corresponding sales, we have transaction exposure to the extent receipts and expenditures are not denominated in the subsidiary’s functional currency. Moreover, the costs of doing business abroad may increase as a result of adverse exchange rate fluctuations. Our financial position and results of operations could be affected by fluctuations in the value of a number of currencies. See Item 7A.-Quantitative and Qualitative Information Disclosures about Market Risk to this Form 10-K for further information.
We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.
We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity, fuel requirements and other commodities to lower our financial exposure related to commodity price fluctuations. As part of this
strategy, we routinely utilize fixed price or indexed forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. We also enter into contracts which help us manage our interest rate exposure. However, we may not cover the entire exposure of our assets or positions to market price or interest rate volatility, and the coverage will vary over time. Furthermore, the risk management practices we have in place may not always perform as planned. In particular, if prices of commodities or interest rates significantly deviate from historical prices or interest rates or if the price or interest rate volatility or distribution of these changes deviates from historical norms, our risk management practices may not protect us from significant losses. As a result, fluctuating commodity prices or interest rates may negatively impact our financial results to the extent we have unhedged or inadequately hedged positions. In addition, certain types of economic hedging activities may not qualify for hedge accounting under U.S. GAAP, resulting in increased volatility in our net income. The Company may also suffer losses associated with “basis risk” which is the difference in performance between the hedge instrument and the targeted underlying exposure. Furthermore, there is a risk that the current counterparties to these arrangements may fail or are unable to perform part or all of their obligations under these arrangements.
Our coal-fired facilities in the US continue to face substantial challenges as a result of high coal prices relative to natural gas, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place but purchase fuel at market prices or under short term contracts. For our businesses with PPA pricing that does not perfectly pass through our fuel costs, the businesses attempt to manage the exposure through flexible fuel purchasing and timing of entry and terms of our fuel supply agreements; however, these risk management efforts may not be successful and the resulting commodity exposure could have a material impact on these businesses and/or our results of operations.
Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.
We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of our facilities. If these suppliers cannot perform, we would seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price, which could adversely impact the profitability of the affected business and our results of operations, and could result in a breach of agreements with other counterparties, including, without limitation, offtakers or lenders.
At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility’s output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. We have also hedged a portion of our exposure to power price fluctuations through forward fixed price power sales. Counterparties to these agreements may breach or may be unable to perform their obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement PPAs, these businesses may have to sell power at market prices. A breach by a counterparty of a PPA or other agreement could also result in the breach of other agreements, including, without limitation, the debt documents of the affected business.
The failure of any supplier or customer to fulfill its contractual obligations to The AES Corporation or our subsidiaries could have a material adverse effect on our financial results. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
The market pricing of our common stock has been volatile and may continue to be volatile in future periods.
The market price for our common stock has been volatile in the past, and the price of our common stock could fluctuate substantially in the future. Stock price movements on a quarter by quarter basis for the past two years are set forth in Item 5.-Market-Market Information of this Form 10-K. Factors that could affect the price of our common stock in the future include general conditions in our industry, in the power markets in which we participate and in the world, including environmental and economic developments, over which we have no control, as well as developments specific to us, including, risks that could result in revenue and earnings volatility as well as other risk factors described in this Item 1A.-Risk Factors and those matters described in Item 7.-Management’s Discussion and Analysis of Financial Conditions and Results of Operations.
Risks Associated with our Operations
We do a significant amount of business outside the United States, including in developing countries, which presents significant risks.
A significant amount of our revenue is generated outside the United States and a significant portion of our international operations is conducted in developing countries. Part of our growth strategy is to expand our business in certain developing countries in which AES has an existing presence as such countries may have higher growth rates and offer greater opportunities to expand from our platforms, with potentially higher returns than in some more developed countries. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:
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economic, social and political instability in any particular country or region;
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adverse changes in currency exchange rates;
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government restrictions on converting currencies or repatriating funds;
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unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;
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high inflation and monetary fluctuations;
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restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
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threatened or consummated expropriation or nationalization of our assets by foreign governments;
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risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, United Kingdom Bribery Act or other anti-bribery laws applicable to our operations;
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difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with GAAP expertise;
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unwillingness of governments, government agencies, similar organizations or other counterparties to honor their contracts;
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unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;
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inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
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adverse changes in government tax policy;
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difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and
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potentially adverse tax consequences of operating in multiple jurisdictions.
Any of these factors, by itself or in combination with others, could materially and adversely affect our business, results of operations and financial condition. Our operations may experience volatility in revenues and operating margin which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability and currency devaluations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses. A number of our businesses are facing challenges associated with regulatory changes.
The operation of power generation, distribution and transmission facilities involves significant risks that could adversely affect our financial results. We and/or our subsidiaries may not have adequate risk mitigation and/or insurance coverage for liabilities.
We are in the business of generating and distributing electricity, which involves certain risks that can adversely affect financial and operating performance, including:
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changes in the availability of our generation facilities or distribution systems due to increases in scheduled and unscheduled plant outages, equipment failure, failure of transmission systems, labor disputes, disruptions in fuel supply, poor hydrologic and wind conditions, inability to comply with regulatory or permit requirements or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, explosions, terrorist acts, cyber attacks or other similar occurrences; and
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changes in our operating cost structure including, but not limited to, increases in costs relating to gas, coal, oil and other fuel; fuel transportation; purchased electricity; operations, maintenance and repair; environmental compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental emission equipment; transmission access; and insurance.
Our businesses require reliable transportation sources (including related infrastructure such as roads, ports and rail), power sources and water sources to access and conduct operations. The availability and cost of this infrastructure affects capital and operating costs and levels of production and sales. Limitations, or interruptions in this infrastructure or at the facilities of our subsidiaries, including as a result of third parties intentionally or unintentionally disrupting this infrastructure or the facilities of our subsidiaries, could impede their ability to produce electricity. This could have a material adverse effect on our businesses’ results of operations, financial condition and prospects.
In addition, a portion of our generation facilities were constructed many years ago. Older generating equipment may require significant capital expenditures for maintenance. The equipment at our plants, whether old or new, is also likely to require periodic upgrading, improvement or repair, and replacement equipment or parts may be difficult to obtain in circumstances where we rely on a single supplier or a small number of suppliers. The inability to obtain replacement equipment or parts may impact the ability of our plants to perform and could, therefore, have a material impact on our business and results
of operations. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of a power purchase or other agreement or incurrence of a liability for liquidated damages and/or other penalties.
As a result of the above risks and other potential hazards associated with the power generation, distribution and transmission industries, we may from time to time become exposed to significant liabilities for which we may not have adequate risk mitigation and/or insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility of the occurrence and impact of these risks.
The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is customary, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A claim for which we are not fully insured or insured at all could hurt our financial results and materially harm our financial condition. Further, due to the cyclical nature of the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.
Our businesses’ insurance does not cover every potential risk associated with its operations. Adequate coverage at reasonable rates is not always obtainable. In addition, insurance may not fully cover the liability or the consequences of any business interruptions such as equipment failure or labor dispute. The occurrence of a significant adverse event not fully or partially covered by insurance could have a material adverse effect on the Company’s business, results or operations, financial condition and prospects.
Any of the above risks could have a material adverse effect on our business and results of operations.
Our inability to attract and retain skilled people could have a material adverse effect on our operations.
Our operating success and ability to carry out growth initiatives depends in part on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity, including people in our foreign businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements. For example, we routinely are required to assess the financial impacts of complicated business transactions which occur on a worldwide basis. These assessments are dependent on hiring personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with United States reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse effect on our financial and tax reporting.
We have contractual obligations to certain customers to provide full requirements service, which makes it difficult to predict and plan for load requirements and may result in increased operating costs to certain of our businesses.
We have contractual obligations to certain customers to supply power to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of power that our power generation and distribution facilities must be prepared to supply to customers may increase our operating costs. A significant under- or over-estimation of load requirements could result in our facilities not having enough or having too much power to cover their obligations, in which case we would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating costs.
We may not be able to enter into long-term contracts, which reduce volatility in our results of operations. Even when we successfully enter into long-term contracts, our generation businesses are often dependent on one or a limited number of customers and a limited number of fuel suppliers.
Many of our generation plants conduct business under long-term sales and supply contracts, which helps these businesses to manage risks by reducing the volatility associated with power and input costs and providing a stable revenue and cost structure. In these instances, we rely on power sales contracts with one or a limited number of customers for the majority of, and in some cases all of, the relevant plant’s output and revenues over the term of the power sales contract. The remaining terms of the power sales contracts of our generation plants range from one to 25 years. In many cases, we also limit our
exposure to fluctuations in fuel prices by entering into long-term contracts for fuel with a limited number of suppliers. In these instances, the cash flows and results of operations are dependent on the continued ability of customers and suppliers to meet their obligations under the relevant power sales contract or fuel supply contract, respectively. Some of our long-term power sales agreements are at prices above current spot market prices and some of our long-term fuel supply contracts are at prices below current market prices. The loss of significant power sales contracts or fuel supply contracts, or the failure by any of the parties to such contracts that prevents us from fulfilling our obligations thereunder, could adversely impact our strategy by resulting in costs that exceed revenue, which could have a material adverse impact on our business, results of operations and financial condition. In addition, depending on market conditions and regulatory regimes, it may be difficult for us to secure long-term contracts, either where our current contracts are expiring or for new development projects. The inability to enter into long-term contracts could require many of our businesses to purchase inputs at market prices and sell electricity into spot markets, which may not be favorable.
We have sought to reduce counterparty credit risk under our long-term contracts in part by entering into power sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from certain sovereign governments of the customer’s obligations. However, many of our customers do not have, or have failed to maintain, an investment-grade credit rating, and our generation business cannot always obtain government guarantees and if they do, the government does not always have an investment grade credit rating. We have also sought to reduce our credit risk by locating our plants in different geographic areas in order to mitigate the effects of regional economic downturns. However, there can be no assurance that our efforts to mitigate this risk will be successful.
Competition is increasing and could adversely affect us.
The power production markets in which we operate are characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental or operating experience (including both domestic and international) and financial resources similar to or greater than ours. Further, in recent years, the power production industry has been characterized by strong and increasing competition with respect to both obtaining power sales agreements and acquiring existing power generation assets. In certain markets, these factors have caused reductions in prices contained in new power sales agreements and, in many cases, have caused higher acquisition prices for existing assets through competitive bidding practices. The evolution of competitive electricity markets and the development of highly efficient gas-fired power plants have also caused, or are anticipated to cause, price pressure in certain power markets where we sell or intend to sell power. These competitive factors could have a material adverse effect on us.
Some of our subsidiaries participate in defined benefit pension plans and their net pension plan obligations may require additional significant contributions.
Certain of our subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Of the thirty one defined benefit plans, five are at United States subsidiaries and the remaining plans are at foreign subsidiaries. Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. The Company periodically evaluates the value of the pension plan assets to ensure that they will be sufficient to fund the respective pension obligations. The Company’s exposure to market volatility is mitigated to some extent due to the fact that the asset allocations in our largest plans include a significant weighting of investments in fixed income securities that are less volatile than investments in equity securities. Future downturns in the debt and/or equity markets, or the inaccuracy of any of our significant assumptions underlying the estimates of our subsidiaries’ pension plan obligations, could result in an increase in pension expense and future funding requirements, which may be material. Our subsidiaries who participate in these plans are responsible for satisfying the funding requirements required by law in their respective jurisdiction for any shortfall of pension plan assets compared to pension obligations under the pension plan. This may necessitate additional cash contributions to the pension plans that could adversely affect the Parent Company and our subsidiaries’ liquidity.
For additional information regarding the funding position of the Company’s pension plans, see Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Estimates-Pension and Postretirement Obligations and Note 15-Benefit Plans included in Item 8.-Financial Statements and Supplementary Data included in this Form 10-K.
Our business is subject to substantial development uncertainties.
Certain of our subsidiaries and affiliates are in various stages of developing and constructing power plants, some but not all of which have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion depends upon overcoming substantial risks, including, but not limited to, risks relating to siting, financing, engineering and construction, permitting, governmental approvals, commissioning delays, or the potential for termination of the power sales
contract as a result of a failure to meet certain milestones. For additional information regarding our projects under construction see, Item 1.-Business-Our Organization and Segments included in this Form 10-K.
In certain cases, our subsidiaries may enter into obligations in the development process even though the subsidiaries have not yet secured financing, power purchase arrangements, or other aspects of the development process. For example, in certain cases, our subsidiaries may instruct contractors to begin the construction process or seek to procure equipment even where they do not have financing or a power purchase agreement in place (or conversely, to enter into a power purchase, procurement or other agreement without financing in place). If the project does not proceed, our subsidiaries may remain obligated for certain liabilities even though the project will not proceed. Development is inherently uncertain and we may forgo certain development opportunities and we may undertake significant development costs before determining that we will not proceed with a particular project. We believe that capitalized costs for projects under development are recoverable; however, there can be no assurance that any individual project will be completed and reach commercial operation. If these development efforts are not successful, we may abandon a project under development and write off the costs incurred in connection with such project. At the time of abandonment, we would expense all capitalized development costs incurred in connection therewith and could incur additional losses associated with any related contingent liabilities.
In some of our joint venture projects and businesses and at The AES Corporation, we have granted protective rights to minority shareholders or we own less than a majority of the equity in the project or business and do not manage or otherwise control the project or business, which entails certain risks.
We have invested in some joint ventures where our subsidiaries share operational, management, investment and/or other control rights with our joint venture partners. In many cases, we may exert influence over the joint venture pursuant to a management contract, by holding positions on the board of the joint venture company or on management committees and/or through certain limited governance rights, such as rights to veto significant actions. However, we do not always have this type of influence over the project or business in every instance and we may be dependent on our joint venture partners or the management team of the joint venture to operate, manage, invest or otherwise control such projects or businesses. Our joint venture partners or the management team of our joint ventures may not have the level of experience, technical expertise, human resources, management and other attributes necessary to operate these projects or businesses optimally, and they may not share our business priorities. In some joint venture agreements where we do have majority control of the voting securities, we have entered into shareholder agreements granting protective minority rights to the other shareholders.
The approval of joint venture partners also may be required for us to receive distributions of funds from jointly owned entities or to transfer our interest in projects or businesses. The control or influence exerted by our joint venture partners may result in operational management and/or investment decisions which are different from the decisions our subsidiaries would make if they operated independently and could impact the profitability and value of these joint ventures. In addition, in the event that a joint venture partner becomes insolvent or bankrupt or is otherwise unable to meet its obligations to the joint venture or its share of liabilities at the joint venture, we may be subject to joint and several liability for these joint ventures, if and to the extent provided for in our governing documents or applicable law.
The AES Corporation entered into a Shareholders Agreement with Terrific Investment Corporation ("Investor"), a subsidiary of China Investment Corporation, in connection with the purchase of shares from AES in 2010. The Shareholders Agreement provides Investor with certain rights, including, without limitation, the right to nominate a Director to the Board of The AES Corporation, registration rights for the shares held by Investor, including demand registration rights and piggyback registration rights. Further information regarding the Shareholders Agreement can be found in the agreement itself, which is filed as an exhibit to this Form 10-K. In December of 2013, Terrific sold a significant percentage of its holdings, though it continues to hold over 8% of the Company’s outstanding shares. In the event that Terrific determines to sell additional shares of the Company, there could be a material impact on our share price.
Our renewable energy projects and other initiatives face considerable uncertainties including, development, operational and regulatory challenges.
Wind Generation, our solar projects and our investments in projects such as energy storage are subject to substantial risks. Projects of this nature have been developed through advancement in technologies which may not be proven or whose commercial application is limited, and which are unrelated to our core business. Some of these business lines are dependent upon favorable regulatory incentives to support continued investment, and there is significant uncertainty about the extent to which such favorable regulatory incentives will be available in the future.
Furthermore, production levels for our wind and solar projects may be dependent upon adequate wind or sunlight resulting in volatility in production levels and profitability. For example, for our wind projects, wind resource estimates are based on historical experience when available and on wind resource studies conducted by an independent engineer, and are not expected to reflect actual wind energy production in any given year.
As a result, these types of renewable energy projects face considerable risk relative to our core business, including the risk that favorable regulatory regimes expire or are adversely modified. In addition, because certain of these projects depend on technology outside of our expertise in generation and utility businesses, there are risks associated with our ability to develop and manage such projects profitably. Furthermore, at the development or acquisition stage, because of the nascent nature of these industries or the limited experience with the relevant technologies, our ability to predict actual performance results may be hindered and the projects may not perform as predicted. There are also risks associated with the fact that some of these projects exist in markets where long-term fixed price contracts for the major cost and revenue components may be unavailable, which in turn may result in these projects having relatively high levels of volatility. Even where available, many of our renewable projects sell power under a Feed-in-Tariff, which may be eliminated or reduced, which can impact the profitability of these projects, or make money through the sale of Emission Reductions products, such as Certified Emissions Reductions, Renewable Energy Certificates or Renewable Obligation Certificates, and the price of these products may be volatile.
These projects can be capital-intensive and generally are designed with a view to obtaining third party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to develop these projects or obtain third party financing for these projects. These risks may be exacerbated by the current global economic crisis, including our management’s increased focus on liquidity, which may also result in slower growth in the number of projects we can pursue. The economic downturn could also impact the value of our assets in these countries and our ability to develop these projects. If the value of these assets decline, this could result in a material impairment or a series of impairments which are material in the aggregate, which would adversely affect our financial statements.
Impairment of goodwill or long-lived assets would negatively impact our consolidated results of operations and net worth.
As of December 31, 2014, the Company had approximately $1.5 billion of goodwill, which represented approximately 3.7% of the total assets on its Consolidated Balance Sheets. Goodwill is not amortized, but is evaluated for impairment at least annually, or more frequently if impairment indicators are present. We could be required to evaluate the potential impairment of goodwill outside of the required annual evaluation process if we experience situations, including but not limited to: deterioration in general economic conditions, or our operating or regulatory environment; increased competitive environment; increase in fuel costs, particularly when we are unable to pass through the impact to customers; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; divestiture of a significant component of our business; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment, which could substantially affect our results of operations for those periods. Additionally, goodwill may be impaired if our acquisitions do not perform as expected. See the risk factor Our acquisitions may not perform as expected for further discussion.
Long-lived assets are initially recorded at fair value and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present whereas goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above.
Certain of our businesses are sensitive to variations in weather.
Our businesses are affected by variations in general weather patterns and unusually severe weather. Our businesses forecast electric sales on the basis of normal weather, which represents a long-term historical average. While we also consider possible variations in normal weather patterns and potential impacts on our facilities and our businesses, there can be no assurance that such planning can prevent these impacts, which can adversely affect our business. Generally, demand for electricity peaks in winter and summer. Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less demand for electricity than forecasted. Significant variations from normal weather where our businesses are located could have a material impact on our results of operations.
In addition, we are dependent upon hydrological conditions prevailing from time to time in the broad geographic regions in which our hydroelectric generation facilities are located. If hydrological conditions result in droughts or other conditions that negatively affect our hydroelectric generation business, our results of operations could be materially adversely affected.
Information security breaches could harm our business.
A security breach of our information technology systems or plant control systems used to manage and monitor operations could impact the reliability of our generation fleets and/or the reliability of our transmission and distribution systems. A security breach that impairs our technology infrastructure could disrupt normal business operations and affect our ability to control our transmission and distribution assets, access customer information and limit our communications with third parties. Our security measures may not prevent such security breaches. Any loss of confidential or proprietary data through a breach
could impair our reputation, expose us to legal claims, or impact our ability to make collections or otherwise impact our operations, and materially adversely affect our business and results of operations.
Our acquisitions may not perform as expected.
Historically, acquisitions have been a significant part of our growth strategy. We may continue to grow our business through acquisitions. Although acquired businesses may have significant operating histories, we will have a limited or no history of owning and operating many of these businesses and possibly limited or no experience operating in the country or region where these businesses are located. Some of these businesses may have been government owned and some may be operated as part of a larger integrated utility prior to their acquisition. If we were to acquire any of these types of businesses, there can be no assurance that:
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we will be successful in transitioning them to private ownership;
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such businesses will perform as expected;
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integration or other one-time costs will not be greater than expected;
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we will not incur unforeseen obligations or liabilities;
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such businesses will generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them; or
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the rate of return from such businesses will justify our decision to invest capital to acquire them.
Risks associated with Governmental Regulation and Laws
Our operations are subject to significant government regulation and our business and results of operations could be adversely affected by changes in the law or regulatory schemes.
Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain expected or contracted increases in electricity tariff or contract 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 at our utilities where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:
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changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs to be included in the rates we charge our customers, including but not limited to costs incurred to upgrade our power plants to comply with more stringent environmental regulations;
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changes in the determination of what is an appropriate rate of return on invested capital or a determination that a utility’s operating income or the rates it charges customers are too high, resulting in a reduction of rates or consumer rebates;
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changes in the definition or determination of controllable or non-controllable costs;
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adverse changes in tax law;
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changes in law or regulation which limit or otherwise affect the ability of our counterparties (including sovereign or private parties) to fulfill their obligations (including payment obligations) to us or our subsidiaries;
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changes in environmental law which impose additional costs on our subsidiaries;
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changes in the definition of events which may or may not qualify as changes in economic equilibrium;
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changes in the timing of tariff increases;
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other changes in the regulatory determinations under the relevant concessions;
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other changes related to licensing or permitting which affect our ability to conduct business; or
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other changes that impact the short or long term price-setting mechanism in the markets where we operate.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect our business.
In many countries where we conduct business, the regulatory environment is constantly changing and it may be difficult to predict the impact of the regulations on our businesses. On July 21, 2010, President Obama signed the Dodd-Frank Act. While the bulk of regulations contained in the Dodd-Frank Act regulate financial institutions and their products, there are several provisions related to corporate governance, executive compensation, disclosure and other matters which relate to public companies generally. The types of provisions described above are currently not expected to have a material impact on the Company or its results of operations. Furthermore, while the Dodd-Frank Act substantially expands the regulation regarding the trading, clearing and reporting of derivative transactions, the Dodd-Frank Act provides for commercial end-user exemptions which may apply to our derivative transactions. However, even with the exemption, the Dodd-Frank Act could still have a material adverse impact on the Company, as the regulation of derivatives (which includes capital and margin requirements for
non-exempt companies), could limit the availability of derivative transactions that we use to reduce interest rate, commodity and currency risks, which would increase our exposure to these risks. Even if derivative transactions remain available, the costs to enter into these transactions may increase, which could adversely affect the operating results of certain projects; cause us to default on certain types of contracts where we are contractually obligated to hedge certain risks, such as project financing agreements; prevent us from developing new projects where interest rate hedging is required; cause the Company to abandon certain of its hedging strategies and transactions, thereby increasing our exposure to interest rate, commodity and currency risk; and/or consume substantial liquidity by forcing the Company to post cash and/or other permitted collateral in support of these derivatives. In addition to the Dodd-Frank Act, in 2012, the EMIR became effective. EMIR includes regulations related to the trading, reporting and clearing of derivatives and the impacts described above could also result from our (or our subsidiaries’) efforts to comply with EMIR. It is also possible that additional similar regulations may be passed in other jurisdictions where we conduct business. Any of these outcomes could have a material adverse effect on the Company.
Our business in the United States is subject to the provisions of various laws and regulations administered in whole or in part by the FERC and NERC, including PURPA, the Federal Power Act, and the EPAct 2005. Actions by the FERC, NERC and by state utility commissions can have a material effect on our operations.
EPAct 2005 authorizes the FERC to remove the obligation of electric utilities under Section 210 of PURPA to enter into new contracts for the purchase or sale of electricity from or to QFs if certain market conditions are met. Pursuant to this authority, the FERC has instituted a rebuttable presumption that utilities located within the control areas of the Midwest Independent Transmission System Operator, Inc., PJM Interconnection, L.L.C., ISO New England, Inc., the NYISO and the Electric Reliability Council of Texas, Inc. are not required to purchase or sell power from or to QFs above a certain size. In addition, the FERC is authorized under EPAct 2005 to remove the purchase/sale obligations of individual utilities on a case-by-case basis. While this law does not affect existing contracts, as a result of the changes to PURPA, our QFs may face a more difficult market environment when their current long-term contracts expire.
EPAct 2005 repealed PUHCA 1935 and enacted PUHCA 2005 in its place. PUHCA 1935 had the effect of requiring utility holding companies to operate in geographically proximate regions and therefore limited the range of potential combinations and mergers among utilities. By comparison, PUHCA 2005 has no such restrictions and simply provides the FERC and state utility commissions with enhanced access to the books and records of certain utility holding companies. The repeal of PUHCA 1935 removed barriers to mergers and other potential combinations which could result in the creation of large, geographically dispersed utility holding companies. These entities may have enhanced financial strength and therefore an increased ability to compete with us in the United States generation market.
In accordance with Congressional mandates in the EPAct 1992 and now in EPAct 2005, the FERC has strongly encouraged competition in wholesale electric markets. Increased competition may have the effect of lowering our operating margins. Among other steps, the FERC has encouraged RTOs and ISOs to develop demand response bidding programs as a mechanism for responding to peak electric demand. These programs may reduce the value of our peaking assets which rely on very high prices during a relatively small number of hours to recover their costs. Similarly, the FERC is encouraging the construction of new transmission infrastructure in accordance with provisions of EPAct 2005. Although new transmission lines may increase market opportunities, they may also increase the competition in our existing markets.
While the FERC continues to promote competition, some state utility commissions have reversed course and begun to encourage the construction of generation facilities by traditional utilities to be paid for on a cost-of-service basis by retail ratepayers. Such actions have the effect of reducing sale opportunities in the competitive wholesale generating markets in which we operate.
FERC has civil penalty authority over violations of any provision of Part II of the FPA which concerns wholesale generation or transmission, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under the FPA. This penalty authority was enhanced in EPAct 2005. With this expanded enforcement authority, violations of the FPA and FERC’s regulations could potentially have more serious consequences than in the past.
Pursuant to EPAct 2005, the NERC has been certified by FERC as the Electric Reliability Organization (“ERO”) to develop mandatory and enforceable electric system reliability standards applicable throughout the United States to improve the overall reliability of the electric grid. These standards are subject to FERC review and approval. Once approved, the reliability standards may be enforced by FERC independently, or, alternatively, by the ERO and regional reliability organizations with responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation may be assessed for violations of the reliability standards.
Our utility businesses in the U.S. face significant regulation by their respective state utility commissions. The regulatory discretion is reasonably broad in both Indiana and Ohio and includes regulation as to services and facilities, the valuation of
property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of certain securities, the acquisition and sale of some public utility properties or securities and certain other matters. These businesses face the risk of unexpected or adverse regulatory action which could have a material adverse effect on our results of operations, financial condition, and cash flows. See Item 1.-Business-US SBU-U.S. Utilities and Item 1A.-Risk Factors-We have not realized the anticipated benefits and cost savings of the DPL acquisition, and DPL continues to face business and regulatory challenges for further information on the regulation faced by our U.S. utilities.
Our businesses are subject to stringent environmental laws and regulations.
Our businesses are subject to stringent environmental laws and regulations by many federal, regional, state and local authorities, international treaties and foreign governmental authorities. These laws and regulations generally concern emissions into the air, effluents into the water, use of water, wetlands preservation, remediation of contamination, waste disposal, endangered species and noise regulation, among others. Failure to comply with such laws and regulations or to obtain or comply with any necessary environmental permits pursuant to such laws and regulations could result in fines or other sanctions. Environmental laws and regulations affecting power generation and distribution are complex and have tended to become more stringent over time. Congress and other domestic and foreign governmental authorities have either considered or implemented various laws and regulations to restrict or tax certain emissions, particularly those involving air emissions and water discharges. See the various descriptions of these laws and regulations contained in Item 1.-Business of this Form 10-K. These laws and regulations have imposed, and proposed laws and regulations could impose in the future, additional costs on the operation of our power plants. We have incurred and will continue to incur significant capital and other expenditures to comply with these and other environmental laws and regulations. Changes in, or new, environmental restrictions may force the Company to incur significant expenses or expenses that may exceed our estimates. There can be no assurance that we would be able to recover all or any increased environmental costs from our customers or that our business, financial condition, including recorded asset values or results of operations, would not be materially and adversely affected by such expenditures or any changes in domestic or foreign environmental laws and regulations.
Our businesses are subject to enforcement initiatives from environmental regulatory agencies.
The EPA has pursued an enforcement initiative against coal-fired generating plants alleging wide-spread violations of the new source review and prevention of significant deterioration provisions of the CAA. The EPA has brought suit against a number of companies and has obtained settlements with many of these companies over such allegations. The allegations typically involve claims that a company made major modifications to a coal-fired generating unit without proper permit approval and without installing best available control technology. The principal, but not exclusive, focus of this EPA enforcement initiative is emissions of SO2 and NOX. In connection with this enforcement initiative, the EPA has imposed fines and required companies to install improved pollution control technologies to reduce emissions of SO2 and NOX. There can be no assurance that foreign environmental regulatory agencies in countries in which our subsidiaries operate will not pursue similar enforcement initiatives under relevant laws and regulations.
Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.
As discussed in Item 1.-Business, at the international, federal and various regional and state levels, rules are in effect and policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. In 2014, the Company’s subsidiaries operated businesses which had total CO2 emissions of approximately 78.7 million metric tonnes, approximately 41.6 million of which were emitted by businesses located in the United States (both figures ownership adjusted). The Company uses CO2 emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. For existing power generation plants, CO2 emissions data are either obtained directly from plant continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission factors. The estimated annual CO2 emissions from fossil fuel electric power generation facilities of the Company’s subsidiaries that are in construction or development and have received the necessary air permits for commercial operations are approximately 12.5 million metric tonnes (ownership adjusted). This overall estimate is based on a number of projections and assumptions which may prove to be incorrect, such as the forecasted dispatch, anticipated plant efficiency, fuel type, CO2 emissions rates and our subsidiaries’ achieving completion of such construction and development projects. However, it is certain that the projects under construction or development when completed will increase emissions of our portfolio and therefore could increase the risks associated with regulation of GHG emissions. Because there is significant uncertainty regarding these estimates, actual emissions from these projects under construction or development may vary substantially from these estimates.
The non-utility, generation subsidiaries of the Company often seek to pass on any costs arising from CO2 emissions to contract counterparties, but there can be no assurance that such subsidiaries of the Company will effectively pass such costs
onto the contract counterparties or that the cost and burden associated with any dispute over which party bears such costs would not be burdensome and costly to the relevant subsidiaries of the Company. The utility subsidiaries of the Company may seek to pass on any costs arising from CO2 emissions to customers, but there can be no assurance that such subsidiaries of the Company will effectively pass such costs to the customers, or that they will be able to fully or timely recover such costs.
Foreign, federal, state or regional regulation of GHG emissions could have a material adverse impact on the Company’s financial performance. The actual impact on the Company’s financial performance and the financial performance of the Company’s subsidiaries will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, the cost of emissions reduction equipment and the price and availability of offsets, the extent to which market based compliance options are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the ability of our subsidiaries to recover costs incurred through rate increases or otherwise. As a result of these factors, our cost of compliance could be substantial and could have a material adverse impact on our results of operations.
In January 2005, based on European Community “Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading,” the EU ETS commenced operation as the largest multi-country GHG emission trading scheme in the world. On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires all developed countries that have ratified it to substantially reduce their GHG emissions, including CO2. To date, compliance with the Kyoto Protocol and the EU ETS has not had a material adverse effect on the Company’s consolidated results of operations, financial condition and cash flows. The parties to the United Nations Framework Convention on Climate Change are continuing to work to reach an international agreement on GHG emissions to replace the Kyoto Protocol, which expired in 2012 but which is still observed by some countries. We cannot predict the impact of any such agreement, but it could have a material adverse effect on the Company’s consolidated results of operations, financial condition and cash flows.
The United States has not ratified the Kyoto Protocol. In the United States, there currently is no federal legislation imposing a mandatory GHG emission reduction programs (including for CO2) affecting the electric power generation facilities of the Company’s subsidiaries. However, the EPA has adopted regulations pertaining to GHG emissions that require new sources of GHG emissions of over 100,000 tons per year, and existing sources planning physical changes that would increase their GHG emissions by more than 75,000 tons per year, to obtain new source review permits from the EPA prior to construction or modification. Additionally, the EPA has proposed a rule establishing New Source Performance Standards for CO2 emissions for newly constructed fossil-fueled EUSGUs larger than 25 MW. The EPA has also proposed rules that would apply to modified or existing EUSGUs. Under the proposed rules, states would be judged against state-specific CO2 emissions targets beginning in 2020, with expected total U.S. power sector emissions reduction of 30% from 2005 levels by 2030. The proposed rules requires states to implement plans to meet the standards or adopt a federal plan the EPA will propose. For further discussion of the regulation of GHG emission, see Item 1.-Business-Environmental and Land-Use Regulations-United States Environmental and Land-Use Legislation and Regulations-Greenhouse Gas Emissions above.
Such regulations, and in particular regulations applying to modified or existing EUSGUs, could increase our costs directly and indirectly and have a material adverse effect on our business and/or results of operations. See Item 1.-Business of this Form 10-K for further discussion about these environmental agreements, laws and regulations.
At the state level, the RGGI, a cap-and-trade program covering CO2 emissions from electric power generation facilities in the Northeast, became effective in January 2009, and California has adopted comprehensive legislation and regulations that require mandatory GHG reductions from several industrial sectors, including the electric power generation industry. At this time, other than with regard to RGGI (further described below) and proposed Hawaii regulations relating to the collection of fees on GHG emissions, the impact of both of which we do not expect to be material, the Company cannot estimate the costs of compliance with United States federal, regional or state GHG emissions reduction legislation or initiatives, due to the fact that most of these proposals are not being actively pursued or are in the early stages of development and any final regulations or laws, if adopted, could vary drastically from current proposals; in the case of California, we anticipate no material impact due to the fact that we expect such costs will be passed through to our offtakers under the terms of existing tolling agreements.
The regional auctions of RGGI allowances needed to be acquired by power generators to comply with state programs implementing RGGI occur approximately every quarter. Our subsidiary in Maryland is our only subsidiary that was subject to RGGI in 2014. Of the approximately 41.6 million metric tonnes of CO2 emitted in the United States by our subsidiaries in 2014 (ownership adjusted), approximately 1.36 million metric tonnes were emitted by our subsidiary in Maryland. The Company estimates that the RGGI compliance costs could be approximately $3.4 million for 2015. There is a risk that our actual compliance costs under RGGI will differ from our estimates by a material amount and that our model could underestimate our costs of compliance.
In addition to government regulators, other groups such as politicians, environmentalists and other private parties have expressed increasing concern about GHG emissions. For example, certain financial institutions have expressed concern about
providing financing for facilities which would emit GHGs, which can affect our ability to obtain capital, or if we can obtain capital, to receive it on commercially viable terms. Further, rating agencies may decide to downgrade our credit ratings based on the emissions of the businesses operated by our subsidiaries or increased compliance costs which could make financing unattractive. In addition, plaintiffs have brought tort lawsuits against the Company because of its subsidiaries’ GHG emissions. Unless the United States Congress acts to preempt such suits as part of comprehensive federal legislation, additional lawsuits may be brought against the Company or its subsidiaries in the future. While the litigation mentioned has been dismissed, it is impossible to predict whether similar future lawsuits are likely to prevail or result in damages awards or other relief. Consequently, it is impossible to determine whether such lawsuits are likely to have a material adverse effect on the Company’s consolidated results of operations and financial condition.
Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect the Company’s business and operations, and any such potential impact may render it more difficult for our businesses to obtain financing. For example, extreme weather events could result in increased downtime and operation and maintenance costs at the electric power generation facilities and support facilities of the Company’s subsidiaries. Variations in weather conditions, primarily temperature and humidity also would be expected to affect the energy needs of customers. A decrease in energy consumption could decrease the revenues of the Company’s subsidiaries. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of the fossil fuel-fired electric power generation facilities of the Company’s subsidiaries. Changes in temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric generation.
In addition to potential physical risks noted by the Intergovernmental Panel on Climate Change, there could be damage to the reputation of the Company and its subsidiaries due to public perception of GHG emissions by the Company’s subsidiaries, and any such negative public perception or concerns could ultimately result in a decreased demand for electric power generation or distribution from our subsidiaries. The level of GHG emissions made by subsidiaries of the Company is not a factor in the compensation of executives of the Company.
If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on the electric power generation businesses of the Company’s subsidiaries and on the Company’s consolidated results of operations, financial condition and cash flows.
Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.
Our subsidiaries have operations in the United States and various non-United States jurisdictions. As such, we are subject to the tax laws and regulations of the United States federal, state and local governments and of many non-United States jurisdictions. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures. In addition, United States federal, state and local, as well as non-United States, tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations.
We and our affiliates are subject to material litigation and regulatory proceedings.
We and our affiliates are parties to material litigation and regulatory proceedings. See Item 3.-Legal Proceedings below. There can be no assurances that the outcome of such matters will not have a material adverse effect on our consolidated financial position.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-term leases, none of which we believe are material. With a few exceptions, our facilities, which are described in Item 1 of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project’s related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, 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 as of December 31, 2014.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) 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 FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.57 billion ($584 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 of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC has appointed an accounting expert who will issue a report on the amount of the alleged debt and the responsibility for its payment in light of the privatization. The parties will be entitled to take discovery and present arguments on the issues to be determined by the expert. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn, the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC 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.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1.6 million ($596 thousand) as of December 31, 2014, or pay an indemnification amount of approximately R$15 million ($6 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court’s decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$1.6 million ($596 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court’s decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo.
In December 2001, Gridco Ltd. ("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 shareholders agreement between Gridco, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company. In the arbitration, 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. 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. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. Gridco filed challenges of the tribunal's awards with the local Indian court. Gridco's challenge of the costs award has been dismissed by the court, but its challenge of the liability award remains pending. 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 March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, 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. The MPF requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. The lawsuit remains before the FCSP, but the FCSP has suspended the lawsuit pending a decision on MPF's interlocutory appeal. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the State of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located on the grounds of the pole factory and an indemnity payment (approximately R$6 million ($2 million)) to the State’s Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to contain and remove the contamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendant CEEE was required to proceed with the removal work. In May 2012, CEEE began the removal work in compliance with the injunction. The removal costs are estimated to be approximately R$60 million ($22 million) and the work was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The court-appointed expert final report was presented to the State Attorneys in October 2014, and in January 2015 to the defendant companies. The defendant companies have until March 2015 to present their response to the report. The case is in the evidentiary stage awaiting the conclusion of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area.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 March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserted that if it was determined that AESU was responsible for the termination of the GSA, AESU was liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011. In May 2013, the arbitral Tribunal issued a liability award in AESU's favor. YPF thereafter challenged the award in Argentine court. That challenge remains pending. Also, there are competing decisions of the Argentine and Uruguayan courts on whether the arbitration should be suspended, including an Argentine appellate court’s decision purporting to suspend the arbitration and a Uruguayan appellate court’s decision directing the arbitration to continue. Given the competing decisions, the Tribunal suspended the damages phase of the arbitration until February 2, 2015, at which time the Tribunal was to consider whether to lift the suspension. Further, the Tribunal asked the parties to remove any alleged obstacles to the progress of the arbitration. However, to date, the Tribunal has not issued an order on whether to lift the suspension. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.
In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of certain power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. The Agency sought an order from the administrative court requiring UK HPP to
pay an administrative fine of approximately KZT 120 million ($648 thousand) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($2 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police expanded the periods at issue to the entirety of 2009 for UK HPP and from January-October 2009 for Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($6 million) from UK HPP and KZT 1.3 billion ($7 million) from Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful.
In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the 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, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 50 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion by-products of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the six lawsuits filed between April 2010 and November 2011, and may also stay the October 2014 lawsuit. Presently, discovery is proceeding only in the November 2009 lawsuit on causation and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning and
Maritza's termination of the EPC Contract in March 2011. The Contractor sought approximately €240 million ($292 million) in the arbitration, plus interest and costs. Maritza rejected the Contractor’s claims and asserted counterclaims for delay of liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. The evidentiary hearing took place on November 27-December 6, 2013, and January 6-17, 2014. Closing arguments were heard on May 21-22, 2014. In December 2014, the parties settled the dispute.
On February 11, 2011, Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($372 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction of the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernardo do Campo initiated a Civil Proceeding to review the compliance by Eletropaulo with the terms of any possible settlement. Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. Eletropaulo was informed by the Park Administrator that the area where the recovery project was to be located was no longer available. The Park Administrator subsequently approved a new area for the recovery project. Eletropaulo is currently awaiting the draft of the agreement by the environmental agency, and expects to proceed with the recovery project after reaching agreement with the environmental agency.
In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$2.95 billion ($1 billion) as estimated by Eletropaulo. Eletropaulo has appealed to the Second Instance Administrative Court. No tax is due while the appeal is pending. Eletropaulo believes it has meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the ground that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative Court determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest and penalties totaling approximately R$864 million ($322 million) as estimated by AES Tietê. AES Tietê appealed to the Second Instance Administrative Court (“SAIC”). In January 2015, the SAIC issued a decision in AES Tietê’s favor, finding that AES Tietê was not liable for unpaid taxes. The Tax Authority may appeal. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NC”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas ("Camara") perform an audit of the allegations in the criminal complaint. The audit is ongoing and the Camara has not issued its report to date. Further, in August 2012, Coastal and NC initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NC have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NC also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NC further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims and challenged the jurisdiction of the arbitral Tribunal. The Tribunal has established the procedural schedule for the arbitration, but has not yet scheduled dates for the final evidentiary hearing. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assurances that they will be successful in their efforts.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Stock Repurchase Program
In July 2014, the Company’s Board of Directors approved an increase of $140 million to the stock repurchase program (the “Program”) under which the Company can repurchase AES common stock. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and can be modified or terminated by the Board of Directors at any time. During the year ended December 31, 2014, the Company repurchased 21,900,246 shares of its common stock under the Program at a total cost of $308 million. At December 31, 2014, the cumulative repurchases under the Program totaled 105,912,477 shares at a total cost of $1.3 billion, at an average price per share of $12.37 (including a nominal amount of commissions).
The following table presents information regarding repurchases made by The AES Corporation of its common stock in the fourth quarter of 2014.
Market Information
Our common stock is currently traded on the NYSE under the symbol “AES.” The closing price of our common stock as reported by the NYSE on February 18, 2015, was $11.83 per share. The Company repurchased 21,900,246, 25,297,042, and 24,790,384 shares of its common stock in 2014, 2013 and 2012, respectively. The following tables set forth the high and low stock prices and cash dividends declared for the periods indicated:
Dividends
The Company commenced a quarterly cash dividend of $0.04 per share beginning in the fourth quarter of 2012, which was increased to $0.05 per share beginning in the fourth quarter of 2013. During the fourth quarter of 2014, the Board of Directors voted to increase the quarterly dividend to $0.10 per share, beginning in the first quarter of 2015. There can be no assurance that the AES Board will declare the dividend or, if declared, the amount of any dividend. Our ability to pay dividends will also depend on receipt of dividends from our various subsidiaries across our portfolio.
Under the terms of our senior secured credit facility, which we entered into with a commercial bank syndicate, we have limitations on our ability to pay cash dividends and/or repurchase stock. Our project subsidiaries’ ability to declare and pay cash dividends to us is also subject to certain limitations contained in the project loans, governmental provisions and other agreements to which our project subsidiaries are subject. See the information contained under Item 12.-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters-Securities Authorized for Issuance under Equity Compensation Plans of this Form 10-K.
Holders
As of February 18, 2015, there were approximately 4,980 record holders of our common stock.
Performance Graph
THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE
Source: Bloomberg
We have selected the Standard and Poor’s (“S&P”) 500 Utilities Index as our peer group index. The S&P 500 Utilities Index is a published sector index comprising the 31 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 2009 in AES Common Stock, the S&P 500 Index and the S&P 500 Utilities Index. The information included under the heading Performance Graph shall not be considered “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data as of the dates and for the periods indicated. You should read this data together with Item 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Key Topics in the Management Discussion and Analysis
Our discussion covers the following:
•
Overview of 2014 Results and Strategic Performance
•
Review of Consolidated Results of Operations
•
SBU Analysis and Non-GAAP Measures
•
Key Trends and Uncertainties
•
Capital Resources and Liquidity
Overview of 2014 Results and Strategic Performance
Management’s Strategic Priorities
Management is focused on the following priorities:
•
Reducing complexity: By exiting businesses and markets where we do not have a competitive advantage, we have simplified our portfolio and reduced risk.
•
Leveraging our platforms: Focusing our growth on platform expansions, including adjacencies, in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns.
•
Performance excellence: We strive to be the low-cost manager of a portfolio of assets and to derive synergies and scale from our businesses.
•
Expanding access to capital: By building strategic partnerships at the project and business level. Through these partnerships, we aim to optimize our risk-adjusted returns in our existing businesses and growth projects. By selling down portions of certain businesses, we can adjust our global exposure to commodity, fuel, country and other macroeconomic risks. Partial sell-downs of our assets can serve to highlight the value of businesses in our portfolio.
•
Allocating capital in a disciplined manner: Our top priority is to maximize risk-adjusted returns to our shareholders, which we achieve by investing our discretionary cash and recycling the capital we receive from asset sales and strategic partnerships.
In 2014, we made significant progress on our strategy and continued to position our company for the future. We also met our financial guidance, despite sustained poor hydrological conditions in Latin America, particularly in Brazil and Panama, where rainfall has been at some of the lowest levels recorded in many decades. Our key achievements in 2014 were:
•
Adjusted EPS of $1.30 and Proportional Free Cash Flow (FCF) of $891 million
•
Diluted EPS from continuing operations of $1.09 and net cash provided by operating activities of $1.8 billion
•
Returned 76% of discretionary cash to shareholders
•
Increased our quarterly dividend by 100%, to $0.10 per share, beginning in the first quarter of 2015
•
Invested $916 million in our balance sheet, by repurchasing shares and prepaying and refinancing debt
•
Closed ten transactions for $1.8 billion in equity proceeds from asset sales
•
Brought in four strategic partners to invest $1.9 billion in our subsidiaries
•
Achieved goal of reducing global G&A expenses by $200 million one year early
•
Capitalized on our existing footprint - broke ground on six new construction projects, totaling 2,226 MW, expected to come on-line from 2015 through 2018
•
Awarded long-term PPAs by Southern California Edison, for 1,284 MW of combined cycle gas-fired generation and 100 MW of battery-based energy storage
2014 Strategic Performance
Earnings Per Share Results in 2014
_____________________________
(1)
See reconciliation and definition under Non-GAAP Measures.
Diluted earnings per share from continuing operations increased $0.71, to $1.09, principally due to lower goodwill impairment expense and current year gains on the sale of investments. Additionally, higher interest income, foreign currency transaction gains, and lower general and administrative expenses added to the increase. These increases were partially offset by lower operating margin, higher income tax expense, and higher losses on debt extinguishments.
Adjusted EPS increased by 1% to $1.30 primarily due to lower Parent Company interest expense, lower general and administrative expenses, and lower share count, partially offset by lower contribution from the Asia SBU and increased tax expense.
Capital Management and Allocation
We continue to focus on improving cash generation and optimizing the use of our parent discretionary cash. During 2014, we generated $1.8 billion of cash flow from operating activities and closed multiple asset sales. In terms of uses, we deployed our discretionary cash to pay quarterly dividends of $0.05 per share, allocated $308 million to repurchase 22 million shares (see Note 16-Equity in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information), allocated $608 million to reduce recourse debt and extend near-term maturities at the Parent Company, and invested $327 million in our subsidiaries, largely for platform expansions. The largest investments in platform expansions in 2014 were related to environmental upgrades at IPL, where we expect to receive full recovery for qualifying costs, including a return on equity, and our expansion project at our Amman East facility in Jordan.
Reducing Complexity
In 2014, we announced or closed asset sale transactions representing $1.8 billion in equity proceeds to AES. With these transactions, we exited operations in Cameroon, Nigeria and Turkey. These asset sales are part of our strategy to maximize shareholder value by exiting markets where we do not have a compelling competitive advantage and reinvesting capital into expanding our platforms.
In 2014, we added 247 MW of new capacity, through one platform expansion project: IPP4 in Jordan. Our planned future capacity growth will come from a combination of projects currently under construction and development. We have 7,141 MW of new capacity under construction and expected to come on-line through 2018.
Safe, Reliable and Sustainable Operations
Our 2014 operating performance for the year was driven by the strategic management of our assets and cost reductions across our portfolio, but we also faced dry hydrological conditions across many markets in Latin America and reliability challenges at two of our generation assets in the Philippines and the US and utilities in Brazil.
We continue to focus on safety as our top priority. Our safety performance improved in 2014, as we lowered our lost-time incident case rates for both employees and operational contractors.
Generation in GWh is down 4% compared to 2013, mainly driven by dry hydrological conditions in Brazil and Panama, as well as higher unplanned outages at our generation plants in Ohio and Philippines. The dry conditions were partially offset by new capacity in Chile.
Compared to 2013, KPI performance declined in our generation metrics. Our Commercial Availability and EFOF performance deteriorated, largely driven by our unplanned outages at our generation plants in Ohio and the Philippines as discussed above. Most of these events have been resolved and mitigation plans have been implemented. Additionally, one strategic initiative focusing on coal blending can reduce the efficiency of certain generating units, which unfavorably affects our heat rate; however, it is offset by the financial benefits from utilizing lower-cost coal.
Our utility portfolio performance also declined mainly driven by severe weather-related impacts in our Brazil businesses which increased our SAIDI and SAIFI. However, we saw improvements in our non-technical losses performance mainly through strategic initiatives in our Brazil businesses on identifying and preventing fraudulent customers.
Our key performance indicators for the years ended December 31, 2014 and 2013 are as follows:
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Definitions:
•
Lost-Time Incident Case Rate: Number of lost-time cases per number of full-time employees or contractors.
•
Commercial Availability: Actual variable margin, as a percentage of potential variable margin if the unit had been available at full capacity during outages.
•
Equivalent Forced Outage Factor: The percentage of the time that a plant is not capable of producing energy, due to unplanned operational reductions in production.
•
Heat Rate: The amount of energy used by an electrical generator or power plant to generate one kilowatt-hour (kWh).
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System Average Interruption Duration Index: The total hours of interruption the average customer experiences annually.
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System Average Interruption Frequency Index: The average number of interruptions the average customer experiences annually.
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Non-Technical Losses: Delivered energy that was not billed due to measurement error, theft or other reasons.
Review of Consolidated Results of Operations
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NM - Not meaningful
Components of Revenue, Cost of Sales and Operating Margin-Revenue includes revenue earned from the sale of energy from our utilities and the production of energy from our generation plants, which are classified as regulated and non-regulated on the Consolidated Statements of Operations, respectively. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.
Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, O&M costs, depreciation and amortization expense, bad debt expense and recoveries, general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.
Operating margin is defined as revenue less cost of sales.
Year ended December 31, 2014:
Revenue increased $1.3 billion, or 8%, to $17.1 billion in 2014 compared with $15.9 billion in 2013. The key operating drivers of the change at each of the SBUs are as follows:
•
US - Overall favorable variance of $196 million driven by regulatory retail rate increases at DPL in Ohio as well as higher rates, primarily pass-through, at IPL in Indiana, partially offset by lower volume at DPL primarily due to customer switching.
•
Andes - Overall favorable impact of $3 million driven by Chivor in Colombia due to higher spot and contract rates, somewhat offset by unfavorable foreign exchange rates, and Gener in Chile as a result of higher volume, partially offset by lower rates. Offsetting these results, Argentina decreased due to unfavorable foreign exchange rates.
•
Brazil - Overall favorable impact of $994 million driven by higher volumes and higher tariffs, primarily pass-through costs, at Eletropaulo and Sul. Tietê also increased due to higher rates. Unfavorable foreign exchange partially offset these results.
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MCAC - Overall unfavorable impact of $31 million driven by the Dominican Republic due to lower third party gas sales, partially offset by higher PPA rates. El Salvador also decreased as a result of an unfavorable adjustment to unbilled revenue and lower pass-through costs. Offsetting these results, Puerto Rico and Panama increased due to higher volume and rates.
•
Europe - Overall favorable impact of $92 million driven by the start of operations at Jordan IPP4 which commenced operations in July 2014 and Ballylumford in the U.K. due to higher volume and favorable foreign exchange rates, somewhat offset by lower rates. These results were partially offset by Kilroot in the U.K. primarily due to lower volume.
•
Asia - Overall favorable impact of $8 million driven by higher pass-through fuel costs resulting from higher generation at Kelanitissa in Sri Lanka, partially offset by decrease in the Philippines primarily due to lower rates, somewhat offset by higher volume.
Operating margin decreased $159 million, or 5%, to $3.1 billion in 2014 compared with $3.2 billion in 2013. The key operating drivers of the change at each of the SBUs are as follows:
•
US - Overall favorable impact of $31 million driven by favorable results at US Generation including contributions from a platform expansion project at Tait energy storage project, combined with higher availability at Hawaii and increased market prices at Laurel Mountain. US Utilities benefited with favorable results at IPL in Indiana driven by higher wholesale and retail margin as well as lower pension costs, were largely offset by lower results at DPL in Ohio. DPL was driven by outages and lower gas availability in the first half of 2014 resulting in higher purchased power and related costs to supply higher demand from cold weather, partially offset by improvements in Q3 2014 from increased retail rates, lower fuel costs and higher capacity prices. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.
•
Andes - Overall favorable impact of $54 million driven by Chivor in Colombia due to higher generation, higher spot and contract prices, as well as ancillary services. Increases in Argentina were offset by lower results at Gener in Chile. Argentina increased due to the impact of Resolution 529, higher generation and availability, partially offset by higher fixed costs while Gener in Chile decreased due to lower contract and spot prices and lower availability, partially offset by full impact of new operations at Ventanas IV in 2014 and lower fixed costs.
•
Brazil - Overall unfavorable impact of $129 million driven by unfavorable foreign exchange rates and Tietê due to lower water inflows which led to lower generation and an increase in energy purchases at higher prices, partially offset by higher spot sales in first half of 2014 due to lower contracted volumes of energy sold. In addition, Uruguaiana decreased due to a non-recurring extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013. These results were partially offset by Eletropaulo driven by a non-recurring 2013 charge related to the recognition of a regulatory liability related to potential customer refunds as well as higher tariffs and volume. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.
•
MCAC - Overall unfavorable impact of $2 million driven by El Salvador due to an unfavorable adjustment to unbilled revenue, higher energy losses and lower demand. These results were largely offset by the Dominican Republic mainly related to higher spot sales and higher availability, partially offset by lower gas sales to third parties, lower frequency regulation, and lower PPA results.
•
Europe - Overall unfavorable impact of $12 million driven by Kilroot in the U.K. and Maritza in Bulgaria due to lower volume and higher outages, partially offset by higher rates. These results were partially offset by the new operations at Jordan IPP4 as discussed above, and Kazakhstan due to higher generation volume and rates, partially offset by unfavorable foreign exchange rates.
•
Asia - Overall unfavorable impact of $93 million driven by Masinloc in the Philippines, due to lower plant availability and the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, and lower spot rates, partially offset by higher contract demand. Kelanitissa also decreased due to a reduction in rates according to the PPA.
Year Ended December 31, 2013
Revenue decreased $1.3 billion, or 7%, to $15.9 billion in 2013 compared with $17.2 billion in 2012. The key operating drivers of the change at each of the SBUs are as follows:
•
US - Overall unfavorable impact of $106 million driven by the early termination of the PPA at Beaver Valley in Pennsylvania in early 2013, customer switching as well as lower capacity rates at DPL in Ohio, and the short-term restart in 2012 of two Huntington Beach generating units at Southland in California, partially offset by higher wholesale volume and prices at IPL in Indiana.
•
Andes - Overall unfavorable impact of $381 million driven by unfavorable foreign exchange rates of $128 million, lower prices from the impact of Resolution 95 in Argentina, and lower contract and spot prices at Gener in Chile, partially offset by higher spot prices at Chivor in Colombia as a result of dry hydrology.
•
Brazil - Overall unfavorable impact of $773 million driven by unfavorable foreign exchange rates of $631 million, lower demand as well as lower pass-through costs and the tariff reset implemented in April 2013 at Sul, and a decrease at Eletropaulo related to the recognition of a regulatory liability for customer refunds (See Item 1.-Business-Brazil SBU- Eletropaulo Regulatory Asset Base Update) somewhat offset by higher tariffs. Negative results above partially offset by higher prices and sales at Tietê and the temporary restart of operations during February and March of 2013 at Uruguaiana.
•
MCAC - Overall favorable impact of $140 million driven by higher spot prices as well as higher spot and gas sales to third parties in the Dominican Republic, higher prices in Mexico and Puerto Rico, partially offset by lower generation net of higher prices due to lower hydrology in Panama.
•
Europe - Overall favorable impact of $3 million driven by higher energy prices at Kilroot in the UK, pass-through costs at Maritza in Bulgaria and Jordan, as well as higher dispatch and fewer outages at Ballylumford in the UK, partially offset by lower capacity prices. The favorable results above were largely offset by the sale of 80% of our ownership in Cartagena in Spain in February 2012 and a non-recurring favorable arbitration settlement in 2012 prior to final sale of remaining AES interest in April 2013.
•
Asia - Overall unfavorable impact of $183 million due to higher contract levels at lower prices to reduce spot exposure, the reversal of a contingency and unrealized derivative gains in 2012 at Masinloc in the Philippines as well as lower generation at Kelanitissa in Sri Lanka as a result of higher hydrology.
Operating margin decreased $336 million, or 9%, to $3.2 billion in 2013 compared with $3.6 billion in 2012. The key operating drivers of the change at each of the SBUs are as follows:
•
US - Overall unfavorable impact of $43 million driven by the short-term restart of two Huntington Beach units at Southland in 2012, higher outages and related fixed costs at Hawaii, and higher maintenance costs at IPL in Indiana. The negative drivers above were partially offset by higher contributions for US Wind businesses and DPL with lower amortization expense largely offset by higher customer switching.
•
Andes - Largely unfavorable impact of $47 million driven by Chivor due to lower generation, somewhat offset by higher spot prices due to dry hydrology. Chile also decreased due to lower generation, higher spot purchases, and lower contract prices, offset by the commencement of operations of Ventanas IV in March 2013. These negative drivers were partially offset by an increase in Argentina driven by lower outages and higher volumes, somewhat offset by unfavorable foreign currency translation of $18 million and lower rates.
•
Brazil - Overall unfavorable impact of $98 million driven by an unfavorable foreign exchange impact of $84 million, lower tariffs and demand at Sul, as well as lower volumes and higher energy purchases due to low hydrology at Tietê, partially offset by the favorable reversal of a liability and the temporary restart of operations at Uruguaiana and higher tariffs and lower fixed costs at Eletropaulo, somewhat offset by recognition of a regulatory liability as discussed above.
•
MCAC - Overall unfavorable impact of $17 million driven by Panama due to dry hydrological conditions, which resulted in lower generation and higher energy purchases at higher prices, somewhat offset by favorable net settlements. Negative drivers above were partially offset by the Dominican Republic with higher spot sales, higher
international gas prices and volume of gas sales to third parties and higher availability in El Salvador due to the tariff increase at the beginning of 2013.
•
Europe - Overall unfavorable impact of $89 million driven by Cartagena due to a non-recurring, favorable arbitration settlement in 2012 and the two-stage sale of the business as discussed above as well as Ballylumford due to lower capacity payments, somewhat offset by fewer outages. The negative results above were partially offset by favorable dark spreads from higher energy prices and lower coal costs at Kilroot and fewer outages and lower fixed costs at Maritza in Bulgaria.
•
Asia - Overall unfavorable impact of $67 million driven by higher contracted volume at lower prices as discussed above as well as reversal of a contingency of $16 million and an unrealized derivative gain in 2012 at Masinloc.
General and administrative expenses
General and administrative expenses includes expenses related to corporate staff functions and/or initiatives, executive management, finance, legal, human resources and information systems, as well as global development costs.
General and administrative expenses decreased $33 million, or 15%, to $187 million in 2014 from 2013 primarily due to lower employee-related costs and business development costs.
General and administrative expenses decreased $54 million, or 20%, to $220 million in 2013 from 2012 primarily due to Company restructuring efforts, resulting in a decrease in employee related costs, professional fees and business development costs.
Interest expense
Interest expense decreased $11 million, or 1%, to $1.5 billion in 2014 from 2013. The decrease was primarily attributable to lower interest expense of $53 million at the Parent Company due to a reduction in debt principal, and a $48 million reversal of contingent interest accruals associated with disputed purchased energy obligations at Sul for which it was determined, based on developments during the second quarter of 2014, that the likelihood of an unfavorable outcome for the payment of interest on the disputed obligation was no longer probable. These decreases were partially offset by income of $34 million in the prior year resulting from the ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges at Puerto Rico, and higher interest expense of $24 million at Gener due to an increase in debt principal.
Interest expense decreased $62 million, or 4%, to $1.5 billion in 2013 from 2012. This decrease was primarily due to reduced debt principal as well as the prior year prepayment of an interest rate cash flow hedge that resulted in a reclassification of deferred losses from other comprehensive income to earnings at the Parent Company, favorable foreign currency translation and lower interest rates in Brazil, as well as income resulting from ineffectiveness on interest rate swaps in Puerto Rico that continue to qualify for hedge accounting. These decreases were partially offset by a monetary correction on the adjustment to the regulatory liability related to the asset base at Eletropaulo as a result of a ruling by the regulator in December 2013.
Interest income
Interest income increased $90 million, or 33%, to $365 million in 2014 from 2013. The increase was primarily due to interest income of $59 million recognized on FONINVEMEM III receivables in Argentina which satisfied the criteria for revenue recognition in the fourth quarter and $23 million in higher interest rates from an increase in regulatory assets at Eletropaulo. See Note 7-Financing Receivables included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Interest income decreased $73 million, or 21%, to $275 million in 2013 from 2012. The decrease was primarily in Brazil, due to lower interest-bearing assets, lower investment balances, unfavorable foreign currency translation, and lower interest rates. The decrease was partially offset by interest income related to FONINVEMEM III receivables in Argentina which satisfied the criteria for revenue recognition during 2013.
Loss on extinguishment of debt
Loss on extinguishment of debt was $261 million for the year ended December 31, 2014. This loss was primarily related to $193 million, $31 million, and $20 million in early extinguishment of debt at the Parent Company, DPL, and Gener, respectively. See Note 12-Debt included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Loss on extinguishment of debt was $229 million and $8 million for the years ended December 31, 2013 and 2012. The loss in 2013 was primarily related to the loss on the early retirement of recourse debt at the Parent Company and the loss on the early extinguishment of debt at Masinloc. See Note 12-Debt included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information. The loss in 2012 was primarily related to a early retirement of debt at the Parent Company and at Eletropaulo.
Other income and expense
See discussion of the components of other income and expense in Note 20-Other Income and Expense included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Gain on sale of investments
Gain on sale of investments for the year ended December 31, 2014 was $358 million, which is primarily related to the sale of 45% of our investment in Masin-AES Pte Ltd. and 100% of our interest in UK Wind. See Note 16-Equity of this form 10-K for further information.
Gain on sale of investments for the year ended December 31, 2013 was $26 million, which was primarily related to the sale of our remaining 20% interest in Cartagena as well as the sale of our 10% equity interest in Trinidad Generation Unlimited. See Note 24-Dispositions included in Item 8.-Financial Statements and Supplemental Data of this Form 10-K for further information.
Gain on sale of investments for the year ended December 31, 2012 was $219 million, which was primarily related to the sale of 80% of our interest in Cartagena, as well as the sale of certain investments in China.
Goodwill impairment
The Company recognized goodwill impairment expense of $164 million, $372 million, and $1.8 billion for the years ended December 31, 2014, 2013, and 2012. See Note 10-Goodwill and Other Intangible Assets included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Asset impairment expense
The Company recognized asset impairment expense of $91 million, $95 million and $73 million, respectively, for the years ended December 31, 2014, 2013 and 2012. See Note 21-Asset Impairment Expense included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) were as follows:
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(1) Includes gains (losses) of $172 million, $60 million and $(160) million on foreign currency derivative contracts for the years ended December 31, 2014, 2013 and 2012, respectively.
The Company recognized net foreign currency transaction gains of $11 million for the year ended December 31, 2014 primarily due to gains of:
•
$66 million in Argentina, due to the favorable impact from foreign currency derivatives related to government receivables, partially offset by losses from the devaluation of the Argentine Peso by 31% associated with U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) primarily associated with cash and accounts receivable balances in local currency, and the purchase of Argentine sovereign bonds;
•
$17 million in Colombia, primarily due to a 23% depreciation of the Colombian Peso, positively impacting Chivor (a U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos, primarily income tax payable and accounts payable;
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$12 million in the United Kingdom, primarily due to a 6% depreciation of the Pound Sterling, resulting in gains at Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable denominated in Pound Sterling, and gains related to foreign currency derivatives; and
•
$11 million in the Philippines, primarily due to amortization of frozen embedded derivatives and a 4% appreciation of the Philippine Peso against the U.S. Dollar, resulting in a revaluation of cash accounts, customer receivables, and deferred tax asset.
These gains were partially offset by losses of:
•
$34 million at The AES Corporation primarily due to decreases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year, partially offset by gains related to foreign currency option purchases;
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$30 million in Chile primarily due to a 16% devaluation of the Chilean Peso, resulting in a $39 million loss at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, primarily cash, accounts receivable and VAT receivables, partially offset by income of $9 million on foreign currency derivatives; and
•
$14 million in Mexico, primarily due to a 13% devaluation of the Mexican Peso, resulting in a loss at TEGTEP and Merida (U.S. Dollar functional currency subsidiaries) from working capital denominated in Pesos (primarily cash, recoverable tax, and VAT).
The Company recognized foreign currency transaction losses of $22 million for the year ended December 31, 2013 primarily due to losses of:
•
$20 million in Chile, primarily due to a 9% weakening of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Pesos, mainly cash, accounts receivables and tax receivables, partially offset by gains related to foreign currency derivatives;
•
$12 million in Brazil, primarily due to a 15% weakening of the Brazilian Real resulting in losses mainly associated with U.S. Dollar denominated liabilities; and
•
$10 million in the Philippines (a U.S. Dollar functional currency subsidiary beginning in 2013), primarily due to the 8% weakening of the Philippine Peso, resulting in revaluation of cash accounts, customer receivables and deferred tax asset.
The Company recognized foreign currency transaction losses of $170 million for the year ended December 31, 2012 primarily due to losses of:
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$159 million in the Philippines, primarily due to unrealized foreign exchange losses on embedded derivatives as a result of the forecasted strengthening of the Philippine Peso, partially offset by gains from the 7% appreciation of the Philippine Peso on U.S. Dollar denominated debt at Masinloc, which had been a Philippine Peso functional currency subsidiary; and
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$16 million in Brazil, primarily due to a 9% devaluation of the Brazilian Real resulting in losses mainly associated with U.S. Dollar denominated liabilities.
Other non-operating expense
Total other non-operating expense was $128 million, $129 million and $50 million for the years ended December 31, 2014, 2013 and 2012. The amounts in 2014 consist of other-than-temporary impairment losses of $86 million and $42 million at Entek and Silver Ridge, respectively. See Note 9-Other Non-Operating Expense included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Income tax expense
Income tax expense increased $76 million, or 22%, to $419 million in 2014. The Company’s effective tax rates were 27% and 33% for the years ended December 31, 2014 and 2013, respectively.
The net decrease in the 2014 effective tax rate was due, in part, to the 2014 sale of approximately 45% of the Company's interest in Masin AES Pte Ltd., which owns the Company's business interests in the Philippines, and the 2014 sale of the Company's interests in four U.K. wind projects. Neither of these transactions gave rise to income tax expense. Further, the 2014 effective tax rate benefited from the release of valuation allowance against U.S. capital loss carryforwards and a change in tax status at a subsidiary operating in the Dominican Republic. Offsetting these items is the unfavorable impact of Chilean income tax law reform enacted in the third quarter of 2014. See Note 16-Equity for additional information regarding the sale of approximately 45% of the Company's interest in Masin - AES Pte Ltd. See Note 24-Dispositions for additional information regarding the sale of the Company's interests in four U.K wind projects. See Note 22-Income Taxes for additional information regarding the Chilean tax law reform.
Income tax expense decreased $342 million, or 50%, to $343 million in 2013. The Company’s effective tax rates were 33% and 298% for the years ended December 31, 2013 and 2012, respectively.
The net decrease in the 2013 effective tax rate was principally due to a 2012 nondeductible impairment of goodwill at our U.S. utility, DPL, and in part to the net favorable resolution of various uncertain tax positions in 2013. See Note 10-Goodwill and Other Intangible Assets for additional information regarding goodwill impairment.
Our effective tax rate reflects the tax effect of significant operations outside the United States, which are generally taxed at rates lower than the U.S. statutory rate of 35 percent. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate.
We recognized tax expense of $419 million for the year ended December 31, 2014, while our cash payments for income taxes, net of refunds, totaled $480 million. The difference resulted primarily from income tax benefit on current year U.S. losses.
The Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments regarding employment and capital investment. One such benefit related to our operations in the Philippines expired in the 4th quarter of 2014. Accordingly, the Company’s effective tax rate and cash tax payments may increase in future periods. See Note 22-Income Taxes for additional information regarding these reduced rates.
Net equity in earnings of affiliates
Net equity in earnings of affiliates decreased $6 million, or 24%, to $19 million in 2014 from $25 million in 2013. The decrease was primarily a result of an asset impairment charge at Elsta due to long lived assets that were determined to not be recoverable of which our share was $41 million. These items were partially offset by a $22 million lower loss recognized at Entek on an embedded foreign currency derivative and a $19 million increase as a result of the sale of equity interests in Silver Ridge Power, LLC ("SRP") See Note 8-Investments in and Advances to Affiliates included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Net equity in earnings of affiliates decreased $10 million to $25 million in 2013 from $35 million in 2012. The decrease was primarily related to the sale of Yangcheng in China in the third quarter of 2012 as well as higher losses at Entek in Turkey resulting from a loss on an embedded foreign currency derivative, partially offset by increased earnings at Guacolda due to higher energy sales as a result of lower purchase costs.
Income from continuing operations attributable to noncontrolling interests
Income from continuing operations attributable to noncontrolling interests decreased $59 million, or 13%, to $387 million in 2014. The decrease was primarily due to decreased operating margin at Tietê related to lower hydrology and higher prices of energy purchased in the spot market, decreased operating margin at Uruguaiana due to a favorable arbitration settlement in 2013 for $53 million, and decreased operating margin at Panama related to lower hydrology. This was partially offset by increased operating margin at Eletropaulo due to the 2013 recognition of a $269 million regulatory liability related to customer refunds. For details on regulatory liabilities, see Note 11-Regulatory Assets and Liabilities.
Income from continuing operations attributable to noncontrolling interests decreased $94 million, or 17%, from $540 million to $446 million in 2013. This was primarily due to lower operating income at Tietê and Panama related to lower hydrology, the recognition of a regulatory liability related to customer refunds at Eletropaulo, and a reduction in income at Cartagena which was deconsolidated in February 2012 as a result of the sale of 80% of our interest.
Discontinued operations
Total discontinued operations was a net loss of $29 million, a net loss of $179 million, and a net income of $63 million for the years ended December 31, 2014, 2013 and 2012, respectively. See Note 23-Discontinued Operations and Held-for-Sale Businesses included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Net income attributable to The AES Corporation
Net income attributable to The AES Corporation increased $655 million to $769 million in 2014 compared to net income of $114 million in 2013. The key drivers of the increase included:
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the gain on sale of 45% of our investment in Masin - AES Pte Ltd. as well as the gain on sale of the Company's entire interest in the UK Wind projects;
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lower goodwill impairment expense recognized in 2014 compared to 2013;
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higher interest income;
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lower general and administrative expense;
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gain on foreign currency transactions;
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increase in income from operations of discontinued businesses; and
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lower loss from disposal and impairments of discontinued businesses.
These increases were partially offset by:
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lower operating margin;
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increase in income tax expense; and
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higher losses from debt extinguishments.
Net income attributable to The AES Corporation was $114 million in 2013, which is an increase of $1.03 billion compared to net loss of $912 million in 2012. The key drivers included:
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lower goodwill impairment expense;
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lower income tax expense;
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lower foreign currency losses;
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lower interest expense, primarily at the Parent Company, due to a reduction in debt principal as well as the prior year prepayment of an interest rate cash flow hedge that resulted in a reclassification of deferred losses from other comprehensive income to earnings; and
•
lower general and administrative expense.
These increases were partially offset by:
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lower operating margin as described above;
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the loss on the early extinguishment of debt at the Parent Company and at Masinloc;
•
lower gain on sale of investments recorded in 2013 on the sale of our remaining 20% interest in Cartagena as well as our 10% equity interest in Trinidad compared to the prior year gain recorded from the sale of 80% of our interest in Cartagena in the first quarter of 2012;
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an increase in losses from the disposal and impairment of the discontinued businesses;
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other non-operating expense associated with an impairment at our equity method investment at Elsta in the Netherlands.
Non-GAAP Measures
Adjusted Operating Margin, Adjusted PTC, Adjusted EPS, and Proportional Free Cash Flow are non-GAAP supplemental measures that are used by management and external users of our consolidated financial statements such as investors, industry analysts and lenders.
Adjusted Operating Margin
Operating margin is defined as revenue less cost of sales. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business, such as:
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Electricity and fuel purchases,
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Operations and maintenance costs,
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Depreciation and amortization expense,
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Bad debt expense and recoveries,
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General administrative and support costs at the businesses, and
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Gains or losses on derivatives associated with the purchase of electricity or fuel.
We define Adjusted Operating Margin as operating margin, adjusted for the impact of noncontrolling interests, excluding unrealized gains or losses related to derivative transactions.
The GAAP measure most comparable to Adjusted Operating Margin is operating margin. We believe that Adjusted Operating Margin better reflects the underlying business performance of the Company. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly owned by the Company, as well as the variability due to unrealized derivatives gains or losses. Adjusted Operating Margin should not be construed as an alternative to operating margin, which is determined in accordance with GAAP.
Adjusted PTC and Adjusted EPS
We define Adjusted PTC as pretax income from continuing operations attributable to AES excluding gains or losses of
the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency
gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and
(e) costs due to the early retirement of debt. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis,
adjusted for the aforementioned items.
Adjusted PTC reflects the impact of noncontrolling interests and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in operating margin, Adjusted PTC includes the other components of our income statement, such as:
•
General and administrative expense in the corporate segment, as well as business development costs;
•
Interest expense and interest income;
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Other expense and other income;
•
Realized foreign currency transaction gains and losses; and
•
Net equity in earnings of affiliates.
We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt.
The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to AES. The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. We believe that Adjusted PTC and Adjusted EPS better reflect the underlying business performance of the Company and are considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests or retire debt, which affect results in a given period or periods. In addition, for Adjusted PTC, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Adjusted PTC and Adjusted EPS should not be construed as alternatives to income from continuing operations attributable to AES and diluted earnings per share from continuing operations, which are determined in accordance with GAAP.
Proportional Free Cash Flow
Refer to Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Proportional Free Cash Flow (A non-GAAP Measure) for the discussion and reconciliation of Proportional Free Cash Flow to its nearest GAAP measure.
Reconciliations of Non-GAAP Measures
Adjusted Operating Margin
Adjusted PTC
(1)
Adjusted pretax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees and the write-off of intercompany balances.
Adjusted EPS
_____________________________
(1)
Unrealized derivative (gains) losses were net of income tax per share of $(0.07), $(0.02) and $0.04 in 2014, 2013, and 2012, respectively.
(2)
Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.02, $0.02 and $0.00 in 2014, 2013, and 2012, respectively.
(3)
Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($283 million, or $0.39 per share, net of income tax per share of $0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per share of $0.00), the loss from the sale of Ebute of $6 million ($6 million, or $0.01 per share, net of income tax per share of $0.00), the loss from the liquidation of AgCert International of $1 million (net benefit of $18 million, or $0.03 per share, including income tax per share of $0.03), the tax benefit of $24 million ($0.03 per share) related to the Silver Ridge Power transaction, the tax benefit of $18 million ($0.02 per share) associated with the agreement executed in December 2014 to sell a noncontrolling interest in IPALCO, and the tax benefit of $7 million ($0.01 per share) associated with the sale of a noncontrolling interest in our Dominican Republic businesses.
(4)
Amount primarily relates to the gain from the sale of the remaining 20% of our interest in Cartagena for $20 million ($15 million, or $0.02 per share, net of income tax per share of $0.01) as well as the gain from the sale of Trinidad for $3 million ($4 million, or $0.01 per share, net of income tax per share of $0.00).
(5)
Amount primarily relates to the gains from the sale of 80% of our interest in Cartagena for $178 million ($109 million, or $0.14 per share, net of income tax per share of $0.09) and equity method investments in China of $24 million ($25 million, or $0.03 per share, including an income tax credit of $1 million, or income tax per share of $0.00).
(6)
Amount primarily relates to the goodwill impairments at DPLER of $136 million ($136 million, or $0.19 per share, net of income tax per share of $0.00), and at Buffalo Gap of $28 million ($28 million, or $0.04 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($64 million, or $0.09 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.00), at DPL of $12 million ($7 million, or $0.01 per share, net of income tax per share of $0.01), at Newfield of $12 million ($6 million, or $0.01 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00), and at Elsta of $41 million ($31 million, or $0.04 per share, net of income tax per share of $0.01), as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($27 million, or $0.04 per share, net of income tax per share of $0.02), and at Entek of $86 million ($86 million, or $0.12 per share, net of income tax per share of $0.00).
(7)
Amount primarily relates to the goodwill impairments at DPL of $307 million ($307 million, or $0.41 per share, net of income tax per share of $0.00), at Ebute of $58 million ($58 million, or $0.08 per share, net of income tax per share of $0.00) and at Mountain View of $7 million ($7 million, or $0.01 per share, net of income tax per share of $0.00). Amount also includes an other-than-temporary impairment of our equity method investment at Elsta of $129 million ($128 million, or $0.17 per share, net of income tax per share of $0.00) and asset impairments at Beaver Valley of $46 million ($30 million, or $0.04 per share, net of income tax per share of $0.02), at DPL of $26 million ($17 million, or $0.02 per share, net of income tax per
share of $0.01), at Itabo (San Lorenzo) of $16 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00), at El Salvador for $4 million ($4 million, or $0.01 per share, net of income tax per share of $0.00).
(8)
Amount primarily relates to the goodwill impairment at DPL of $1.82 billion ($1.82 billion, or $2.39 per share, net of income tax per share of $0.00). Amount also includes other-than-temporary impairment of equity method investments in China of $32 million ($32 million, or $0.04 per share, net of income tax per share of $0.00), and at Inno Vent of $17 million ($17 million, or $0.02 per share, net of income tax per share of $0.00), as well as asset impairments of Wind turbines and projects of $41 million ($26 million, or $0.03 per share, net of income tax per share of $0.02) and asset impairments at Kelanitissa of $19 million ($17 million, or $0.02 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00) and at St. Patrick of $11 million ($11 million or $0.01 per share, net of income tax per share of $0.00).
(9)
Amount primarily relates to the loss on early retirement of debt at the Parent Company of $200 million ($130 million, or $0.18 per share, net of income tax per share of $0.10), at DPL of $31 million ($20 million, or $0.03 per share, net of income tax per share of $0.02), at Electrica Angamos of $20 million ($11 million, or $0.02 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00), at UK wind projects of $18 million ($15 million, or $0.02 per share, net of income tax per share of $0.00), at Warrior Run of $8 million ($5 million, or $0.01 per share, net of income tax per share of $0.00) and at Gener of $7 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(10)
Amount primarily relates to the loss on early retirement of debt at Parent Company of $165 million ($107 million, or $0.14 per share, net of income tax per share of $0.08), at Masinloc of $43 million ($39 million, or $0.05 per share, net of income tax per share of $0.00) and Changuinola of $14 million ($10 million, or $0.01 per share, net of income tax per share of $0.01).
(11)
Amount primarily relates to the loss on retirement of debt at the Parent Company of $15 million ($10 million, or $0.01 per share, net of income tax per share of $0.01).
The Company reported a loss from continuing operations of $1.27 per share in 2012. For purposes of measuring diluted loss per share under GAAP, common stock equivalents were excluded from weighted-average shares as their inclusion would be anti-dilutive. However, for purposes of computing Adjusted EPS, the Company has included the impact of dilutive common stock equivalents as the inclusion of the defined adjustments result in income for Adjusted EPS. The table below reconciles the weighted-average shares used in GAAP diluted earnings per share to the weighted-average shares used in calculating the non-GAAP measure of Adjusted EPS.
Operating Margin and Adjusted PTC Analysis
US SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our US SBU for the periods indicated:
Fiscal year 2014 versus 2013
Operating margin for 2014 increased $31 million, or 5%. This performance was driven primarily by the following businesses and key operating drivers:
•
US Generation increased by $26 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $8 million at Laurel Mountain due to increased market prices, and $8 million due to the September 2013 completion of the Tait energy storage project; and
•
IPL in Indiana increased $24 million driven by higher wholesale margin of $14 million and lower fixed costs of $11 million primarily due to lower pension expense.
These increases were partially offset by:
•
DPL decreased $19 million, primarily due to decreases of $71 million mainly attributable to outages which resulted in higher purchased power and related costs, especially in the first quarter when we experienced lower gas availability and higher demand as result of cold weather. Also contributing to the decrease was increased customer switching to third party CRES providers. These results were largely offset by higher rates of $57 million from increased retail rates, lower fuel costs and capacity pricing.
Adjusted Operating Margin increased $27 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owned 100% of its businesses in the US in 2014, so there is no adjustment for noncontrolling interests.
Adjusted PTC decreased $5 million driven by net gains of $53 million recognized as a result of the early termination of the PPA and coal supply contract at Beaver Valley during the first quarter of 2013, largely offset by an increase of $27 million in Adjusted Operating Margin described above as well as an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap and Armenia Wind of $13 million and settlements at Laurel Mountain of $6 million.
Fiscal year 2013 versus 2012
Operating margin decreased by $43 million, or 6%. This performance was driven primarily by the following businesses and key operating drivers:
•
US Generation decreased $26 million, driven by a $24 million decline from the short-term restart of two Huntington Beach units at Southland in 2012, and higher outages at Hawaii of $24 million, partially offset by higher contributions from the US Wind portfolio of $32 million; and
•
IPL in Indiana declined $23 million, as a result of $13 million in higher maintenance costs driven by the timing and duration of major generating unit overhauls, and higher depreciation expense of $6 million due to additional utility plant assets placed in service.
These decreases were partially offset by:
•
DPL increased $6 million, as lower amortization expense of $81 million offset:
◦
A $30 million decrease in sales margin, as customer switching drove retail price decreases, partially offset by higher wholesale volumes;
◦
Lower PJM capacity margins of $12 million; and
◦
$19 million from unrealized gains on derivatives in 2012, which did not recur in 2013.
Adjusted Operating Margin decreased $23 million due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.
Adjusted PTC increased $37 million driven by net gains of $53 million recognized as a result of the early termination of the PPA and coal supply contract at Beaver Valley, partially offset by the decrease of $23 million in Adjusted Operating Margin discussed above.
Andes SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated:
Fiscal year 2014 versus 2013
Including the unfavorable impact of foreign currency translation and remeasurement of $14 million, operating margin increased $54 million, or 10%. This performance was driven primarily by the following businesses and key operating drivers:
•
Chivor in Colombia increased $55 million of which $72 million was due to higher generation, higher spot and contract prices, and ancillary services, partially offset by higher maintenance costs of $12 million and unfavorable foreign exchange rates of $9 million.
•
Argentina increased $8 million driven primarily by higher rates of $30 million as a result of the impact of Resolution 529, higher generation and availability of $13 million, partially offset by higher fixed costs of $27 million driven by higher inflation and unfavorable exchange rates of $5 million.
This increase was offset by:
•
Gener in Chile decreased $9 million, largely driven by a reduction of $32 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $9 million; partially offset by the contribution of $10 million from Ventanas IV, which commenced operations in March 2013, and lower fixed costs from lower maintenance and salaries of $19 million.
Adjusted Operating Margin increased $42 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.
Adjusted PTC increased $68 million, driven by the increase of $42 million in Adjusted Operating Margin described above, and a net benefit of $45 million related to FONINVEMEM interest income on receivables in 2014 and 2013, partially offset by realized FX losses at Chile as well as non-recurring equity tax reversal of $8 million at Colombia in 2013.
Fiscal year 2013 versus 2012
Including the unfavorable impact of foreign currency translation and remeasurement of $18 million, operating margin for 2013 decreased $47 million, or 8%. This performance was driven primarily by the following businesses and key operating drivers:
•
Chivor in Colombia decreased $42 million, as dry hydrological conditions reduced generation output and spot volumes but increased spot prices in the market. Lower volumes had an unfavorable impact of $115 million, partially offset by the favorable impact of $84 million from higher prices.
•
Gener in Chile decreased $8 million, as a reduction of $30 million from lower contract prices and higher spot purchases was partially offset by higher generation of $24 million, as the commencement of operations at Ventanas IV in March 2013 was offset by lower gas availability and lower coal generation.
These decreases were partially offset by:
•
AES Argentina increased $4 million, as lower outages of $18 million and higher volumes of $15 million were partially offset by lower rates of $8 million from the implementation of Resolution 95 and unfavorable exchange rates of $9 million.
Adjusted Operating Margin decreased $29 million due to the drivers above. AES owns 71% of Gener and Chivor and 100% of AES Argentina.
Adjusted PTC decreased $16 million driven by the decrease of $29 million in Adjusted Operating Margin described above, partially offset by higher interest income from the beginning of the accrual of interest on the FONINVEMEM III receivables in Argentina.
Brazil SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated:
Fiscal year 2014 versus 2013
Including the unfavorable impact of foreign currency translation of $97 million, operating margin decreased $129 million, or 15%. This performance was driven primarily by the following businesses and key operating drivers:
•
Tietê decreased $315 million, driven by unfavorable foreign exchange rates of $58 million and the net impact of $252 million of lower hydrology which led to lower generation and an increase in energy purchases at higher prices, partially offset by higher spot sales in the first half of 2014 due to lower contracted volumes of energy sold; and
•
Uruguaiana decreased $51 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations.
These results were partially offset by:
•
Eletropaulo increased $207 million, driven by a non-recurring 2013 charge related to the recognition of a regulatory liability of $198 million related to potential customer refunds, higher rates of $124 million driven by higher tariff and volume of $46 million, partially offset by higher fixed costs and depreciation of $133 million, primarily personnel/pension costs related, and unfavorable foreign exchange rates of $28 million; and
•
Sul increased $31 million, due to higher volume and rates of $52 million, partially offset by higher fixed costs and depreciation of $11 million and unfavorable foreign exchange rates of $10 million.
Adjusted Operating Margin decreased $36 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC increased $30 million, driven by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million that is no longer considered probable and 2014 municipalities settlement interest of $12 million at Sul, partially offset by the decrease of $36 million in Adjusted Operating Margin described above and higher interest rates and debt.
Fiscal year 2013 versus 2012
Including the unfavorable impact of foreign currency translation of $84 million, operating margin decreased $98 million, or 10%. This performance was driven primarily by the following businesses and key operating drivers:
•
Sul decreased $96 million, due to lower tariffs of $33 million from the April 2013 tariff reset and lower volume of $44 million due to lower demand; and
•
Tietê decreased $81 million, driven by the negative impact of foreign currency translation of $68 million as well as lower volume and higher energy purchases of $24 million due to lower hydrology.
These decreases were partially offset by:
•
Uruguaiana increased $64 million, as a result of the extinguishment of a liability of $57 million and the temporary re-start of operations during February and March of 2013.
•
Eletropaulo increased $17 million, driven by higher tariffs of $171 million and lower fixed costs of $42 million, partially offset by the recognition of a regulatory liability of $224 million related to potential customer refunds.
Adjusted Operating Margin decreased $85 million for the year primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC decreased $109 million, as a result of the decrease of $85 million in Adjusted Operating Margin described above, and higher interest expense from higher outstanding debt and a monetary correction related to the asset base ruling for Eletropaulo in December 2013.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated:
Fiscal year 2014 versus 2013
Including the unfavorable impact of currency translation of $3 million, operating margin decreased $2 million, or 0.4%. This performance was driven primarily by the following businesses and key operating drivers:
•
El Salvador decreased $22 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs; and
•
Panama decreased $8 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $38 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of approximately $40 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs of $22 million.
These decreases were partially offset by:
•
Dominican Republic increased $19 million, mainly related to higher spot sales of $58 million and higher availability of $20 million, partially offset by lower gas sales to third parties of $27 million, lower frequency regulation of $26 million and lower PPA results of $14 million; and
•
Puerto Rico increased by $6 million, driven by a favorable bad debt reversal.
Adjusted Operating Margin increased $10 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina and 50% of Itabo in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC increased $13 million, driven by the increase in Adjusted Operating Margin of $10 million as described above.
Fiscal year 2013 versus 2012
Including the unfavorable impact of foreign currency translation of $2 million, operating margin decreased $17 million, or 3%. This performance was driven primarily by the following businesses and key operating drivers:
•
Panama decreased $75 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases at higher prices of $88 million, partially offset by favorable net settlements related to the Esti tunnel of $22 million.
This decrease was partially offset by:
•
Dominican Republic increased $42 million, as a result of higher net energy transactions of $28 million, higher gas sales to third parties of $20 million, partially offset by $6 million due to other factors such as higher fixed costs.
•
El Salvador increased $17 million, due to the tariff increase approved by the regulator at the beginning of 2013.
Adjusted Operating Margin increased $17 million due to the drivers above adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola (as of December 2013) and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina and 50% of Itabo in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico, and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC increased $48 million, driven by the increase in Adjusted Operating Margin of $17 million described above, and lower interest income in the Dominican Republic and the receipt of property damage insurance proceeds in 2012 related to the Esti tunnel in Panama.
Europe SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Europe SBU for the periods indicated:
Fiscal year 2014 versus 2013
Including the unfavorable impact of foreign currency translation of $10 million, operating margin decreased $12 million, or 3%. This performance was driven primarily by the following businesses and key operating drivers:
•
Kilroot decreased $31 million driven by lower dispatch and higher outages and related maintenance costs of $46 million, partially offset by higher rates of $13 million, including income from energy price hedges, and favorable foreign exchange rates; and
•
Maritza decreased $17 million due to higher outages and related maintenance costs of $32 million, partially offset by higher rates of $10 million.
These results were partially offset by:
•
Jordan increased $17 million as the IPP4 Jordan plant commenced operations in July 2014; and
•
Kazakhstan increased $11 million driven by higher volumes and rates of $29 million, partially offset by unfavorable foreign exchange impact of $13 million.
Adjusted Operating Margin decreased $19 million due to the drivers above adjusted for noncontrolling interests, primarily Jordan with Amman East at 36% and IPP4 at 60%, and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $3 million, driven primarily by the decrease of $19 million in Adjusted Operating Margin described above, offset by the reversal of a liability of $18 million in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.
Fiscal year 2013 versus 2012
Including the favorable impact of foreign currency translation of $5 million, operating margin decreased $89 million, or 18%. This performance was driven primarily by the following businesses and key operating drivers:
•
Cartagena in Spain decreased $105 million, as a result of:
◦
A non-recurring, favorable arbitration settlement of $95 million in the first quarter of 2012; and
◦
The two-stage sale of the business, as AES owned 71% of the facility through February 2012 and 14% through April 2013, when the sale was completed.
•
Ballylumford in the U.K. decreased $29 million due to lower rates and capacity payments of $48 million, partially offset by fewer outages of $19 million.
These decreases were partially offset by:
•
Maritza in Bulgaria increased $30 million driven by $10 million from fewer outages, $6 million of lower fixed costs, and favorable foreign exchange rates of $7 million.
•
Kilroot in the U.K. increased $28 million driven by favorable dark spreads from higher energy prices and lower coal costs.
Adjusted Operating Margin decreased $55 million due to the drivers above adjusted for the impact of noncontrolling interests, primarily Cartagena in Spain due to the two stage sale of the business as described above, and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $30 million, driven by the decrease of $55 million in Adjusted Operating Margin described above, partially offset by lower interest expense and realized foreign currency gains at Kilroot and higher equity earnings from Turkey and Elsta in the Netherlands.
Asia SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Generation businesses in Asia for the periods indicated:
Fiscal year 2014 versus 2013
Operating margin decreased $93 million, or 55%. This performance was driven primarily by the following businesses and key operating drivers:
•
Masinloc in the Philippines decreased by $79 million, driven by $33 million due to lower plant availability, a net decrease of $21 million of lower spot rates partially offset by higher volume, an unfavorable impact of $15 million resulting from the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, higher maintenance costs of $4 million; and
•
Kelanitissa in Sri Lanka decreased by $17 million, driven by the step-down in the contracted PPA price.
Adjusted Operating Margin decreased $108 million due to the drivers above adjusted for the impact of non-controlling interests and excluding unrealized gains on derivatives. AES owned 92% of Masinloc until July 2014 when AES reduced its ownership to 51%.
Adjusted PTC decreased $96 million, driven by the decrease of $108 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc and gains on foreign currency.
Fiscal year 2013 versus 2012
Operating margin decreased $67 million, or 28%. This performance was driven primarily by the following business and key operating drivers:
•
Masinloc in Philippines decreased $62 million, due to:
◦
The net impact of higher contracted volumes at lower prices, as a result of a new 7-year contract to reduce spot exposure, with an unfavorable impact of $31 million;
◦
A reversal of a contingency of $16 million in 2012; and
◦
An unrealized derivative gain of $15 million in 2012.
Adjusted Operating Margin decreased $45 million due to the drivers discussed above adjusted for the impact of noncontrolling interests and excluding unrealized gains on derivatives. AES owned 92% of Masinloc (prior to partial sale in 2014).
Adjusted PTC decreased $59 million, driven primarily by the decrease of $45 million in Adjusted Operating Margin described above, as well as a reduction in equity earnings from the sale of our businesses in China in 2012, partially offset by lower interest expense at Masinloc.
Key Trends and Uncertainties
During 2015 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.-Business and Item 1A.-Risk Factors of this Form 10-K.
Regulatory
Philippines-In November and December 2013, the Philippines spot market witnessed an unprecedented price spike compared to historical levels. On March 11, 2014, the ERC declared the market prices from this period void and ordered the market operator to recalculate the prices for all market participants for November and December 2013 billing months. The recalculation of prices based on the load weighted average prices for the first nine months of 2013 resulted in an unfavorable adjustment of approximately $15 million to Masinloc spot sales. The ERC denied all motions for reconsideration filed by the generating companies.
Prior to the high price events in 2013, there was a primary price cap for spot prices set at 62,000 pesos per MWh. This cap was lowered to 32,000 pesos per MWh on January 4, 2014 pursuant to a joint resolution by the ERC, the Department of Energy (DoE) and the market operator. On May 5, 2014, a secondary price cap of 6,245 pesos per MWh was established on an interim basis to be applied when certain high price thresholds were met over time. On December 15, 2014, the ERC issued a resolution to change the temporary nature of the secondary price cap into a permanent secondary price cap. Based on historical trends we do not expect either the primary or the secondary price cap mechanisms to be triggered.
Dominican Republic-In August 2014, the Superintendence of Electricity (Sectoral Regulatory Body of the Electricity Sector) modified the rules for offering primary frequency regulation service, an ancillary service item. The former rules allocated the service to generators based on merit order and those which were the most flexible and could enter the system quickly met the supply requirement. The new rule assigns a mandatory minimum margin to all generators which must be provided by its own source or through bilateral contracts with other generators who can offer the service. Additional supply requirements are allocated using the merit order process. The AES businesses, Andres and Los Mina, were previously lower in the merit order and received a majority of the allocation under the former rules. The lower allocation of this service to these units under the new rules will have an impact of lowering margin from frequency regulation, which will be partially offset by higher energy dispatch due to increased capacity.
Operational
Sensitivity to Dry Hydrological Conditions
Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Throughout 2013 and 2014, dry hydrological conditions in Brazil, Panama, Chile and Colombia have presented challenges for our businesses in these markets. Low rainfall and water inflows caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If hydrological conditions do not improve and our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations. Some local forecasts suggest continued dry conditions may continue through first half of 2015. Even if rainfall and water inflows return to historical average, high market prices and low generation could persist until reservoir levels are fully recovered.
In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and there is a mechanism called MRE created to share hydrological risk across all generators. If the system of hydroelectric generation facilities generates less than the assured energy of the system, the shortfall is shared among generators, and depending on a generator's contract level, is fulfilled with spot market purchases. The system average inflows in 2014 were the 10th worst of the historical data since 1931. The consequences of unfavorable hydrology are (i) thermal plants (more expensive to the system) being dispatched, (ii) lower hydro power generation with deficits in the MRE and (iii) high spot prices. During 2014 spot prices sustained significantly high levels causing financial stress to most agents in the energy sector. From February to April 2014, the spot price was at the cap level of R$822/MWh, contributing to the average spot price of R$690/MWh in 2014. During October and November 2014, ANEEL conducted a public hearing to define a new spot price cap, reducing it from R$822/MWh to R$388/MWh from January 2015 forward. The lower cap price will result in a meaningful reduction on expenses for the agents that are negatively exposed to the spot price in 2015.
We expect the system operator in Brazil to continue to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 17 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices at high levels. AES Tietê has contract obligations throughout 2015 and may need to fulfill some of these obligations with spot purchases, so they will be sensitive to generation output and spot prices for electricity during this period. In addition, the costs incurred by our distribution companies, AES Eletropaulo and AES Sul, on energy purchases are passed through to customers with adjustments on a yearly basis, so working capital will be sensitive to significant increases in energy prices. In order to reduce potential working capital needs, on February 2015 ANEEL opened two public hearings i) to discuss an Extraordinary Tariff Review requested by distribution companies and ii) to discuss adjustments to a tariff flag mechanism that may change the tariff to customers on a monthly basis depending on energy prices. These items are expected to increase tariffs starting in March 2015, anticipating pass-through of energy costs thus reducing potential working capital needs for distribution companies.
Finally, if dry conditions persist into the next rainy season through April 2015, there is a risk that the government of Brazil could implement a rationing program in 2015. If rationing were to occur, we would expect rules to be implemented that may include, but are not limited to, i) adjustments to hydroelectric generation PPAs in accordance with the overall load reduction affecting contracting position of hydroelectric generators and distribution companies, ii) reduction in energy consumption impacting hydroelectric generation and margins of distribution companies, iii) increases in costs for distribution companies to provide additional customer services, communications, and to comply with rationing decree rules and iv) increases in losses and delinquency for distribution companies due to higher tariffs and potential penalties. As a result, if below long-term average hydrology continues and/or Brazil implements a rationing program, we would expect there to be an adverse impact on our results of operations and cash flows of our generation and distribution businesses in Brazil. Finally, an Extraordinary Tariff Review may be applied to partially or completely offset the reduction in margin and increase on costs, losses and delinquency incurred by distribution companies due to rationing, mitigating the adverse impact on results.
In Panama, dry hydrological conditions continued in 2014 reducing generation output from hydroelectric facilities and increasing spot prices for electricity. From March to June 2014, the government of Panama implemented certain energy saving measures designed to reduce demand for electricity during the peak hours by approximately 300 MW, which contributed to
water savings in the key hydroelectric dams and lower spot prices. AES Panama had to purchase energy on the spot market to fulfill its contract obligations when its generation output is below its contract levels, and we expect this trend to continue through the first half of the year which will continue to impact our results of operations. As authorized on March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70MW reduction in contracted capacity for the period 2014-2016 by compensating AES Panama for spot purchases up to $40 million in 2014, $30 million in 2015 and $30 million in 2016. Compensation payments recognized through December 31, 2014 were $40 million, of which $3 million are pending to be collected. Additionally, as part of our strategy to reduce our reliance on hydrology, AES Panama acquired a 72MW power barge for $27 million, financed with non-recourse debt, in September 2014, which we expect to become operational in the first quarter of 2015.
Taxes
The Company expects its effective tax rate in future years to be higher than the current year effective rate of 27%. As discussed in Item 7.- Review of Consolidated Results of Operations, the current year rate was favorably impacted by certain non-recurring items and the Company’s benefit from reduced income tax rates on its operations in the Philippines which expired in the fourth quarter of 2014. Further, as noted in Critical Accounting Policies and Estimates (also in Item 7. of this Form 10-K), the Company is subject to higher income tax rates in Colombia for the next four years.
Macroeconomic and Political
During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue.
Argentina-In Argentina, economic conditions remain unfavorable, as measured by indicators such as non-receding inflation, increased government deficits, diminished sovereign reserves, lack of foreign currency accessibility, the potential for continued devaluation of the local currency, and a decline in expectations for economic growth. Many of these economic conditions in conjunction with the restrictions to freely access the foreign exchange currency established by the Argentine Government since 2012, have contributed to the development of a limited parallel unofficial foreign exchange market that is less favorable than the official exchange. At December 31, 2014, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 7-Financing Receivables in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information on the long-term receivables. In January 2014, the Argentine Peso devalued by approximately 20%, the most rapid depreciation since 2002. While the currency has stabilized in the later part of 2014, further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets.
Argentina defaulted on its public debt in 2001, when it stopped making payments on about $100 billion amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the “hold-out” bondholders have been in judicial proceedings with Argentina regarding payment. More recently, the United States District Court ruled that Argentina would need to make payment to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. Although this situation remains unresolved, it has not caused any significant changes that impact our current exposures, however, as noted above, there could be impacts on our businesses in the future.
Bulgaria-Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned electricity public supplier and energy trading company. Maritza, a lignite-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by NEK. In November 2013, Maritza and NEK signed a rescheduling agreement for the overdue receivables as of November 12, 2013. Under the terms of the agreement, NEK paid $70 million of the overdue receivables and agreed to pay the remaining receivables in 13 equal monthly installments beginning December 2013. NEK has made payments according to the schedule through December 2014 when the final installment was paid. On July 31, 2014 Maritza entered into a tripartite agreement with NEK and Mini Maritza Iztok EAD ("MMI"), our fuel supplier, which reduced Maritza's outstanding receivables from NEK by $17 million through an offset of payables due by Maritza to MMI. Additionally in 2014, NEK paid four additional monthly installments totaling $28 million as agreed upon on time. As of December 31, 2014, Maritza had outstanding receivables of $262 million, representing $57 million of current receivables, $75 million of receivables overdue by less than 90 days and $130 million of receivables overdue by more than 90 days. Although Maritza continued to collect overdue receivables during the fourth quarter of 2014 and thereafter, there continue to be risks associated with collections, which could result in a write-off of the remaining receivables and/or liquidity problems
which could impact Maritza's ability to meet its obligations, if the situation around collections were to deteriorate significantly. No allowance has been recognized on the receivables as the Company continues to assert that collection is probable. See Note 12-Debt included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information on current existing debt defaults. Litigation related to construction delays and related matters was settled in December 2014. For further information on the litigation see Item 3.-Legal Proceedings.
In May and June 2014, Bulgaria’s SEWRC issued decisions precluding the ability of NEK to pass-through to the regulated market certain costs incurred by NEK pursuant to the PPA with Maritza, which further impacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments to the PPA, including taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30%. However, SEWRC confirmed that until such negotiations conclude, the PPA is in full force and effect and NEK has not objected to Maritza's invoices. Maritza has filed appeals and requests for suspension of these SEWRC decisions with the Supreme Administrative Court in Bulgaria. The requests for suspension were denied by SAC. Further, on November 17, 2014, SEWRC replaced its May 2014 decision taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30% with a decision which only required NEK and Maritza to start negotiations towards amending the PPA, without any prescribed parameters. Following the repeal of the decision, Maritza withdrew its appeal against that decision but continues to appeal the other May 2014 decisions. In addition, SEWRC announced in June 2014 that it has asked the DG Comp to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date. If necessary, Maritza will defend the PPA in any assessment or proceeding that may be initiated by DG Comp in response to SEWRC's request.
In June 2014, new measures aiming at allocating to renewable energy producers the cost associated with the imbalance between forecasted and actual generation (known as Balancing Market) became effective. Saint-Nikola, a wind farm located in Kavarna, has been negatively impacted by these measures. Saint-Nikola is challenging the validity of the calculation methodology with SEWRC, and will take all actions necessary to protect its interests.
On July 24, 2014, the Government of Bulgaria formally resigned and the Caretaker Government was appointed by the President. Preliminary Parliamentary Elections were held on October 5, 2014. A coalition led by center-right party GERB formed a new government led by Prime Minister Boyko Borisov. The new government set as one of its priorities the restructuring of the energy sector, which is necessary to restore NEK’s liquidity. The first measure announced by the new government was an end-consumer energy price increase of approximately 10% effective October 1, 2014. The other measures are being prepared by the Energy Commission of the Parliament, and are expected to be promulgated by June 2015. One of the components of the energy sector restructuring is the negotiation of an amendment of Maritza’s PPA. Maritza has engaged in negotiations with SEWRC, NEK, and other Bulgarian instrumentalities concerning these matters. In February 2015, the Company signed a Memorandum of Understanding with the Government of Bulgaria to commence negotiations on proposed amendments to the existing PPA with NEK, which includes the payment of all outstanding receivables. Maritza will take all actions necessary to protect its interests, whether through negotiated agreement with NEK or through enforcement of its rights under the PPA.
Furthermore, as noted in Item 1.-Business-Bulgaria, during the fourth quarter of 2013, NEK requested a consent from Maritza for a restructuring. In February 2014, the NEK restructuring was implemented after approval by the regulatory authorities. As a result, NEK’s credit rating fell below the rating NEK had upon the issuance of the Government Support Letter in 2005. Also, as a result of this restructuring NEK transmission license was revoked by the Regulator. These are defaults under the PPA, which triggered additional events of default under the project debt agreements. For further information on the importance of long-term contracts and our counterparty credit risk, see Item 1A.-Risk Factors-“We may not be able to enter into long-term contracts, which reduce volatility in our results of operations.” As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
As of December 31, 2014, we concluded there is no indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.3 billion and total debt of $690 million, and Kavarna, which were $242 million and total debt of $168 million. Therefore, management believes the carrying amount of the asset group is recoverable as of December 31, 2014.
In December 2014 the Agency for State Financial Inspection started an audit to evaluate the compliance of Maritza with Public Procurement rules. Based on an extensive regulatory review conducted in 2011 at the time of Maritza plant commissioning, Maritza does not follow Public Procurement rules and will defend its rights if necessary after the conclusion of the audit, expected by June 2015.
Puerto Rico- Our subsidiary in Puerto Rico has a long-term PPA with the PREPA, a state-owned entity that supplies virtually all of the electric power consumed in the Commonwealth and generates, transmits and distributes electricity to 1.5 million customers. As a result of macroeconomic challenges in the country, including a seven-year recession, PREPA faces economic challenges including, but not limited to, reliance on high cost fuel oil, decline in electricity sales, high customer power rates, high operating costs, past due accounts receivable from government institutions, and very low liquidity along with challenges obtaining financing due to the recent downgrades, and has struggled to honor its payment obligations to electricity generators on a timely basis.
In February 2014, all agencies downgraded the Commonwealth of Puerto Rico and its public sector companies (PREPA included) to below investment grade. On June 28, 2014, the Governor of Puerto Rico signed into law the Recovery Act, which allows public corporations to adjust their debts in the interest of all creditors and establishes procedures for the orderly enforcement. With the recent passing of the Recovery Act, the ratings were further reduced. The downgrade on PREPA has had a direct impact on AES Puerto Rico's bonds. While Fitch rates both AES PR and PREPA with CC, Moody's rates AES Puerto Rico bonds (B3) three notches above PREPA (Caa3) citing as reasons the priority position of PREPA's contractual payments to AES PR as an operating expense as well as the project's strategic importance to PREPA as an efficient, reliable and relatively low cost source of power. We believe that AES Puerto Rico’s unique position as the lowest cost energy producer and cost-effective alternative for PREPA relative to fuel oil generated power, positions the business well and reduces the probability of negative impacts from a potential PREPA restructuring process. However, there can be no assurance as to the final terms of any restructuring or potential impacts on AES Puerto Rico.
On December 14, 2014 PREPA presented the first stage of the business plan to bondholders, which laid out key financial information on the current affairs of PREPA. The report, presented by PREPA's Chief Restructuring Officer ("CRO") complied with a key milestone in the Forbearance Agreement that expires on March 2, 2015 with bondholders. While the report is subject to strict confidentiality clauses, the CRO has stated that it does not contain recommendations or proposals on the utility’s capital structure, rates, payroll or any other fronts. During January, the CRO informed that their recommendations will not be ready until June 2015. The CRO is required to submit the recommendations to the Forbearance Committee which should state whether PREPA intends to restructure its debt combined with other restructuring actions on vendor negotiations, fuel cost contacts, capital needs and labor costs.
If AES Puerto Rico fails to receive payment in accordance with the terms of the PPA with PREPA, its liquidity issues could worsen, which could impact AES Puerto Rico's ability to meet its obligations. For further information, see Item 1A.-Risk Factors-“We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and "We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations." As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. AES Puerto Rico's receivables balance as of December 31, 2014 is $89 million, of which $24 million is overdue. Subsequent to December 31, 2014, the full overdue amount has been collected.
Our Puerto Rico business will take all actions necessary to protect its interests, whether through negotiated agreement with PREPA or through enforcement of its rights under the PPA. In October 2014, the Parent Company reached an agreement with an investor in AES Puerto Rico's preferred shares to retire the investment at a fixed redemption value of $52 million. As the events pertaining to the Recovery Act continue to unfold, we concluded that there was no indicator of an impairment of the long-lived assets in Puerto Rico, which were $632 million and total debt of $528 million. Therefore, management believes the carrying amount of the asset group is recoverable as of December 31, 2014.
If the above referenced economic conditions deteriorate further, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.
Impairments
Goodwill - In the fourth quarter of 2014, the Company completed its annual October 1 goodwill impairment tests and recognized goodwill impairment expense of $10 million. Year to date, the Company has recognized goodwill impairment expense of $164 million. The Company has no reporting units considered to be "at risk." A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. The Company monitors its reporting units at risk of step 1 failure on an ongoing basis. It is possible that the Company may incur goodwill impairment charges at any reporting
units containing goodwill in future periods if adverse changes in their business or operating environments occur. See Note 10-Goodwill and Other Intangible Assets included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Capital Resources and Liquidity
Overview
As of December 31, 2014, the Company had unrestricted cash and cash equivalents of $1.5 billion, of which $507 million was held at the Parent Company and qualified holding companies. The Company also had $709 million in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $694 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.6 billion and $5.3 billion, respectively. Of the approximately $2.0 billion of our current non-recourse debt, $1.1 billion was presented as such because it is due in the next twelve months and $858 million relates to debt considered in default due to covenant violations. The defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants and/or other conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the Company.
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 $151 million of our recourse debt matures within the next twelve months, which we expect to repay using a combination of cash on hand at the Parent Company, net cash provided by operating activities and/or net proceeds from the issuance of new debt at the Parent Company.
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.
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. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility and floating rate senior unsecured notes due 2019. On a consolidated basis, of the Company’s $15.6 billion of total non-recourse debt outstanding as of December 31, 2014, approximately $3.9 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, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At December 31, 2014, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $417 million in aggregate (excluding 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, 2014, we had $61 million in letters of credit outstanding, provided under our senior secured credit facility, and $74 million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the year ended December 31, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% 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 we or our affiliates 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 on economically attractive terms or at all. 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, 2014, the Company had approximately $293 million and $31 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic and its utility businesses in Brazil classified as “Noncurrent assets-other” and “Current assets-Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond December 31, 2015, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 7-Financing Receivables included in Item 8.-Financial Statements and Supplementary Data and Item 1.-Business-Regulatory Matters-Argentina of this Form 10-K for further information.
Consolidated Cash Flows
During the year ended December 31, 2014, cash and cash equivalents decreased $103 million to $1.5 billion. The decrease in cash and cash equivalents was due to $1.8 billion of cash provided by operating activities, $656 million of cash used in investing activities, $1.3 billion of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $51 million and a $75 million decrease in cash of discontinued and held-for-sale businesses.
Operating Activities
2014 Cash Flows from Operating Activities
For the year ended December 31, 2014 compared to the year ended December 31, 2013, the net decrease in cash flows from operating activities of $924 million, or 34% to $1.8 billion was primarily the result of the following:
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Brazil - decrease of $549 million primarily driven by higher tax payments of $244 million across the region and higher energy purchases in excess of collections resulting from poor hydrology of $153 million and $84 million at the Utilities and Tietê, respectively;
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MCAC - a decrease of $184 million primarily driven by a non-recurring $90 million settlement received in 2013 related to a fuel contract amendment and $12 million lower collections in Dominican Republic, as well as higher energy purchases of $46 million in Panama, and;
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Europe - a decrease of $180 million primarily due to lower collections of $56 million at Maritza in Bulgaria and higher working capital requirements of $52 million in Northern Ireland in the U.K.
Operating cash flow of $1.8 billion for the year ended December 31, 2014 resulted primarily from net income and adjustments for non-cash items (principally depreciation and amortization, gain from sale of assets and investments, and
impairment expense), which was partially offset by a net use of cash from changes in operating assets and liabilities of $1.0 billion due to the following:
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an increase of $723 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs as well as an increase at Alicura related to the recognition of interest associated with the FONINVEMEM agreement;
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an increase of $520 million in accounts receivable primarily related to higher sales at Eletropaulo and Sul and lower collections at Maritza; and
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a decrease of $89 million in net income tax and other tax payables primarily for payments of income taxes in excess of accruals of new current tax liabilities; partially offset by
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an increase of $516 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by pension contributions at IPL and payments for share-based compensation issuance withholding tax and termination of a derivative contract at the Parent Company.
2013 Cash Flows from Operating Activities
For the year ended December 31, 2013 compared to the year ended December 31, 2012, the net decrease in cash flows from operating activities of $186 million, or 6% to $2.7 billion was primarily the result of the following:
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US - an increase of $74 million primarily due to a bankruptcy settlement payment of the New York entities in 2012 and the proceeds from the PPA termination at Beaver Valley in January 2013;
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Andes - a decrease of $276 million primarily driven by higher working capital requirements;
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Brazil - a decrease of $106 million primarily related to lower collections and higher energy purchases at Sul, partially offset by the recovery of deferred costs from ANEEL, rate regulator, lower transmission costs and regulatory charges at Eletropaulo;
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MCAC - an increase of $185 million primarily driven by a $90 million settlement received related to an amendment to a fuel contract and lower working capital requirements; and
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Asia - a decrease of $85 million primarily driven by higher working capital requirements and lower operating results at Masinloc.
Operating cash flow of $2.7 billion for the year ended December 31, 2013 resulted primarily from net loss and adjustments for non-cash items (principally gain and losses on sales and disposals, impairment charges, depreciation and amortization, and deferred income taxes), which was partially offset by a net use of cash from changes in operating assets and liabilities of $76 million due to the following:
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a decrease of $725 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and at Uruguaiana primarily related to the extinguishment of a liability as well as lower generation and higher payments to fuel supplier at Kelanitissa;
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an increase of $103 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs and an increase at Alicura related to the recognition of interest associated to FONINVEMEM agreement, partially offset by a decrease in noncurrent regulatory assets at IPL related to the annual adjustment to pension benefits based on the actuarial valuation; partially offset by
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a decrease of $358 million in prepaid expenses and other current assets mainly due to a decrease in current regulatory assets, for the recovery of prior period tariff cycle energy purchases and regulatory charges at Eletropaulo;
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a decrease of $146 million in accounts receivable primarily related to lower tariffs at Eletropaulo combined with lower tariff and reduced consumption at Sul as well as lower revenue offset by higher collections at Kelanitissa, partially offset by lower collections at Maritza;
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an increase of $137 million in other liabilities primarily due to an increase in noncurrent regulatory liabilities at Eletropaulo partially offset by a decrease in pension liability at IPL; and
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a increase of $95 million in net income tax and other tax payables primarily due to accruals for new current tax liabilities offset by payments of income taxes.
2012 Cash Flows from Operating Activities
Net cash provided by operating activities was $2.9 billion for the year ended December 31, 2012. Operating cash flow resulted primarily from net income and adjustments for non-cash items (principally depreciation and amortization, contingencies, deferred income taxes, losses on the extinguishment of debt, gains and losses on sales and disposals, and impairment charges), as well as a net source of cash from changes in operating assets and liabilities of $68 million due to the following:
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an increase of $589 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases, regulatory charges and transmission costs which are recoverable through future tariffs and the establishment of a noncurrent note receivable at Cartagena in Spain following the arbitration settlement, prior to its deconsolidation;
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an increase of $241 million in accounts receivable primarily due to lower collection Eletropaulo and Andres as well as an increase in revenue at Sul and Kelanitissa;
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a decrease of $47 million net income tax payables and other tax payables primarily for the payment of income taxes in excess of the accrual of new tax liabilities; partially offset by
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an increase of $335 million in other liabilities primarily explained by an increase in noncurrent regulatory liabilities at Eletropaulo related to the tariff reset;
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an increase of $330 million in accounts payable and other current liabilities primarily at Eletropaulo due to an increase in current regulatory liabilities driven by the tariff reset, offset by a decrease in other current liabilities arising from value-added tax payables; and
•
a decrease of $120 million in prepaid expenses and other current assets mainly due to the recovery of value-added taxes at our construction projects in Chile.
Investing Activities
2014 Cash Flows from Investing Activities
Net cash used in investing activities was $656 million for the year ended December 31, 2014 primarily attributable to the following:
•
Capital expenditures of $2.0 billion consisting of $1.2 billion of growth capital expenditures and $865 million of maintenance and environmental capital expenditures. Material expenditures by business are as follows:
◦
Growth capital expenditures included amounts at Gener of $399 million, Eletropaulo of $146 million, IPL of $126 million, Mong Duong of $111 million, Jordan of $72 million, Maritza of $62 million, DPL of $46 million, Sul of $45 million and Panama of $42 million;
◦
Maintenance and environmental capital expenditures included amounts at IPL of $265 million, Eletropaulo of $90 million, Gener of $89 million, Tietê of $80 million, DPL of $65 million, Sul of $54 million and Altai of $43 million;
•
Acquisitions, net of cash acquired of $728 million consisted primarily of an acquisition at Gener in the second quarter for the remaining 50% interest in our equity investment in Guacolda, of which 50% less one share was subsequently sold during the same quarter. See Note 8-Investment in and Advances to Affiliates in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information;
•
Purchases of short-term investments, net of sales of $120 million including amounts at Brasiliana Energia of $81 million and Tietê of $63 million offset by net sales at Eletropaulo of $39 million; partially offset by
•
Proceeds from the sale of businesses, net of cash sold of $1.8 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $436 million for the sale of 45% of our equity interest in Masinloc, $174 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and the United States, $158 million related to the UK Wind Sale, $156 million from the sale of our businesses in Cameroon and $125 million for the sale of Entek, our equity investment in Turkey; and
•
Decreases in restricted cash, debt service reserve and other assets of $419 million including amounts of $98 million primarily related to the Alstom settlement repayment at Maritza, $96 million at the Parent Company pertaining to letter of credit reductions for Jordan and Mong Duong development projects, as well as project debt refinancing of $70 million and $45 million at Angamos and Southland, respectively.
2013 Cash Flows from Investing Activities
Net cash used in investing activities was $1.8 billion for the year ended December 31, 2013 primarily attributable to the following:
•
Capital expenditures of $2.0 billion consisting of $1.1 billion of growth capital expenditures and $934 million of maintenance and environmental capital expenditures.
◦
Growth capital expenditures included amounts at Gener of $317 million, Eletropaulo of $223 million, Jordan of $200 million, Sul of $72 million, Mong Duong of $48 million, DPL of $40 million, Sixpenny Wood of $25 million, Altai of $21 million, Yelvertoft of $20 million and Kribi of $20 million;
◦
Maintenance and environmental expenditures included amounts at IPL of $246 million, Eletropaulo of $138 million, Tietê of $94 million, Gener of $92 million, DPL of $76 million, Sul of $61 million and Altai of $43 million; partially offset by
•
Proceeds from the sale of businesses, net of cash sold of $170 million including $110 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.
Financing Activities
2014 Cash Flows from Financing Activities
Net cash used in financing activities was $1.3 billion for the year ended December 31, 2014 primarily attributable to the following:
•
Repayments of recourse and non-recourse debt of $5.6 billion including amounts at the Parent Company of $2.1 billion, Gener of $905 million, Angamos of $780 million, DPL of $364 million, Southland of $188 million, Chivor of $165 million, Tietê of $132 million, $114 million related to the UK Wind sale, Eletropaulo of $110 million and Warrior Run of $109 million;
•
Payments for financed capital expenditures were $528 million including $310 million at Mong Duong, $143 million at Cochrane and $30 million at Changuinola;
•
Distributions to noncontrolling interests of $485 million including amounts at Tietê of $188 million, Brasiliana Energia of $69 million, Gener of $66 million and Buffalo Gap of $45 million;
•
Purchase of treasury stock of $308 million at the Parent Company; partially offset by
•
Issuances of recourse and non-recourse debt of $5.7 billion including new issuances at the Parent Company of $1.5 billion, Angamos of $800 million, Gener of $700 million, Mong Duong of $364 million, Tietê of $318 million, Cochrane of $305 million, US Generation Holdings of $299 million, Eletropaulo of $253 million, DPL of $200 million and Sul of $185 million.
2013 Cash Flows from Financing Activities
Net cash used in financing activities was $1.1 billion for the year ended December 31, 2013 primarily attributable to the following:
•
Repayments of recourse and non-recourse debt of $4.6 billion including amounts at the Parent Company of $1.2 billion, DPL of $948 million, Masinloc of $560 million, Changuinola of $412 million, Tietê of $396 million, Caess of $301 million, IPL of $110 million, Warrior Run of $100 million, Puerto Rico of $73 million, Maritza of $57 million, Southland of $54 million, Sonel of $47 million and Sul of $44 million;
•
Payments for financed capital expenditures were $591 million primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed;
•
Distributions to noncontrolling interests of $557 million including amounts at Tietê of $205 million, Brasiliana of $128 million, Gener of $62 million and Buffalo Gap of $54 million;
•
The purchase of treasury stock at the Parent Company was $322 million;
•
Payments for financing fees of $176 million including amounts at Gener of $54 million including amounts at the Alto Maipo and Cochrane projects, Mong Duong of $28 million and Eletropaulo of $25 million; partially offset by
•
Issuances of recourse and non-recourse debt of $5.0 billion including amounts of $750 million at the Parent Company, Gener of $707 million including amounts at the Cochrane and Alto Maipo projects, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $471 million, Changuinola of $420 million, Caess of $310 million, Jordan of $180 million, IPL of $170 million and Sul of $153 million; and
•
Contributions from noncontrolling interests of $210 million including amounts at Gener of $109 million including amounts at the Cochrane and Alto Maipo projects and at Mong Duong of $77 million.
Proportional Free Cash Flow (a non-GAAP measure)
We define Proportional free cash flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests.
We exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1. US SBU-IPL-Environmental Matters for details of these investments.
The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be available for investing or repaying debt or other purposes. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly owned by the Company.
The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies.
(1) The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds), and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by non-controlling interests for each entity by its corresponding consolidated cash flow metric and adding up the resulting figures. For example, the Company owns approximately 71% of AES Gener, its subsidiary in Chile. Assuming a consolidated net cash flow from operating activities of $100 from AES Gener, the proportional adjustment factor for AES Gener would equal approximately $29 (or $100 x 29%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then adds these amounts together to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to non-controlling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary where such items occur.
Proportional Free Cash Flow for the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased $380 million, driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions pertaining to interest, tax sharing and charges for management fee and transfer pricing:
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MCAC - $152 million decrease primarily driven by a non-recurring $90 million settlement received in 2013 related to a fuel contract amendment and $30 million lower collections in Dominican Republic, as well as higher energy purchases of $22 million in Panama;
•
Europe - $149 million decrease primarily driven by $56 million of lower collections in Bulgaria and $52 million of lower operating margins and higher working capital in Northern Ireland in the U.K.;
•
Brazil - $103 million decrease primarily driven by higher tax payments of $100 million across the region and higher energy purchases in excess of collections resulting from poor hydrology of $10 million and $20 million at the Utilities and Tietê, respectively;
•
US - $46 million decrease driven by $46 million proceeds from the PPA termination at Beaver Valley in 2013 and $41 million of higher working capital at DPL, partially offset by $52 million of lower maintenance capital expenditures at the U.S. Utilities;
•
Asia - $19 million decrease driven primarily by lower margins at Kelanitissa; and
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Andes - $13 million decrease primarily related to $51 million in Chile driven by $28 million of VAT receivable timing and an interest rate swap payment of $18 million as well as $28 million in Argentina primarily due to an increase in interest receivables. These results were partially offset by an increase of $67 million at Chivor in Colombia primarily due to higher margins.
These decreases were partially offset by:
•
Corporate - $98 million increase primarily driven by lower Parent interest of $69 million.
Proportional Free Cash Flow for the year ended December 31, 2013 compared to the year ended December 31, 2012 increased $21 million, driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions pertaining to interest, tax sharing and charges for management fee and transfer pricing:
•
MCAC - $197 million increase driven by higher operating cash flow, as a result of a $90 million settlement related to an amendment to a fuel contract and lower working capital requirements, and
•
US - $110 million increase as a result of higher operating cash flow from a settlement received related to the bankruptcy of the New York entities in 2012 and the proceeds from the PPA termination at Beaver Valley in January 2013, as well as $48 million due to lower capital expenditures.
These increases were partially offset by:
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Andes - $193 million increase driven by lower operating cash flow from higher working capital requirements; and
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Asia - $76 million decrease largely due to lower operating cash flow from higher working capital requirements and lower operating results at Masinloc.
Parent Free Cash Flow (a non-GAAP measure)
The Company defines Parent Free Cash Flow as dividends and other distributions received from our operating businesses less certain cash costs at the Parent Company level, primarily interest payments, overhead, and development costs. Parent Free Cash Flow is used to fund shareholder dividends, share repurchases, growth investments, recourse debt repayments, and other uses by the Parent Company. Refer to Item 1 - Business-Overview for further discussion of the Parent Company's capital allocation strategy.
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. 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;
•
proceeds from debt and equity financings at the Parent Company level, including availability under our credit facility; and
•
proceeds from asset sales.
Cash requirements at the Parent Company level are primarily to fund:
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interest;
•
principal repayments of debt;
•
acquisitions;
•
construction commitments;
•
other equity commitments;
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common stock repurchases;
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taxes;
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Parent Company overhead and development costs; and
•
dividends on common stock.
The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facility. 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, 2014 and 2013 as follows:
The Company paid dividends of $0.20 per share to its common stockholders during the year ended December 31, 2014. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends.
Recourse Debt:
Our recourse debt at year-end was approximately $5.3 billion and $5.7 billion in 2014 and 2013, respectively. See Note 12-Debt in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for additional detail.
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 Key Trends and Uncertainties, Global Economic Conditions), 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. See Item 1A.-Risk Factors-The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise, of this Form 10-K.
Various debt instruments at the Parent Company level, including our senior secured credit facility, contain certain restrictive covenants. The covenants provide for, among other items:
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limitations on other indebtedness, liens, investments and guarantees;
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limitations on dividends, stock repurchases and other equity transactions;
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restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements;
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maintenance of certain financial ratios; and
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financial and other reporting requirements.
As of December 31, 2014, we were in compliance with these covenants at the Parent Company level.
Non-Recourse Debt
While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:
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reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;
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triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;
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causing us to record a loss in the event the lender forecloses on the assets; and
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triggering defaults in our outstanding debt at the Parent Company.
For example, our senior secured credit facility and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying consolidated balance sheets amounts to $2.0 billion. The portion of current debt related to such defaults was $858 million at December 31, 2014, all of which was non-recourse debt
related to two subsidiaries - Maritza and Kavarna. See Note 12-Debt in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for additional detail.
None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of December 31, 2014 in order for such defaults to trigger an event of default or permit acceleration under AES’ indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position 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 an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facility as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of December 31, 2014, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.
Contractual Obligations and Parent Company Contingent Contractual Obligations
A summary of our contractual obligations, commitments and other liabilities as of December 31, 2014 is presented in the table below, which excludes any businesses classified as discontinued operations or held-for-sale (in millions):
(1)
Includes recourse and non-recourse debt presented on the Consolidated Balance Sheet. See Note 12-Debt to the Consolidated Financial Statements included in Item 8 - Financial Statements and Supplementary Data 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, 2014 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, 2014.
(3)
See Note 13-Commitments to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further information.
(4)
These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of 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. In addition, the amounts do not include: (1) regulatory liabilities (See Note 11-Regulatory Assets and Liabilities), (2) contingencies (See Note 14-Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 15-Benefit Plans) or (4) any taxes (See Note 22-Income Taxes) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. 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 6-Derivative Instruments and Hedging Activities) and incentive compensation are excluded as the Company is not able to reasonably estimate the timing or amount of the future payments.
(5)
For further information see the note referenced below in Item 8.-Financial Statements and Supplementary Data of this Form 10-K.
The following table sets forth our Parent Company contingent contractual obligations as of December 31, 2014:
(1) Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.
As of December 31, 2014, the Company had no commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit disclosed above.
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, sponsor support and liquidated damages under power sales agreements for projects in development, in operation and under construction. In addition, we have an asset sale program through which we may have customary indemnity obligations under certain assets sale agreements. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations beyond 2014, 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.
Critical Accounting Policies and Estimates
The Consolidated Financial Statements of AES are prepared in conformity with U.S. 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’ 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:
•
the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made;
•
different estimates reasonably could have been used; or
•
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 Taxes
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 tax jurisdiction 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 amounts of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.
Because we have a wide range of statutory tax rates in the multiple jurisdictions in which we operate, any changes in our geographical earnings mix could materially impact our effective tax rate. Furthermore, our tax position could be adversely impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof and such changes may be more likely or become more likely in view of recent economic trends in certain of the jurisdictions in which we operate. For example, on December 23, 2014, the Colombian Government enacted new taxes and modifications of existing taxes to apply as of January 1, 2015. Among other impacts, income tax rates, inclusive of temporary surcharges, will be 39% in 2015, 40% in 2016, 42% in 2017 and 43% in 2018 before reverting to 34% for 2019 and beyond. The impact of these higher rates for the four year period will be material to the Company.
The Company’s provision for income taxes could be adversely impacted by changes to the U.S. taxation of earnings of our foreign subsidiaries. Since 2006, the Company has benefited from the Controlled Foreign Corporation look-through rule, originally enacted in the TIPRA of 2005. The provision has been subject to repeated temporary extensions, including the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 and the American Taxpayer Relief Act of 2012. On December 19, 2014, the Controlled Foreign Corporation look-through rule was once again retroactively reinstated to January 1, 2014 for a period of one year through the Tax Increase Prevention Act of 2014. There can be no assurance that this provision will continue to be extended beyond December 31, 2014. Accordingly, if this provision is not renewed, our expected effective tax rate could increase by amounts that may be material to the Company.
In addition, U.S. income taxes and foreign withholding taxes have not been provided on undistributed earnings for certain of our non-U.S. subsidiaries to the extent such earnings are considered to be indefinitely reinvested in the operations of those subsidiaries.
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.
Sales of Noncontrolling Interests
The accounting for a sale of noncontrolling interests under the accounting standards depends on whether the sale is considered to be a sale of in-substance real estate (as opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within stockholders’ equity. If management's estimation process determines that there is no significant value beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings. However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest would be recognized within stockholders’ equity. In-substance real estate is comprised of land plus improvements and integral equipment. The determination of whether property, plant and equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair value of the equipment as a result of those removal activities. When the combined total of removal costs and the decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is considered integral equipment. The accounting standards specifically identify power plants as an example of in-substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-substance real estate, management estimates the extent to which the total fair value of the assets of the entity is represented by the in-substance real estate and whether significant value exists beyond the in-substance real estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical accounting estimates discussed below for impairments and fair value.
Impairments
Our accounting policies on goodwill and long-lived assets are described in detail in Note 1-General and Summary of Significant Accounting Policies, included in Item 8 of this Form 10-K. The Company makes considerable judgments in its impairment evaluations of goodwill and long-lived assets; however, the fair value determination is typically the most judgmental part in an impairment evaluation.
The Company determines the fair value of a reporting unit or a long-lived asset (asset group) by applying the approaches prescribed under the fair value measurement accounting framework. Generally, the market approach and income approach are most relevant in the fair value measurement of our reporting units and long-lived assets; however, due to the lack of available relevant observable market information in many circumstances, the Company often relies on the income approach. The Company may engage an independent valuation firm to assist management with the valuation. The decision to engage an independent valuation firm considers all relevant facts and circumstances, including a cost/benefit analysis and the Company’s internal valuation knowledge of the long-lived asset (asset group) or business. The Company develops the underlying assumptions consistent with its internal budgets and forecasts for such valuations. Additionally, the Company uses an internal discounted cash flow valuation model (the “DCF model”), based on the principles of present value techniques, to estimate the fair value of its reporting units or long-lived assets under the income approach. The DCF model estimates fair value by discounting our internal budgets and cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.
Management applies considerable judgment in selecting several input assumptions during the development of our internal budgets and cash flow forecasts. Examples of the input assumptions that our budgets and forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources (e.g., Economic Intelligence Unit) and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical trends which often do not recur. The input assumptions most significant to our budgets and cash flows are based on expectations of macroeconomic factors which have been volatile recently. It is not uncommon that different market data sources have different views of the macroeconomic factors expectations and related assumptions. As a result, macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations these ranges become wide and the use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.
A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg, Capital IQ, etc.). The Company selects and uses a set of publicly traded companies from the relevant industry to estimate the discount rate inputs.
Management applies judgment in the selection of such companies based on its view of the most likely market participants. It is reasonably possible that the selection of a different set of likely market participants could produce different input assumptions and result in the use of a different discount rate.
Fair value of a reporting unit or a long-lived asset (asset group) is sensitive to both input assumptions to our budgets and cash flow forecasts and the discount rate. Further, estimates of long-term growth and terminal value are often critical to the fair value determination. As part of the impairment evaluation process, management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap between fair value and carrying amount decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment, which could be material. Our impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.
Further discussion of the impairment charges recognized by the Company can be found within Note 10-Goodwill and Other Intangible Assets, Note 21-Asset Impairment Expense and Note 9-Other Non-Operating Expense to the Consolidated Financial Statements included in Item 8 of this Form 10-K.
Fair Value
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 includes a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. For more information regarding the fair value hierarchy, see Note 1-General and Summary of Significant Accounting Policies included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K.
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”. 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 4-Fair Value included in Item 8. - Financial Statements and Supplementary Data of this Form 10-K.
Fair Value of Nonfinancial Assets and Liabilities
Significant estimates are made in determining the fair value of long-lived tangible and intangible assets (i.e., property, plant and equipment, intangible assets and goodwill) during the impairment evaluation process. In addition, the majority of assets acquired and liabilities assumed in a business combination are required to be recognized at fair value under the relevant accounting guidance. In determining the fair value of these items, management makes several assumptions discussed in the Impairments section.
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 that generated by the underlying asset or liability. See Note 6-Derivative Instruments and Hedging Activities included in Item 8 of this Form 10-K for further information on the classification.
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 fair value measurement accounting 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). 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, Reuters 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.
Regulatory Assets and Liabilities
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.
Consolidation
The Company has recently entered into several transactions whereby the Company sells an interest in its controlled subsidiaries and/or equity method investments. In connection with each transaction, the Company must determine whether the sale of the interest impacts the Company’s consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, the Company is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights.
If the entity is determined to be a variable interest entity, the most significant judgment in determining whether the Company must consolidate the entity is whether the subsidiary, including its related parties and de facto agents, collectively have power and benefits. If AES is determined to have power and benefits, the entity will be consolidated by AES.
Alternatively, if the entity is determined to be a voting model entity, the most significant judgments involve determining whether the non-AES shareholders have substantive participating rights. The assessment of shareholder rights and whether they are substantive participating rights requires significant judgment since the rights provided under shareholders’ agreements may
include selecting, terminating, and setting the compensation of management responsible for implementing the subsidiary’s policies and procedures, establishing operating and capital decisions of the entity, including budgets, in the ordinary course of business. On the other hand, if shareholder rights are only protective in nature (referred to as protective rights) then such rights would not overcome the presumption that the owner of a majority voting interest shall consolidate its investee. Significant judgment is required to determine whether minority rights represent substantive participating rights or protective rights that do not affect the evaluation of control. While both represent an approval or veto right, a distinguishing factor is the underlying activity or action to which the right relates.
New Accounting Pronouncements
The Company did not adopt any new accounting pronouncements during the year that had a material impact on the Company's financial position or results of operations. See Note 1-General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K for further information about accounting pronouncements issued but not yet effective.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks
Our businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.
These disclosures set forth in this Item 7A are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 7A. For further information regarding market risk, see Item 1A.-Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of the 2013 Form 10-K.
Commodity Price Risk
Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an un-hedged exposure on some of our capacity or through imperfect fuel pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. 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. At our generation businesses for 2015-2017, 75% to 80% of our variable margin is hedged against changes in commodity prices. At our utility businesses for 2015-2017, 90% to 95% of our variable margin is insulated from changes in commodity prices.
When hedging the output of our generation assets, we utilize contract sales that lock in the spread per MWh between variable costs and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk.
AES businesses will see changes in variable margin performance as global commodity prices shift. For 2015, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $25 million for natural gas, $10 million for oil and $10 million for coal. Our estimates exclude correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.
Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Generation costs can be directly affected by movements in the price of natural gas, oil and coal. Spot power prices and contract indexation provisions are affected by the 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. Offsets are 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, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. 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.
In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during peak periods.
In the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set power prices. In Colombia, we operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.
In the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under more extreme hydrological conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation.
In the MCAC SBU, our businesses have commodity exposure on un-hedged volumes. Panama is largely contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices.
In the Europe SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are un-hedged, the commodity risk at our Kilroot business is due to the dark spread -- the difference between electricity price and our coal-based variable dispatch cost. Natural gas-fired generators set power prices for many periods, so higher natural gas prices expand margins and higher coal prices reduce them. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, the regulator has the right to terminate the contract, which would impact our commodity exposure.
In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume sold in the spot market. 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 that mainly stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. We have varying degrees of exposure to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, 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.
We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. The largest foreign exchange risks over a twelve-month forward-looking period are stemming from the following currencies: Argentine Peso, Brazilian Real, Colombian Peso, and Euro. As of December 31, 2014, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro and Kazakhstan Tenge relative to the
U.S. Dollar are projected to be reduced by approximately less than $5 million, $15 million, less than $5 million, $10 million, $10 million and $5 million respectively, for 2015. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2015 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.
Interest Rate Risks
We are exposed to risk resulting from changes in interest rates as a result of our issuance of debt, as well as execution of interest rate swap, cap, floor and other option agreements.
Decisions on the fixed-floating debt mix 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. Most of our interest rate risk is related to non-recourse financings at our businesses.
Most of our interest rate risk is related to non-recourse financings at our businesses where in certain cases, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.
As of December 31, 2014, the portfolio’s pretax earnings exposure for 2015 to a 100-basis-point increase in interest rates for our Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Kazakhstani Tenge and U.S. Dollar denominated debt would be approximately $30 million based on the impact of a one time, 100-basis-point upward shift in interest rates on interest expense for the debt denominated in these currencies. The amounts do not take into account the historical correlation between these interest rates.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited the accompanying consolidated balance sheets of The AES Corporation as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedules listed in the index at Item 15(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also 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 at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its requirements for reporting discontinued operations as a result of the adoption of the amendments to the FASB Accounting Standards Codification resulting from Accounting Standards Update No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” effective July 1, 2014.
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, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 25, 2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
McLean, Virginia
February 25, 2015
THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2014 AND 2013
See Accompanying Notes to Consolidated Financial Statements.
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012
See Accompanying Notes to Consolidated Financial Statements.
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012
See Accompanying Notes to Consolidated Financial Statements.
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012
(1) Reclassification resulting from Silver Ridge Power transaction. See Note 8-Investments In and Advances to Affiliates for further information.
See Accompanying Notes to Consolidated Financial Statements
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012
See Accompanying Notes to Consolidated Financial Statements.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2014, 2013, AND 2012
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The AES Corporation is a holding company (the “Parent Company”) that through its subsidiaries and affiliates, (collectively, “AES” or “the Company”) operates a geographically diversified portfolio of electricity generation and distribution businesses. Generally, given this holding company structure, the liabilities of the individual operating entities are non-recourse to the parent and are isolated to the operating entities. Most of our operating entities are structured as limited liability entities, which limit the liability of shareholders. The structure is generally the same regardless of whether a subsidiary is consolidated under a voting or interest model.
PRINCIPLES OF CONSOLIDATION-The Consolidated Financial Statements of the Company include the accounts of The AES Corporation and its subsidiaries, which are the entities that it controls. Furthermore, variable interest entities (“VIEs”) in which the Company has a variable interest have been consolidated where the Company is the primary beneficiary and thus controls the VIE. Intercompany transactions and balances are eliminated in consolidation. Investments in common stock where the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.
DP&L, our utility in Ohio, has undivided interests in five generation facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro-rata basis in our consolidated financial statements. Certain expenses, primarily fuel costs for the generating units, are allocated to the joint owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies and capital additions are allocated to the joint owners in accordance with their respective ownership interests.
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 amount and estimated useful lives of long-lived assets; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of regulatory assets; the estimation of regulatory liabilities; the fair value of financial instruments; the fair value of assets and liabilities acquired in a business combination; the measurement of noncontrolling interest using the hypothetical liquidation at book value (“HLBV”) method for certain wind generation partnerships; the determination of whether a sale of noncontrolling interests is considered to be a sale of in-substance real estate (as opposed to an equity transaction); pension liabilities; environmental liabilities; and potential litigation claims and settlements.5
DISCONTINUED OPERATIONS AND RECLASSIFICATIONS-Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current presentation. Effective July 1, 2014, the Company prospectively adopted Accounting Standards Update ("ASU") No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360) Reporting discontinued Operations and Disclosures of Disposals of Components of an Entity, which significantly changes the existing accounting guidance on discontinued operations. Under ASU No. 2014-08, only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations. Amongst other changes: equity method investments that were previously scoped-out of the discontinued operations accounting guidance are now included in the scope; a business can meet the criteria to be classified as held-for-sale upon acquisition and can be reported in discontinued operations; and components where an entity retains significant continuing involvement or where operations and cash flows will not be eliminated from ongoing operations as a result of a disposal transaction can meet the definition of discontinued operations. Additionally, where summarized amounts are presented on the face of the financial statements, reconciliations of those amounts to major classes of line items are also required. ASU No. 2014-08 requires additional disclosures for individually material components that do not meet the definition of discontinued operations. Under the previous accounting guidance, the UK Wind and Ebute disposals would have met the discontinued operations criteria and would have been reclassified accordingly. See Note 24-Dispositions for further information.
Prior to July 1, 2014, a discontinued operation was a component of the Company that either had been disposed of or was classified as held for sale and where the Company did not expect to have significant cash flows from or significant continuing involvement with the component as of one year after its disposal or sale. A component was comprised of operations and cash flows that could be clearly distinguished, operationally and for financial reporting purposes, from the rest of the Company. Before the Company's adoption of ASU No. 2014-08, prior period amounts were retrospectively revised to reflect the businesses determined to be discontinued operations. For components that had been determined to be discontinued operations
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
and held for sale businesses under the old standard, the related cash flows are included within the relevant categories within operating, investing and financing activities. The aggregate amount of cash flows is offset by the net increase or decrease in cash of discontinued and held for sale businesses, which is presented as a separate line item in the Consolidated Statements of Cash Flows.
When an operation is classified as held for sale, the Company recognizes impairment expense, if any, at the consolidated financial statement level which also includes noncontrolling interests. However, any gain or loss on the completion of a disposal transaction is recognized only for the Company's ownership interest. Upon adoption of ASU No. 2014-08 on July 1, 2014, the Company no longer recasts prior period results related to operations classified as held for sale. Prior to July 1, 2014, when reclassifications were made in the current period, the amounts reported in the prior period financial statements were reclassified to conform to the then-current year presentation. The reclassifications related primarily to general and administrative costs at certain of the Company's SBUs that were previously classified as "general and administrative expenses" that were reclassified to "cost of sales."
FAIR VALUE-Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly, hypothetical transaction between market participants at the measurement date, or exit price. The Company applies the fair value measurement accounting guidance to financial assets and liabilities in determining the fair value of 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 Company applies the fair value measurement guidance to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of a potential impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill.
The Company makes assumptions about what market participants would assume in valuing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the subsidiary (for liabilities) and of the counterparty (for assets). The Company is prohibited from including transaction costs and any adjustments for blockage factors in determining fair value. The principal or most advantageous market is considered from the perspective of the subsidiary owning the asset or with the liability.
Fair value is based on observable market prices where available. Where they are not available, specific valuation models and techniques are applied depending on what is being fair valued. These models and techniques 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 price transparency and complexity. An asset's or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:
•
Level 1-unadjusted quoted prices in active markets accessible by the Company for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
•
Level 2-pricing inputs other than quoted market prices included in Level 1 which are based on observable market data, that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from observable market data by correlation or other means.
•
Level 3-pricing inputs that are unobservable from objective sources. Unobservable inputs are only used to the extent observable inputs are not available. These inputs maintain the concept of an exit price from the perspective of a market participant and reflect assumptions of other market participants. The Company considers 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.
Any transfers between all levels within the fair value hierarchy levels are recognized at the end of the reporting period.
CASH AND CASH EQUIVALENTS-The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit and short-term marketable securities that mature within three months or less from the date of purchase to be cash and cash equivalents. The carrying amounts of such balances approximate fair value.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
RESTRICTED CASH AND DEBT SERVICE RESERVES-These include cash balances which are restricted as to withdrawal or usage by the subsidiary that owns the cash. The nature of restrictions includes restrictions imposed by financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves and others, as well as restrictions imposed by long-term PPAs.
INVESTMENTS IN MARKETABLE SECURITIES-The Company’s marketable investments are primarily unsecured debentures, certificates of deposit, government debt securities and money market funds. Short-term investments in marketable debt and equity securities consist of securities with original maturities in excess of three months with remaining maturities of less than one year.
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 fair valued at the end of each reporting period where the unrealized gains or losses are reflected in accumulated other comprehensive loss (“AOCL”), a separate component of equity.
Investments classified as trading are fair valued at the end of each reporting period 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.
ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS-Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable, considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectible amount as appropriate. Certain of our businesses charge interest on accounts receivable either under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. When the collection of such interest is not reasonably assured, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectible.
INVENTORY-Inventory primarily consists of coal, fuel oil and other raw materials used to generate power, and spare parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost or market. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. Cost is determined under the first-in, first-out (“FIFO”), average cost or specific identification method. Generally, cost is reduced to market value if the market value of inventory has declined and it is probable that the utility of inventory, in its disposal in the ordinary course of business, will not be recovered through revenue earned from the generation of power.
LONG-LIVED ASSETS-Long-lived assets include property, plant and equipment, assets under capital leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).
Property, plant and equipment
Property, plant and equipment are stated at cost, net of accumulated depreciation. The cost of renewals and improvements that extend the useful life of property, plant and equipment are capitalized.
Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the project is deemed probable, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Construction-in-progress balances are transferred to electric generation and distribution assets when an asset group is ready for its intended use. Government subsidies, liquidated damages recovered for construction delays and income tax credits are recorded as a reduction to property, plant and equipment and reflected in cash flows from investing activities.
Depreciation, after consideration of salvage value and asset retirement obligations, is computed primarily using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Maintenance and repairs are charged to expense as incurred. Capital spare parts, including rotable spare parts, are included in electric generation and distribution assets. If the spare part is considered a component, it is depreciated over its useful life after the part is placed in service. If the spare part is deemed part of a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The Company’s Brazilian subsidiaries, which include both generation and distribution companies, operate under concession contracts. Certain estimates are utilized to determine depreciation expense for the Brazilian subsidiaries, including the useful lives of the property, plant and equipment and the amounts to be recovered at the end of the concession contract. The amounts to be recovered under these concession contracts are based on estimates that are inherently uncertain and actual amounts recovered may differ from those estimates.
Intangible Assets Subject to Amortization
Finite-lived intangible assets are amortized over their useful lives which range from 1 - 50 years. The Company accounts for purchased emission allowances as intangible assets and records an expense when utilized or sold. Granted emission allowances are valued at zero.
Impairment of Long-lived Assets
When circumstances indicate that the carrying amount of long-lived assets (asset group) held-for-use may not be recoverable, the Company evaluates the assets for potential impairment using internal projections of undiscounted cash flows expected to result from the use and eventual disposal of the assets. Events or changes in circumstances that may necessitate a recoverability evaluation may include, but are not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, or an expectation that it is more likely than not that the asset will be disposed of before the end of its previously estimated useful life. If the carrying amount of the assets exceeds the undiscounted cash flows and exceeds any fair value of the assets, an impairment expense is recognized for the excess up to the carrying amount of the long-lived assets (but up to any fair value for any individual long-lived asset that is determinable without undue cost and effort). For regulated assets, an impairment expense could be reduced by the establishment of a regulatory asset, if recovery through approved rates was probable. For non-regulated assets, impairment is recognized as an expense. When long-lived assets meet the criteria to be classified as held-for-sale and the carrying amount of the disposal group exceeds its fair value less costs to sell, an impairment expense is recognized for the excess up to the carrying amount of the long-lived assets; if the fair value of the disposal group subsequently exceeds the carrying amount while the disposal group is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the prior expense or the subsequent excess.
DEFERRED FINANCING COSTS-Costs incurred in connection with the issuance of long-term debt 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 financing activities.
EQUITY METHOD INVESTMENTS-Investments in entities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in “Investments in and advances to affiliates” on the Consolidated Balance Sheets. The Company periodically assesses if there is an indication that the fair value of an equity method investment is less than its carrying amount. When an indicator exists, any excess of the carrying amount over 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” in the Consolidated Statements of Operations.
The Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the equity method if the investee subsequently reports net income to the extent that the Company’s share of such net income equals the share of net losses not recognized during the period in which the equity method of accounting was suspended.
GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS-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 1.
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 a component (i.e., one level below an operating segment). In determining its reporting units, the Company starts with its management reporting structure. Operating segments are identified and then analyzed to identify components which make up these operating segments. Two or more components are combined into a single reporting unit if they are economically similar. Assets and liabilities are allocated to a reporting unit if the assets will be employed by or a liability relates to the operations of the reporting unit or would be considered by a market participant in determining its fair value. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
from the synergies of the acquisition. Generally, each AES business with a goodwill balance constitutes a reporting unit as they are not reported to segment management together with other businesses and are not similar to other businesses in a segment.
Goodwill is evaluated for impairment either under the qualitative assessment option or the two-step test approach depending on facts and circumstances of a reporting unit, including the excess of fair value over carrying amount in the last valuation or changes in business environment. If the Company qualitatively determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. Otherwise, goodwill is evaluated for impairment using the two-step test, where the carrying amount of a reporting unit is compared to its fair value in Step 1; if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations (which in some cases may be based in part on third party valuation reports), or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss.
Most of the Company’s reporting units are not publicly traded. Therefore, the Company estimates the fair value of its reporting units using internal budgets and forecasts, adjusted for any market participants’ assumptions and discounted at the rate of return required by a market participant. The Company considers both market and income-based approaches to determine a range of fair value, but typically concludes that the value derived using an income-based approach is more representative of fair value due to the lack of direct market comparables. The Company does use market data to corroborate and determine the reasonableness of the fair value derived from the income-based discounted cash flow analysis.
Indefinite-Lived Intangible Assets
The Company’s indefinite-lived intangible assets primarily include land-use rights, water rights, easements, concessions and trade name. These are tested for impairment on an annual basis or whenever events or changes in circumstances necessitate an evaluation for impairment. If the carrying amount of an intangible asset exceeds its fair value, the excess is recognized as impairment expense. When deemed appropriate, the Company uses the qualitative assessment option under the accounting guidance on goodwill and intangible assets to determine whether the existence of events or circumstances indicate that it is more likely than not that an intangible asset is impaired. If, after assessing the totality of events and circumstances, the Company determines that it is not more likely than not that an intangible asset is impaired, no further action is taken. The accounting guidance provides the option to bypass the qualitative assessment for any intangible asset in any period and proceed directly to performing the quantitative impairment test.
ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES-Accounts payable consists of amounts due to trade creditors related to the Company’s core business operations. These payables include amounts owed to vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and employee-related costs including payroll, benefits and related taxes.
REGULATORY ASSETS AND LIABILITIES-The Company 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 related regulatory assets are written off and recognized in income from continuing operations.
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 AOCL, except for those plans at certain of the Company’s regulated utilities that can recover portions of their pension and postretirement obligations through future rates. 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.
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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
ASSET RETIREMENT OBLIGATIONS-The Company records the fair value of the liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
NONCONTROLLING INTERESTS-Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income in the Consolidated Statements of Operations and Consolidated Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests (unless the transaction qualifies as a sale of in-substance real estate). Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero.
Although, in general, the noncontrolling ownership interest in earnings is calculated based on ownership percentage, certain of the Company’s businesses are subject to certain profit-sharing arrangements. These agreements exist for Wind Generation partnerships to designate different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership. For these businesses, the Company uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. HLBV uses a balance sheet approach, which measures the Company’s equity in income or loss by calculating the change in the amount of net worth the partners are legally able to claim based on a hypothetical liquidation of the entity at the beginning of a reporting period compared to the end of that period.
FOREIGN CURRENCY TRANSLATION-A business’ functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the U.S. Dollar translate their assets and liabilities into U.S. Dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. Dollars at the average exchange rates that prevailed during the period. Translation adjustments are included in AOCL. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in AOCL. 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. Accumulated foreign currency translation adjustments are reclassified to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. The accumulated adjustments are included in carrying amounts in impairment assessments where the Company has committed to a plan that will cause the accumulated adjustments to be reclassified to earnings.
REVENUE RECOGNITION-Revenue from utilities is classified as regulated in 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. The Company has businesses where it sells and purchases 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 from generation businesses 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. Certain of the Company PPAs meet the definition of an operating lease or contain similar arrangements. Typically, minimum lease payments from such PPAs are recognized as revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned. 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 expense is based on the grant-date fair value of the equity or liability instrument issued and is recognized 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.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
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 corporate business development efforts are classified as general and administrative expenses.
DERIVATIVES AND HEDGING ACTIVITIES-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. See the Company’s fair value policy and Note 4-Fair Value for additional discussion regarding the determination of the fair value. The PPAs and fuel supply agreements entered into by the Company are evaluated to determine if they meet the definition of a derivative or contain embedded derivatives, either of which require separate valuation and accounting. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could then be net settled and meet the definition of a derivative.
Derivatives primarily consist of interest rate swaps, cross-currency swaps, foreign currency instruments, and commodity derivatives. The Company enters into various derivative transactions in order to hedge its exposure to certain market risks, primarily interest rate, foreign currency and commodity price risks. Regarding interest rate risk, the Company and our subsidiaries generally utilize variable rate debt financing for construction projects and operations so interest rate swap, lock, 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 and are typically designated as cash flow hedges. Regarding foreign currency risk, we are exposed to it as a result of our investments in foreign subsidiaries and affiliates that may be impacted by significant fluctuations in foreign currency exchange rates so foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to these fluctuations. Cross-currency swaps are utilized in certain instances to manage the risk related to fluctuations in both interest rates and certain foreign currencies. In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives as a portion of the contracts is denominated in a currency other than the functional or local currency of that subsidiary or the currency of the item. Regarding commodity price risk, we are exposed to the impact of market fluctuations in the price of electricity, fuel and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions (which provide our distribution businesses with a franchise to serve a specific geographic region), a portion of our current and expected future revenues are derived from businesses without significant long-term purchase or sales contracts. We use an overall hedging strategy, not just derivatives, to hedge our financial performance against the effects of fluctuations in commodity prices.
The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. The Company only has cash flow 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 AOCL and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is recognized in earnings immediately. For all designated and qualifying hedges, 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 no longer 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 AOCL into earnings.
While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting. Changes in the fair value of derivatives not designated and qualifying as cash flow hedges are immediately recognized in earnings. Regardless of when gains or losses on derivatives (including all those where the fair value measurement is classified as Level 3) are recognized in earnings, they are generally classified as follows: interest expense for interest rate and cross-currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity and other derivatives. However, gains and losses on interest rate and cross-currency derivatives are classified as foreign currency transaction gains and losses if they offset the remeasurement of the foreign currency-denominated debt being hedged by the cross-currency swaps and the amount reclassified from AOCL to cost of sales to offset depreciation where the variable-rate interest capitalized as part of the asset was hedged during its construction. Cash flows arising from derivatives are included in the Consolidated Statements of Cash Flows as an operating activity given
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
the nature of the underlying risk being economically hedged and the lack of significant financing elements, except that cash flows on designated and qualifying hedges of variable-rate interest during construction are classified as an investing activity.
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.
NEW ACCOUNTING PRONOUNCEMENTS ADOPTED
ASU No. 2013-11, Income Taxes (Topic 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a consensus of the FASB Emerging Issues Task Force)
Effective January 1, 2014, the Company prospectively adopted ASU No. 2013-11, which requires the netting of unrecognized tax benefits (“UTBs”) against a deferred tax asset for a loss or other carryforward that would apply in settlement of uncertain tax positions. Under ASU No. 2013-11, UTBs are netted against all available same-jurisdiction losses or other tax carryforwards that would be utilized, rather than only against carryforwards that are created by the UTBs. The impact to the Company’s Condensed Consolidated Balance Sheet as of December 31, 2014 was a reduction of $66 million to “Other noncurrent liabilities” and an offsetting increase to “Deferred income taxes” under “Noncurrent liabilities.” There were no impacts on the results of operations and cash flows.
ASU No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360) Reporting discontinued Operations and Disclosures of Disposals of Components of an Entity
Effective July 1, 2014, the Company prospectively adopted ASU No. 2014-08. See the "Discontinued Operations and Reclassifications" policy above for further information.
ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET EFFECTIVE-The following accounting standards have been issued, but are not yet effective for, and have not been adopted by AES.
ASU No. 2014-05, Service Concession Arrangements (Topic 853)
In January 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-5 which states that certain service concession arrangements with public-sector entity grantors are not in scope of ASC 840, Leases ("ASC 840"). A service concession arrangement is described as an arrangement between a public-sector entity grantor and an operating entity. Operating entities with these types of arrangements with public-sector entities will no longer account for these arrangements as a lease in accordance with ASC 840 and will not recognize the related infrastructure as property, plant and equipment. Entities will apply other GAAP to the arrangement. The standard is effective for annual reporting periods beginning after December 15, 2014 and interim periods therein. The guidance will be applied on a modified retrospective basis to service concession arrangements in existence at January 1, 2015. The Company is currently evaluating the impact of the new guidance and has identified certain of its generation plants that meet the criteria of a concession arrangement under this standard. Upon adoption of this standard, the Company currently expects that the impact to the Company’s Consolidated Balance Sheet as of January 1, 2015 will result in a reclassification of approximately $1.5 billion from Property, Plant and Equipment to Other Noncurrent Assets.
ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09 which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard is effective for annual reporting periods beginning after December 15, 2016 and interim periods therein. Early adoption is not permitted. The standard permits the use of either a full retrospective or modified retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of adopting the standard on its financial position and results of operations.
ASU No. 2014-12, Compensation - Stock Compensation (Topic 718)
In June 2014, the FASB issued ASU No. 2014-12 which is intended to resolve the diverse accounting treatment in practice with compensation awards. The objective of the new standard is to clarify the treatment of accounting for performance targets which affect award vesting. The standard is effective for annual reporting periods beginning after December 15, 2015
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
and interim periods therein. Early adoption is permitted. The standard permits the use of either a prospective or modified retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of the standard on its financial position and results of operations, but does not expect to be materially impacted.
ASU No. 2014-12, Consolidation - Amendments to Consolidation Analysis (Topic 810)
In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of the standard on its consolidated financial statements.
2. INVENTORY
Inventory is valued primarily using the average-cost method. The following table summarizes the Company’s inventory balances as of the dates indicated:
3. PROPERTY, PLANT AND 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. The amounts are stated net of impairment losses recognized as further discussed in Note 21-Asset Impairment Expense.
(1)
Net electric generation and distribution assets and other related to the Company's held-for-sale businesses of $1.2 billion as of December 31, 2013, were excluded from the table above and were included in the noncurrent assets of discontinued and held-for-sale businesses in the consolidated balance sheets. There were no discontinued and held-for-sale businesses at December 31, 2014.
(2)
Net electric generation and distribution assets and other include unamortized internal-use software costs of $115 million and $133 million as of December 31, 2014 and 2013, respectively.
The following table summarizes depreciation expense (including the amortization of assets recorded under capital leases), amortization of internal-use software and interest capitalized during development and construction on qualifying assets for the periods indicated:
Property, plant and equipment, net of accumulated depreciation, of $15 billion and $15 billion was mortgaged, pledged or subject to liens as of December 31, 2014 and 2013, respectively.
The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation as of the periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The following table summarizes the amounts recognized related to asset retirement obligations for the periods indicated:
The Company’s asset retirement obligations covered by the relevant guidance primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plants and equipment. There were no legally restricted assets for purposes of settling asset retirement obligations for the years ended December 31, 2014 and 2013.
Ownership of Coal-Fired Facilities
DP&L has undivided ownership interests in five coal-fired generation facilities jointly owned with other utilities. As of December 31, 2014, DP&L had $25 million of construction work in process at such facilities. DP&L’s share of the operating costs of such facilities is included in Cost of Sales in the Consolidated Statements of Operations and its share of investment in the facilities is included in Property, Plant and Equipment in the Consolidated Balance Sheets. DP&L’s undivided ownership interest in such facilities at December 31, 2014 is as follows:
4. FAIR VALUE
The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. 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.
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 current market expectations of the return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and emissions allowances, etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, the value estimated under the income approach is often the most representative of fair value.
Investments
The Company’s investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are measured at fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
instruments are generally indexed to the CDI (Brazilian equivalent to London Inter Bank Offered Rate, or LIBOR, a benchmark interest rate widely used by banks in the interbank lending market) or Selic (overnight borrowing rate) rates in Brazil. Fair value is determined from comparisons to market data obtained for similar assets and are considered Level 2 in the fair value hierarchy. For more detail regarding the fair value of investments see Note 5-Investments in Marketable Securities.
Derivatives
Any Level 1 derivative instruments are exchange-traded commodity futures for which the pricing is observable in active markets, and as such, these are not expected to transfer to other levels. There have been no transfers between Level 1 and Level 2.
For all derivatives, with the exception of any classified as Level 1, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published information provided from another source. When significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis or prices for similarly traded instruments available in the market.
For derivatives for which there is a standard industry valuation model, the Company uses a third-party treasury and risk management software product that uses a standard model and observable inputs to estimate the fair value. For these derivatives, the Company performs analytical procedures and makes comparisons to other third-party information in order to assess the reasonableness of the fair value. For derivatives for which there is not a standard industry valuation model (such as PPAs and fuel supply agreements that are derivatives or include embedded derivatives), the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. At each quarter-end, the models for the commodity and foreign currency-based derivatives are generally prepared and reviewed by employees who globally manage the respective commodity and foreign currency risks and are analytically reviewed independent of those employees.
Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR). The Company then makes a credit valuation adjustment (“CVA”) by further discounting the cash flows for nonperformance or credit risk based on the observable or estimated debt spread of the Company’s subsidiary or its counterparty and the tenor of the respective derivative instrument. The CVA for asset positions is based on the counterparty’s credit ratings, credit default swap spreads, and debt spreads, as available. The CVA for liability positions is based on the Parent Company’s or the subsidiary’s current debt spread. In the absence of readily obtainable credit information, the Parent Company’s or the subsidiary’s estimated credit rating (based on applying a standard industry model to historical financial information and then considering other relevant information) and spreads of comparably rated entities or the respective country’s debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.
The Company’s methodology to fair value its derivatives is to start with any observable inputs; however, in certain instances the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. In addition, in certain instances, there may not be market or market-corroborated data readily available, requiring the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are classified as Level 3 when the use of unobservable inputs is significant. When the use of unobservable inputs is insignificant, assets and liabilities are classified as Level 2. Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and result from changes in significance of unobservable inputs used to calculate the CVA.
Debt
Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon the type of loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow analyses. In the discounted cash flow analysis, the discount rate is based on the credit rating of the individual debt instruments, if available, or the credit rating of the subsidiary. If the subsidiary’s credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry-specific factors. For subsidiaries located outside the U.S., in the event that the country rating is lower than the credit rating previously determined, the country rating is used for purposes of the discounted cash flow
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date. The fair value was determined using available market information as of December 31, 2014. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to December 31, 2014.
Nonfinancial Assets and Liabilities
For nonrecurring measurements derived using the income approach, fair value is determined using valuation models based on the principles of discounted cash flows (“DCF”). The income approach is most often used in the impairment evaluation of long-lived tangible assets, goodwill and intangible assets. The Company uses its internally developed DCF valuation models as the primary means to determine nonrecurring fair value measurements though other valuation approaches prescribed under the fair value measurement accounting guidance are also considered. Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management in the valuation process. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates and power and commodity prices. Whenever possible, the Company attempts to obtain market observable data to develop input assumptions. Where the use of market observable data is limited or not available for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations.
For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to identify sale transactions of identical or similar assets. This approach is used in impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.
For nonrecurring measurements derived using the cost approach, fair value is typically based upon a replacement cost approach. Under this approach, the depreciated replacement cost of assets is derived by first estimating the current replacement cost of assets and then applying the remaining useful life percentages to such costs. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach.
Fair Value Considerations
In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company’s or its counterparty’s nonperformance. The conditions and criteria used to assess these factors are:
Sources of market assumptions
The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Reuters). To determine fair value, where market data is not readily available, management uses comparable market sources and empirical evidence to develop its own estimates of market assumptions.
Market liquidity
The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company’s current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of assets traded without significantly affecting the market price. Another factor the Company considers when determining whether a market is active or inactive is the presence of government or regulatory controls over pricing that could make it difficult to establish a market-based price when entering into a transaction.
Nonperformance risk
Nonperformance risk refers to the risk that an 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 its counterparty’s credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives, which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.
Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from quoted market data to mark the investments to fair value.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
Recurring Measurements
The following table sets forth, by level within the fair value hierarchy, as described in Note 1 - General and Summary of Significant Accounting Policies, the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of the periods indicated:
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(1)
Amortized cost approximated fair value at December 31, 2014 and 2013.
The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2014 and 2013 (presented net by type of derivative). Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) as of December 31, 2014:
Changes in the above significant unobservable inputs that lead to a significant and unusual impact to current-period earnings are disclosed to the Financial Audit Committee. For interest rate derivatives, and embedded foreign currency derivatives, increases (decreases) in the estimates of the Company's own credit spreads would decrease (increase) the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the estimate of the above exchange rate would increase (decrease) the value of the derivative.
Nonrecurring Measurements
When evaluating impairment of goodwill, long-lived assets, discontinued operations and held-for-sale businesses, and equity method investments, the Company measures fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to their then-latest available carrying amount. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
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(1)
Represents the carrying value at the date of measurement, before fair value adjustment.
(2)
See Note 21-Asset Impairment Expense and Note 24-Dispositions for further information.
(3)
See Note 23-Discontinued Operations and Held-For-Sale Businesses for further information. Fair value of long-lived assets held-for-sale exclude costs to sell.
(4)
See Note 9-Other Non-Operating Expense for further information.
The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the year ended December 31, 2014:
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
The following table sets forth the carrying amount, fair value and fair value hierarchy of the Company’s financial assets and liabilities that are not measured at fair value in the consolidated balance sheets as of December 31, 2014 and 2013, but for which fair value is disclosed.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
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(1)
These accounts receivable principally relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and are included in “Noncurrent assets - Other” in the accompanying consolidated balance sheets. The fair value of these accounts receivable excludes value-added tax of $36 million and $46 million at December 31, 2014 and 2013, respectively.
5. INVESTMENTS IN MARKETABLE SECURITIES
The Company’s investments in marketable debt and equity securities as of December 31, 2014 and 2013 by security class and by level within the fair value hierarchy have been disclosed in Note 4-Fair Value. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities. As of December 31, 2014, $676 million of available-for-sale ("AFS") debt securities had stated maturities within one year and $33 million had stated maturities between one and three years. Gains and losses on the sale of investments are determined using the specific-identification method. Pretax gains and losses related to AFS and trading securities are generally immaterial for disclosure purposes. For the years ended December 31, 2014, 2013, and 2012, there were no realized losses on the sale of AFS securities and no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income. The following table summarizes the gross proceeds from sale of AFS securities for the years ended December 31, 2014, 2013, and 2012:
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Volume of Activity
The following tables set forth, by type of derivative, the Company’s outstanding notional under its derivatives and the weighted-average remaining term as of December 31, 2014 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:
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(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, 2014 and the maturity of the derivative instrument, which includes forward-starting derivative instruments. The interest rate and cross currency derivatives range in maturity through 2033 and 2028, respectively.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
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(1)
Represents contractual notionals. The notionals for options have not been probability adjusted, which generally would decrease them.
(2)
Represents the remaining tenor of our foreign currency derivatives weighted by the corresponding notional. These options and forwards and these embedded derivatives range in maturity through 2025 and 2017, respectively.
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(1)
Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2016.
Accounting and Reporting
Assets and Liabilities
The following tables set forth the Company’s derivative instruments as of the periods indicated, first by whether or not they are designated hedging instruments, then by whether they are current or noncurrent to the extent they are subject to master netting agreements or similar agreements (where the rights to set-off relate to settlement of amounts receivable and payable under those derivatives) and by balances no longer accounted for as derivatives.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
Effective Portion of Cash Flow Hedges
The following tables set forth the pretax gains (losses) recognized in AOCL and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships (including amounts that were reclassified from AOCL as interest expense related to interest rate derivative instruments that previously, but no longer, qualify for cash flow hedge accounting), as defined in the accounting standards for derivatives and hedging, for the periods indicated:
The pretax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of December 31, 2014 is $(100) million for interest rate hedges, $(4) million for cross currency swaps, $9 million for foreign currency hedges, and $18 million for commodity and other hedges.
For the years ended December 31, 2014 and 2012, pretax losses of $6 million and $10 million, net of noncontrolling interests 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. There was no such item for the year ended December 31, 2013.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
Ineffective Portion of Cash Flow Hedges
The following table sets forth the pretax 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 periods indicated:
Not Designated for Hedge Accounting
The following table sets forth the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging and the amortization of balances that had been, but are no longer, accounted for as derivatives, for the periods indicated:
Credit Risk-Related Contingent Features
DP&L has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require DP&L to maintain an investment-grade issuer credit rating from credit rating agencies. Since DP&L's rating has fallen below investment grade, certain of the counterparties to the derivative contracts have requested immediate and ongoing full overnight collateralization of the mark-to-market loss (fair value excluding credit valuation adjustments), which was $12 million and $11 million as of December 31, 2014 and 2013, respectively, for all derivatives with credit risk-related contingent features. As of December 31, 2014 and 2013, DP&L had posted $5 million and $6 million, respectively, of cash collateral directly with third parties and in a broker margin account and DP&L held $0 million and $3 million, respectively, of cash collateral from counterparties to its derivative instruments that were in an asset position. After consideration of the netting of counterparty assets, DP&L could have been required to, but did not, provide additional collateral of $1 million and $0 million as of December 31, 2014 and 2013, respectively.
7. FINANCING RECEIVABLES
Financing receivables are defined as receivables that have contractual maturities of greater than one year. The Company has financing receivables pursuant to amended agreements or government resolutions that are due from certain Latin American governmental bodies, primarily in Argentina. The table below sets forth the breakdown of financing receivables by country as of the periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
_____________________________
(1)
As of December 31, 2014 all amounts had contractual maturities of greater than one year. As of December 31, 2013, total receivables with the Argentine government were $286 million, and the amount presented in the table above excluded noncurrent receivables of $122 million which had not yet been converted into financing receivables and did not have contractual maturities of greater than one year at the time.
Argentina-Collection of the principal and interest on these receivables is subject to various business risks and uncertainties including, but not limited to, the completion and operation of power plants which generate cash for payments of these receivables, regulatory changes that could impact the timing and amount of collections, and economic conditions in Argentina. The Company monitors these risks including the credit ratings of the Argentine government on a quarterly basis to assess the collectability of these receivables. The Company accrues interest on these receivables once the recognition criteria have been met. The Company’s collection estimates are based on assumptions that it believes to be reasonable, but are inherently uncertain. Actual future cash flows could differ from these estimates.
FONINVEMEM Agreements
As a result of energy market reforms in 2004 and 2010, AES Argentina entered into three agreements with the Argentine government, referred to as the FONINVEMEM Agreements, to contribute a portion of their accounts receivable into a fund for financing the construction of combined cycle and gas-fired plants. These receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In addition, AES Argentina receives an ownership interest in these newly built plants once the receivables have been fully repaid.
FONINVEMEM I and II - The receivables under the first two FONINVEMEM Agreements have been actively collected since the related plants commenced operations in 2010. In assessing the collectability of the receivables under these agreements, the Company also considers how timely the collections have historically been made in accordance with the agreements.
FONINVEMEM III - The receivables related to the third FONINVEMEM Agreement will not be repaid until commercial operation of the related gas-fired plant has been achieved. In assessing the collectability of the receivables under this agreement, the Company also considers the extent to which significant milestones necessary to complete the plants have been achieved or are still probable. In November 2014, the Company received a letter from CAMMESA confirming the contribution of certain receivables into the FONIVEMEM III Agreement and establishing the methodology for the interest to be recognized on the outstanding receivables. CAMMESA is the Argentine wholesale electricity market regulator responsible for dispatch coordination and determination of short-term prices. Based on this new information, additional receivables of $120 million were considered formally contributed into FONIVEMEM III trust in the fourth quarter of 2014. Additionally, upon receipt of the letter, the Company determined that the recognition criteria was met related to the interest on all the FONIVEMEM III receivables and accordingly, recognized $59 million of interest income in the fourth quarter of 2014.
The FONINVEMEM receivables are denominated in Argentine pesos, but indexed to U.S. Dollars, which represents a foreign currency derivative. During the fourth quarter of 2014, the value of the foreign currency derivative experienced a significant increase due to CAMMESA confirming that additional receivables would be included in the FONINVEMEM III project as well as the recognition of interest on all the FONINVEMEM III receivables. As a result, an unrealized foreign currency gain of $106 million was recognized in earnings. As of December 31, 2014 and 2013, the amount of the foreign currency-related derivative assets associated with the FONINVEMEM financing receivables that were excluded from the table above had a fair value of $208 million and $97 million, respectively.
Other Agreements
In 2013, Resolution No. 95/2013 ("Resolution 95") which developed a new energy regulatory framework that applies to all generation companies with certain exceptions became effective. The new regulatory framework remunerates fixed and variable costs plus a margin that will depend on the technology and fuel used to generate the electricity and the installed capacity of each plant.
In the fourth quarter of 2014, the Argentine government passed a resolution to contribute outstanding Resolution 95 receivables into a trust whereby AES Argentina has committed to install 93 MW of capacity into the system. CAMMESA will finance the investment utilizing the outstanding receivables as a guarantee.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
8. 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 the periods indicated.
(1)
Represent VIEs in which the Company holds a variable interest but is not the primary beneficiary.
(2)
The Company's ownership in Guacolda is held through AES Gener, a 71%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 35%.
(3)
OPGC has one coal-fired expansion project under development with a total capacity of 1,320 MW. The project started construction in April 2014 and is currently expected to begin operations in 2018. As of December 31, 2014, total capitalized costs at the project level were $186 million (AES share of $91 million).
Silver Ridge Power
On July 1, 2014, the Puerto Rico solar business, Solar Power PR, LLC, was distributed by Silver Ridge Power, LLC (“SRP”) to AES and Riverstone Holdings LLC and is now accounted for as a direct equity method investment. On July 2, 2014, the Company closed the sale of its 50% ownership interest in SRP for a purchase price of $179 million, excluding the Company’s indirect ownership interests in SRP’s solar generation businesses in Italy and Spain. The buyer also has an option to purchase the Company's indirect 50% interest in the Italy solar generation business for an additional consideration of $42 million by August 2015.
Currently, this transaction does not qualify as a sale for accounting purposes as the Company has continuing involvement in the business operations. Once the Company ceases its involvement in SRP's business operations, the transaction will then be considered a sale of real estate. As of July 2, 2014, the Company no longer retained an equity interest in SRP. As such, the then- remaining investment balance of $32 million related to Italy and Spain and the AOCL balance of $40 million were reclassified to "Other noncurrent assets" on the Consolidated Balance Sheets. As of December 31, 2014, the carrying value of these investments recorded in Other noncurrent assets was $64 million.
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. Due to 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, 2014 and 2013, other long-term liabilities included $52 million and $55 million related to this debt agreement.
Elsta
In 2014, long lived assets within Elsta were determined to not be recoverable and an impairment charge of approximately$82 million was recognized. The Company recognized its 50% share, or $41 million, through its proportion of the equity earnings in Elsta.
During 2013 the Company recognized a $129 million other-than-temporary impairment of its investment in the Elsta JV. For additional information see Note 9-Other Non-Operating Expense.
Entek
In September 2014, the Company executed an agreement, subject to the approval of the Company’s Board of Directors, to sell its equity interest in AES Entek. Based on this agreement, during the third quarter of 2014, the Company determined there was an other-than-temporary decline in the fair value of its equity method investment in AES Entek and recognized a pretax impairment loss of $18 million in other non-operating expense. On October 13, 2014, the Company entered into a binding agreement to sell its 49.62% ownership interest in Entek for a purchase price of $125 million. This resulted in the recognition of an additional other-than-temporary impairment of $68 million due to the inclusion of the cumulative translation adjustment in
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
the carrying value of the investment. For additional information see Note 9-Other Non-Operating Expense. The sale represents 100% of the Company's interest in assets in Turkey. On December 18, 2014, the transaction closed which resulted in a final loss on sale of $4 million. Entek does not meet the criteria to be reported as discontinued operations under ASU No. 2014-08, which was adopted by the Company on July 1, 2014. Accordingly, AES' proportion of Entek's results are reflected in the Consolidated Statements of Operations within continuing operations. Excluding the loss on sale, Entek's pretax loss attributable to AES was $9 million, $29 million and $12 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Guacolda
On April 11, 2014, AES Gener undertook a series of transactions, pursuant to which AES Gener acquired the interests that it did not previously own in Guacolda for $728 million and simultaneously sold the ownership interest to Global Infrastructure Partners ("GIP") for $730 million. The transaction provided GIP with substantive participating rights in Guacolda and, as a result, the Company continues to account for its investment in Guacolda using the equity method of accounting. At no time during this transaction did the Company acquire a non-controlling interest. The cash paid for the acquisition is reflected in "Acquisitions, net of cash acquired" and the cash proceeds from the sale of these ownership interests to GIP is reflected in "Proceeds from the sale of businesses, net of cash sold" on the Consolidated Statement of Cash Flows for the period ended December 31, 2014.
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, 2014, retained earnings included $159 million related to the undistributed earnings of the Company’s 50%-or-less owned affiliates. Distributions received from these affiliates were $28 million, $6 million, and $22 million for the years ended December 31, 2014, 2013, and 2012, respectively. As of December 31, 2014, the aggregate carrying amount of our investments in equity affiliates exceeded the underlying equity in their net assets by $203 million.
9. OTHER NON-OPERATING EXPENSE
Entek - During 2014, the Company executed an agreement to sell its 49.62% equity interest in AES Entek for $125 million. AES Entek consists of 364 MW of natural gas and hydroelectric generation facilities, plus a coal-fired development project. The Company also determined that there was an other-than-temporary decline in the fair value of its equity method investment in AES Entek and recognized pretax impairment losses of $86 million in other non-operating expense. The sale of
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
the Company's interest in Entek closed on December 18, 2014. See Note 8-Investments in and Advances to Affiliates, of this Form 10-K for further information.
Silver Ridge - During 2014, the Company determined that there was a decline in the fair value of its equity method investment in SRP that was other-than-temporary based on indications about the fair value of the projects in Italy and Spain that resulted from actual and proposed changes to their tariffs. For 2014, the Company has recognized a pretax impairment loss of $42 million in other non-operating expense. The transaction related to our 50% ownership interest in SRP closed on July 2, 2014 for $179 million. See Note 8-Investments in and Advances to Affiliates, of this Form 10-K for further information.
Elsta - Elsta BV & Co CV ("Elsta"), a 630 MW combined cycle gas-fired plant in the Netherlands, is accounted for under the equity method of accounting. During 2013, the Company identified an impairment indicator resulting from initial negotiations with Elsta's offtakers for an extension of the existing PPA which expires during 2018, suggesting that the income earned under the existing PPA would likely be reduced upon an extension and that the resulting decline in the estimated fair value of the Company's equity method investment in Elsta was other-than-temporary. The Company recognized an impairment of $129 million by reducing the carrying value of $240 million to the estimated fair value of $111 million. The Company estimated fair value using probability-weighted outcomes which contemplated various scenarios involving the amendments to the existing PPA.
China Generation and InnoVent - In the first quarter of 2012, the Company concluded that it was more likely than not that it would sell its interest in its equity method investments in China and France and recorded other-than-temporary-impairment ("OTTI") of $32 million and $17 million, respectively.
10. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
The following table summarizes the changes in the carrying amount of goodwill, by reportable segment for the years ended December 31, 2014 and 2013.
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(1) Both the gross carrying amount and the accumulated impairment losses of the Europe segment have been reduced by $58 million with no impact on the net carrying amount for the segment. This relates to Ebute, which had fully impaired goodwill of $58 million and was sold in 2014.
Buffalo Gap - During the first quarter of 2014, the Company recognized an $18 million impairment of its goodwill at its Buffalo Gap reporting unit, which is comprised of three wind projects in Texas with an aggregate generation capacity of 524 MW. During the fourth quarter of 2014, the Company performed the annual goodwill impairment test at its Buffalo Gap reporting unit. The reporting unit failed Step 1 and Step 2 was performed to measure the amount of goodwill impairment. In Step 2, after the hypothetical purchase price allocation under the relevant accounting guidance, the implied fair value of goodwill was negative. As a result, a full impairment of goodwill of $10 million was recognized. Buffalo Gap is reported in the US SBU reportable segment.
DPLER - During the first quarter of 2014, the Company performed an interim impairment test on the $136 million in goodwill at its DPLER reporting unit, a competitive retail marketer selling retail electricity to customers in Ohio and Illinois.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014.
In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business.
In Step 2 of the interim impairment test, the goodwill was determined to have an implied fair value of zero after the hypothetical purchase price allocation and the Company accordingly recognized a full impairment of the $136 million in goodwill at the DPLER reporting unit. DPLER is reported in the US SBU reportable segment.
DP&L-During the fourth quarter of 2013, the Company performed the annual goodwill impairment test at its DP&L reporting unit ("DP&L") and recognized a goodwill impairment expense of $307 million. The reporting unit failed Step 1 as its fair value was less than its carrying amount primarily due to lower estimates of capacity prices in future years as well as lower dark spreads contributing to lower overall operating margins. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were capacity price curves, amount of the non-bypassable charge, commodity price curves, dispatching, valuation of regulatory assets and liabilities, discount rates and deferred income taxes. In Step 2, goodwill was determined to have an implied fair value of $316 million after the hypothetical purchase price allocation under the accounting guidance for business combinations. The goodwill associated with the DP&L acquisition is not deductible for tax purposes. Accordingly, there is no financial statement tax benefit related to the impairment. The pretax impairment impacted the Company’s effective tax rate for the year ended December 31, 2013, which was 33%. DP&L is reported in the US SBU reportable segment.
The Company had previously recognized a goodwill impairment expense of $1.82 billion in 2012 at the DP&L reporting unit. During 2012, North American natural gas prices declined significantly compared to the previous year, which exerted downward pressure on wholesale power prices in the Ohio power market. These falling power prices compressed wholesale margins at DP&L and led to increased customer switching from DP&L to other competitive retail electric service (“CRES”) providers, including DPLER, who were offering retail prices lower than DP&L’s standard service offer. In addition, several municipalities in DP&L’s service territory passed ordinances allowing them to become government aggregators and contracted with CRES providers to provide generation service to the customers located within the municipal boundaries, further contributing to the switching trend. CRES providers also became more active in DP&L’s service territory. These developments reduced DP&L’s forecasted profitability, operating cash flows and liquidity. As a result, in September 2012, management reduced its previous forecasts of profitability and operating cash flows. Collectively, these events were considered an interim goodwill impairment indicator at the DP&L reporting unit. There were no interim impairment indicators identified for the goodwill at DPLER. The goodwill associated with the DP&L acquisition is not deductible for tax purposes. Accordingly, there was no financial statement tax benefit related to the impairment. The pretax impairment impacted the Company’s effective tax rate for the year ended December 31, 2012, which was 298%.
MountainView-During the fourth quarter of 2013, the Company performed the annual goodwill impairment test at its MountainView reporting unit, two wind projects in California with an aggregate generation capacity of 67 MW, and recognized a full impairment of goodwill of $7 million. Factors contributing to impairment were lower forward power prices impacting revenue after the expiration of the current PPA and higher discount rates. In Step 1, the fair value of MountainView was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were power price curves, fixed costs, discount rates and income tax attributes associated with the projects. MountainView failed Step 1 and its goodwill was determined to have no value in Step 2. MountainView is reported in the US SBU reportable segment.
Ebute-During the third quarter of 2013, the Company performed an interim goodwill impairment test at Ebute, a 294 MW gas-fired plant in Nigeria and recognized the entire goodwill balance of $58 million as goodwill impairment expense. Ebute currently operates on leased land located within the PHCN Egbin Power Station Compound (“Egbin”) in Ijede, Ikorodu, Lagos. A controlling stake in Egbin was sold to a private investor as part of the Nigerian government privatization program in 2007, but the sale transaction did not close until the third quarter of 2013. The Company has been evaluating Ebute's future options for the continuation of the plant operation after the end of the current PPA on an ongoing basis. The viability of a number of such options is subject to the Company's ability to secure among other things long-term land rights, permits, gas transportation and supply agreements, and a new or extended PPA. In this evaluation, the Company has been continually
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
assessing the probability of success of each of these options. Based on communications with the Nigerian government and other power sector stakeholders it interacts with to secure the required key project components and agreements, in September 2013, management determined that the prospects for Ebute's future expansion had significantly reduced. These adverse developments were considered as impairment indicators for Ebute's goodwill and long-lived assets. The long-lived assets were deemed recoverable based on the undiscounted cash flow recoverability analysis. In Step 1, the fair value of Ebute was determined using the income approach based on a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were the ability to obtain an extension to the existing land lease, permits, gas transportation and supply agreements, future PPA terms, maintenance and growth capital expenditures, and discount rates. Ebute failed Step 1 and its goodwill was determined to have no value in Step 2. Ebute is reported in the Europe SBU reportable segment.
Other Intangible Assets
The following tables summarize the balances comprising other intangible assets in the accompanying Consolidated Balance Sheets as of the periods indicated:
_____________________________
(1)
Represent development rights, including but not limited to, land control, various permits and right to acquire equity interests in development projects resulting from asset acquisitions by our wind operations in the U.K. The balance excludes project development rights of $70 million relating to our Poland wind operations that were fully impaired in the third quarter of 2013 and subsequently sold in November 2013. See Note 23-Discontinued Operations and Held-for-Sale Businesses for further information.
(2)
Excludes net balance of sales concessions of $32 million as of December 31, 2013 relating to our utility businesses in Cameroon that were included in noncurrent assets of discontinued operations. See Note 23-Discontinued Operations and Held for Sale Businesses for further information.
(3)
Represent legal rights to receive system reliability payments from the regulator.
(4)
Includes renewable energy certificates, land-use rights and various other intangible assets none of which is individually significant.
The following table summarizes, by category, other intangible assets acquired during the periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The following table summarizes the estimated amortization expense, by intangible asset category, for 2015 through 2019:
Intangible asset amortization expense was $26 million, $29 million and $115 million for the years ended December 31, 2014, 2013 and 2012, respectively.
11. REGULATORY ASSETS AND 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, 2014, 2013, AND 2012
_____________________________
(1)
Recoverable or refundable per Brazilian 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 passed through for a period of 12 months as part of the annual tariff adjustment. Any remaining balance is considered in the following annual tariff adjustment, which results in a total of 24 months to recover or refund the costs. Favorable spot market sales are also subject to customer refunds through the IRT over the course of these time periods.
(2)
Deferred fuel costs incurred by our El Salvador subsidiaries associated with purchase of energy from the El Salvador spot market and the power generation plants. In El Salvador, the deferred fuel adjustment represents the variance between the actual fuel costs and the fuel costs recovered in the tariffs. The variance is recovered quarterly at the tariff reset period.
(3)
Includes assets with and without a rate of return. Other current regulatory assets that did not earn a rate of return were $22 million and $13 million, as of December 31, 2014 and 2013, respectively. Other noncurrent regulatory assets that did not earn a rate of return were $73 million and $71 million, as of December 31, 2014 and 2013, respectively. Other current and noncurrent regulatory assets primarily consist of:
▪
Unamortized losses on long-term debt reacquired or redeemed in prior periods at IPL and DPL, which are amortized over the lives of the original issues in accordance with the FERC and PUCO rules.
▪
Unamortized carrying charges and certain other costs related to Petersburg unit 4 at IPL.
▪
Deferred storm costs incurred primarily in 2008 to repair storm damage at DPL; recovery was approved in a December 17, 2014 order from the PUCO and began in January 2015.
▪
Additional Regulatory Asset Base (RAB) from a favorable decision on tariff reset (administrative appeal) at Eletropaulo.
(4)
Past expenditures on which the Company does not earn a rate of return.
(5)
The regulatory accounting standards allow the defined pension and postretirement benefit obligation to be recorded as a regulatory asset equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Pension expense is recognized based on the plan’s actuarially determined pension liability. Recovery of costs is probable, but not yet determined. Pension contributions made by our Brazilian subsidiaries are not included in regulatory assets as those contributions are not covered by the established tariff in Brazil.
(6)
Probability of recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This amount is expected to be recovered, without interest, over the period as book-tax temporary differences reverse and become current taxes.
(7)
Transmission service costs and other administrative costs from IPL’s participation in the Midwest ISO market, which are recoverable but do not earn a rate of return. Recovery of costs is probable, but the timing is not yet determined.
(8)
In July 2012, the Brazilian energy regulator (the “Regulator”) approved the periodic review and reset of a component of Eletropaulo’s regulated tariff, which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component is retroactive to July 2011 and will be applied to customers’ invoices from July 2012 to June 2015. From July 2011 through June 2012, Eletropaulo invoiced customers under the then-existing tariff rate, as required by the Regulator. As the new tariff rate is lower than the pre-existing tariff rate, Eletropaulo is required to reduce customer tariffs for this difference over the next year. Accordingly, from July 2011 through June 2012, Eletropaulo recognized a regulatory liability for such estimated future refunds, which was subsequently adjusted as of June 30, 2012 upon the finalization of the new tariff with the Regulator. The refund to customers was considered in the 2013 tariff adjustment, which contemplates an amortization of 67.55% as from July 4, 2013. The remaining balance, representing 32.45%, will be considered in the next annual tariff adjustment. As of December 31, 2014, Eletropaulo had recorded a current regulatory liability of $76 million.
(9)
Amounts received for costs expected to be incurred to improve the efficiency of our plants in Brazil as part of the IRT.
(10)
Other current and noncurrent regulatory liabilities primarily consist of liabilities owed to electricity generators due to variance in energy prices during rationing periods (“Free Energy”). Our Brazilian subsidiaries are authorized to recover or refund this cost associated with monthly energy price variances between the wholesale energy market prices owed to the power generation plants producing Free Energy and the capped price reimbursed by the local distribution companies which are passed through to the final customers through energy tariffs. The balance excludes asset retirement obligations that were reclassified out of Other.
(11)
Obligations for removal costs which do not have an associated legal retirement obligation as defined by the accounting standards on asset retirement obligations.
(12)
Obligations established by ANEEL in Brazil associated with electric utility concessions and represent amounts received from customers or donations not subject to return. These donations are allocated to support energy network expansion and to improve utility operations to meet customers’ needs. The term of the obligation is established by ANEEL. Settlement shall occur when the concession ends.
(13)
Represents adjustments to the regulatory asset base resulting from an administrative ruling in December 2013 which compelled Eletropaulo to refund customers beginning in July 2014.
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 noncurrent assets” and “Other noncurrent liabilities,” respectively, in the accompanying Consolidated Balance Sheets. The following table summarizes regulatory assets and liabilities by reportable segment as of the periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
12. DEBT
NON-RECOURSE DEBT
The following table summarizes the carrying amount and terms of non-recourse debt as of the periods indicated:
(1)
The interest rate on variable rate debt represents the total of a variable component that is based on changes in an interest rate index and of a fixed component. The Company has interest rate swaps and option agreements in an aggregate notional principal amount of approximately $3.0 billion on non-recourse debt outstanding at December 31, 2014. These agreements economically fix the variable component of the interest rates on the portion of the variable-rate debt being hedged so that the total interest rate on that debt has been fixed at rates ranging from approximately 2.87% to 9.80%. These agreements expire at various dates from 2016 through 2033.
(2)
Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
(3)
There was no non-recourse debt excluded from non-recourse debt and included in current and noncurrent liabilities of held for sale and discontinued businesses in the accompanying Consolidated Balance Sheets as of December 31, 2014. There were $658 million excluded in 2013.
Non-recourse debt as of December 31, 2014 is scheduled to reach maturity as set forth in the table below:
As of December 31, 2014, AES subsidiaries with facilities under construction had a total of approximately $2.3 billion of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $2.4 billion in a number of available but unused committed credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used for borrowings, letters of credit, or a combination of these uses.
Significant transactions
During the year ended December 31, 2014, we had the following significant debt transactions at our subsidiaries:
•
Mong Duong drew $364 million under its construction loan facility;
•
Angamos issued new debt of $800 million, offset by repayments of $780 million;
•
Gener issued new debt of $700 million, more than offset by repayments of $905 million;
•
Southland, Shady Point and Hawaii (collectively US Generation Holdings) issued new debt of $299 million;
•
Eletropaulo issued new debt of $253 million; offset by repayments of $110 million;
•
DPL issued new debt of $200 million; more than offset by repayments of $364 million;
•
Tietê issued new debt of $318 million, offset by repayments of $132 million;
•
Cochrane drew $305 million under its construction loans;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
•
Sul issued new debt of $185 million;
•
Southland made repayments of $188 million;
•
Chivor made repayments of $165 million;
•
UK Wind made repayments of $114 million; and
•
Warrior Run made repayments of $109 million.
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.
As of December 31, 2014 and 2013, approximately $245 million and $492 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these amounts were included within “Restricted cash” and “Debt service reserves and other deposits” in the accompanying Consolidated Balance Sheets.
Various lender and governmental provisions restrict the ability of certain of the Company’s subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $2.7 billion at December 31, 2014.
The following table summarizes the Company’s subsidiary non-recourse debt in default as of December 31, 2014. Due to the defaults, these amounts are included in the current portion of non-recourse debt:
As of December 31, 2014, none of the defaults are payment defaults. All of the subsidiary non-recourse defaults were triggered by failure to comply with other covenants and/or conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the applicable subsidiary. However, as of December 31, 2014, Kavarna is forecasting a payment default as likely to occur at the end of February 2015.
In the event that there is a default, bankruptcy or maturity acceleration at a subsidiary or group of subsidiaries that meets the applicable definition of materiality under the corporate debt agreements of The AES Corporation, there could be a cross-default to the Company’s recourse debt. Materiality is defined in the Parent's senior secured credit facility as having provided 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of December 31, 2014, none of the defaults listed above individually or in the aggregate result in or are at risk of triggering a cross-default under the recourse debt of the Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its senior secured revolving credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the then-prevailing rate. Payment defaults and bankruptcy defaults would preclude the making of any restricted payments.
Interest Expense
Interest expense for the year ended December 31, 2014 has been reduced by approximately $48 million related to reversing contingent interest accruals associated with disputed purchased energy obligations at Sul for which it was determined, based on developments during the second quarter of 2014, that the likelihood of an unfavorable outcome for the payment of interest on the disputed obligations was no longer probable. Interest expense for the year ended December 31, 2013 was reduced by approximately $34 million related to the recognition of ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
RECOURSE DEBT
The table below summarizes the carrying amount and terms of recourse debt of the Company as of the periods indicated:
The table below summarizes the principal amounts due, net of unamortized discounts, under our recourse debt for the next five years and thereafter:
In February 2014, the Company redeemed in full the $110 million balance of its 7.75% senior unsecured notes due March 2014. On March 7, 2014, the Company issued $750 million aggregate principal amount of 5.50% senior notes due 2024. Concurrent with this offering, the Company redeemed via tender offers $625 million aggregate principal of its existing 8.00% senior unsecured notes due 2017. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $132 million that is included in the Consolidated Statements of Operations.
On May 20, 2014, the Company issued $775 million aggregate principal amount of senior unsecured floating rate notes due June 2019. The notes bear interest at a rate of 3% above three-month LIBOR, reset quarterly. Concurrent with this offering, the Company repaid $767 million of its existing senior secured term loan due 2018. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $10 million that is included in the Consolidated Statement of Operations. On June 16, 2014, the Company repaid in full the remaining balance of approximately $29 million of its senior secured term loan due 2018.
On July 25, 2014, the Company issued two notices to call $320 million aggregate principal amount of unsecured notes, $160 million of which was used to retire notes due in 2015 and $160 million of which was used to retire notes due in 2016. The Company closed these transactions on August 25, 2014. As a result of this transaction, the Company recognized a loss on extinguishment of debt of $40 million that is included in the Consolidated Statement of Operations.
Recourse Debt Covenants and Guarantees
The Company’s obligations under the senior secured credit facility are subject to certain exceptions, secured by:
(i)
all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company; and
(ii)
certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The senior secured credit facility is subject to mandatory prepayment under certain circumstances, including the sale of certain assets. In such a situation, the net cash proceeds from the sale must be applied pro rata to repay the term loan, if any, using 60% of net cash proceeds, reduced to 50% when and if the parent’s recourse debt to cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption.
The senior secured credit facility contains customary covenants and restrictions on the Company’s ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.
The senior secured credit facility also contains financial covenants requiring the Company to maintain certain financial ratios including a cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company’s adjusted operating cash flow to the Company’s interest charges related to recourse debt of 1.3× must be maintained at all times and a recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company’s total recourse debt to the Company’s adjusted operating cash flow must not exceed a maximum of 7.5×.
The terms of the Company’s senior unsecured notes and senior secured credit facility contain certain covenants including, without limitation, limitation on the Company’s ability to incur liens or enter into sale and leaseback transactions.
TERM CONVERTIBLE TRUST SECURITIES
In 1999, AES Trust III, a wholly owned special purpose business trust and a VIE, issued approximately 10.35 million of $50 par value Term Convertible Preferred Securities (“TECONS”) with a quarterly coupon payment of $0.844 for total proceeds of $517 million and concurrently purchased $517 million of 6.75% Junior Subordinated Convertible Debentures due 2029 (the “6.75% Debentures”) issued by AES. The Company consolidates AES Trust III in its consolidated financial statements and classifies the TECONS as recourse debt on its Consolidated Balance Sheet. The Company’s obligations under the 6.75% Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by the Company of the TECON Trusts’ obligations. As of December 31, 2014 and 2013, the sole assets of AES Trust III are the 6.75% Debentures.
AES, at its option, can redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by AES Trust III, currently for $50 per TECON. The TECONS must be redeemed upon maturity of the 6.75% Debentures. The TECONS are convertible into the common stock of AES at each holder’s option prior to October 15, 2029 at the rate of 1.4216, representing a conversion price of $35.17 per share. The maximum number of shares of common stock AES would be required to issue should all holders decide to convert their securities would be 14.7 million shares.
Dividends on the TECONS are payable quarterly at an annual rate of 6.75%. The Trust is permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the TECONS would accumulate quarterly and accrue interest, and the Company may not declare or pay dividends on its common stock. AES has not exercised the option to defer any dividends at this time and all dividends due under the Trust have been paid.
13. COMMITMENTS
LEASES-The Company and its subsidiaries enter into long-term non-cancelable lease arrangements which, for accounting purposes, are classified as either an operating lease or capital lease. Operating leases primarily include certain transmission lines, office rental and site leases. Operating lease rental expense for the years ended December 31, 2014, 2013, and 2012 was $58 million, $46 million and $57 million, respectively. Capital leases primarily include transmission lines at our subsidiaries in Brazil, vehicles, and office and other operating equipment. Capital leases are recognized in Property, Plant and Equipment within “Electric generation and distribution assets.” The gross value of the capital lease assets as of December 31, 2014 and 2013 was $80 million and $93 million, respectively. The table below sets forth the future minimum lease payments under operating and capital leases for continuing operations together with the present value of the net minimum lease payments under capital leases as of December 31, 2014 for 2015 through 2019 and thereafter:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
CONTRACTS-The Company’s operating subsidiaries enter into long-term contracts for construction projects, maintenance and service, transmission of electricity, operations services and purchase of electricity and fuel. In general, these contracts are subject to variable quantities or prices and are terminable in limited circumstances only. Electricity purchase contracts primarily include energy auction agreements at our Brazil subsidiaries with extended terms from 2013 through 2028. The table below sets forth the future minimum commitments for continuing operations under these contracts as of December 31, 2014 for 2015 through 2019 and thereafter. Actual purchases under these contracts for the years ended December 31, 2014, 2013, and 2012 are also presented:
14. CONTINGENCIES
Guarantees, Letters of Credit
In connection with certain project financing, acquisition and dispositions, power purchase and other agreements, the Parent 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. In the normal course of business, the Parent Company has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 20 years.
The following table summarizes the Parent Company’s contingent contractual obligations as of December 31, 2014. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses of $24 million.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
(1) Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.
As of December 31, 2014, the Parent Company had no commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. During the year ended December 31, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts of letters of credit.
Environmental
The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of December 31, 2014 and 2013 the Company had recognized liabilities of $12 million and $19 million, respectively, 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. Moreover, where no liability has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of December 31, 2014. In aggregate, the Company estimates that the range of potential losses related to environmental matters, where estimable, to be up to $1 million. The amounts considered reasonably possible do not include amounts accrued as discussed above.
Litigation
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has recorded aggregate liabilities for all claims of approximately $199 million and $239 million as of December 31, 2014 and 2013, respectively. These amounts are reported on the Consolidated Balance Sheets within “accrued and other liabilities” and “other noncurrent liabilities.” A significant portion of these accrued liabilities relate to employment, non-income tax and customer disputes in international jurisdictions (principally Brazil). Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. The reduction in the recorded liabilities at December 31, 2014 primarily relates to labor dispute settlements and the expiration of the statute of limitations for certain claims in Brazil, as well as the devaluation of the Brazilian Real. There can be no assurance that these accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
The Company believes, based upon information it currently possesses and taking into account established accruals for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s consolidated financial statements. However, where no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2014. The material contingencies where a loss is reasonably possible primarily include claims under financing agreements; disputes with offtakers, suppliers and EPC contractors; alleged violation of monopoly laws and regulations; income tax and non-income tax matters with tax authorities; and regulatory matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between $1.1 billion and $1.2 billion. The amounts considered reasonably possible do not include amounts accrued, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.
15. BENEFIT PLANS
Defined Contribution Plan
The Company sponsors four defined contribution plans ("the Plans"). Three are for U.S. non-union employees, of which one is for employees of the Parent Company and U.S. SBU generation businesses, one is for IPL employees and one is for DPL employees. One defined contribution plan is for union employees at DPL. The Plans are qualified under section 401 of the Internal Revenue Code. All U.S. employees of the Company are eligible to participate in the appropriate Plan except for those employees who are covered by a collective bargaining agreement, unless such agreement specifically provides that the employee is considered an eligible employee under a Plan. The Plans provide matching contributions in AES common stock or cash, other contributions at the discretion of the Compensation Committee of the Board of Directors in AES common stock or cash 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
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
ending on the fifth anniversary of their hire date. For the year ended December 31, 2014, the Company’s contributions to the defined contribution plans were approximately $14 million, and for the years ended December 31, 2013 and 2012, contributions were $15 million and $21 million per year, 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 31 active defined benefit plans as of December 31, 2014, five are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries .
The following table reconciles the Company’s funded status, both domestic and foreign, as of the periods indicated:
The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the funded status of the plans, both domestic and foreign, as of the periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The following table summarizes the Company’s accumulated benefit obligation, both domestic and foreign, as of the periods indicated:
(1)
$1.1 billion of the total net unfunded projected benefit obligation is due to Eletropaulo in Brazil.
The table below summarizes the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of the periods indicated:
(1)
A U.S. subsidiary of the Company has a defined benefit obligation of $748 million and $651 million as of December 31, 2014 and 2013, respectively, and uses salary bands to determine future benefit costs rather than rates of compensation increases. Rates of compensation increases in the table above do not include amounts related to this specific defined benefit plan.
(2)
Includes an inflation factor that is used to calculate future periodic benefit cost, but is not used to calculate the benefit obligation.
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 assumptions used in developing the required estimates include the following key factors:
•
discount rates;
•
salary growth;
•
retirement rates;
•
inflation;
•
expected return on plan assets; and
•
mortality rates.
The effects of actual results differing from the Company’s assumptions are accumulated and amortized over future periods and, therefore, generally affect the Company’s recognized expense in such future periods.
Sensitivity of the Company’s pension funded status to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric and are specific to the base conditions at year-end 2014. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The funded status as of December 31, 2014 is affected by the assumptions as of that date. Pension expense for 2014 is affected by the December 31, 2013
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
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 indicated:
The following table summarizes the amounts reflected in AOCL including accumulated other comprehensive loss attributable to noncontrolling interests, on the Consolidated Balance Sheet as of December 31, 2014, that have not yet been recognized as components of net periodic benefit cost and amounts expected to be reclassified to earnings in the next fiscal year:
The following table summarizes the Company’s target allocation for 2014 and pension plan asset allocation, both domestic and foreign, as of the periods indicated:
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; and
•
long-term competitive rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates.
The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage risk through portfolio diversification and takes into account, among other possible factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends. The following table summarizes the Company’s U.S. plan assets by category of investment and level within the fair value hierarchy as of the periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
(1)
Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk. The assumed asset allocation has less exposure to equities in order to closely match market conditions and near term forecasts. The following table summarizes the Company’s foreign plan assets by category of investment and level within the fair value hierarchy as of December 31, 2014 and 2013:
(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 periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The following table summarizes the estimated cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign:
16. EQUITY
Equity Transactions with Noncontrolling Interests
Dominican Republic - On September 2, 2014, the Company executed an agreement with the Estrella and Linda Groups, an investor-based group in the Dominican Republic, to form a strategic partnership. Under the terms of the agreement, the Estrella and Linda Groups acquired an 8% noncontrolling interest in our businesses in the Dominican Republic for $84 million, with options to acquire an additional 2% for $24 million at any time between the closing date and December 31, 2015, and an additional 10% for $125 million at any time between the closing date and December 31, 2016. The transaction closed on December 19, 2014. As a result of this transaction, $29 million was recognized in equity as Additional Paid-In Capital and no gain or loss was recognized in net income as the sale is not considered to be a sale of in-substance real estate. As the Company maintained control after the sale, our businesses in the Dominican Republic continue to be consolidated by the Company within the MCAC SBU reportable segment.
Masinloc - On June 25, 2014, the Company executed an agreement to sell approximately 45% of its interest in Masin-AES Pte Ltd., a wholly-owned subsidiary that owns the Company's business interests in the Philippines, for $453 million, subject to certain purchase price adjustments. On July 15, 2014, the Company completed the Masinloc sale transaction and received cumulative net proceeds of $436 million, including $23 million contingent upon the achievement of certain restructuring efficiencies. The transaction was accounted for as a sale of in-substance real estate. Noncontrolling interest of $130 million and a pretax gain on sale of investment of approximately $283 million, net of transaction costs, were recognized during the third quarter of 2014. The portion of the proceeds related to the contingency has been deferred.
After completion of the sale, the Company owns a 51% net ownership interest in Masinloc and will continue to manage and operate the plant, with 41% owned by Electricity Generating Public Company Limited and 8% owned by the International Finance Corporation. As the Company maintained control after the sale, Masinloc continues to be accounted for as a consolidated subsidiary within the Asia SBU reportable segment.
IPALCO - On December 15, 2014, the Company executed an agreement with La Caisse de depot et placement du Quebec ("CDPQ"). Under the agreement, CDPQ will purchase 15% of AES US Investment, Inc., a wholly-owned subsidiary that owns 100% of IPALCO Enterprises, Inc. ("IPALCO"), for $247 million . This transaction closed on February 11, 2015. Under the agreement, CDPQ will invest an additional $349 million in IPALCO through 2016 in exchange for a 17.65% equity stake, by funding existing growth and environmental projects at Indianapolis Power & Light Company. Upon completion of these transactions, CDPQ's direct and indirect interests in IPALCO will total 30%. As the Company maintained control after the sale, IPALCO continues to be accounted for as a consolidated subsidiary within the US SBU reportable segment.
The following table summarizes the net income (loss) attributable to The AES Corporation and all transfers (to) from noncontrolling interests for the periods indicated:
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
Accumulated Other Comprehensive Loss
The changes in AOCL by component, net of tax and noncontrolling interests for the year ended December 31, 2014 were as follows:
(1) Reclassification resulting from Silver Ridge transaction. See Note 8-Investments In and Advances to Affiliates for further information.
Reclassifications out of accumulated other comprehensive loss for the periods indicated were as follows:
_____________________________
(1)
Amounts in parentheses indicate debits to the consolidated statements of operations.
Common Stock Dividends
The Company paid dividends of $0.05 per outstanding share to its common stockholders during the first, second, third and fourth quarters of 2014. On December 12, 2014, the Board of Directors declared a quarterly common stock dividend of $0.10 per share payable on February 17, 2015 to shareholders of record at the close of business on February 3, 2015.
Stock Repurchase Program
In July 2014, the Company's Board of Directors authorized an increase to the Company's common stock repurchase program (the "Program") for up to an additional $140 million of repurchases of the Company's common stock, bringing the cumulative total of authorized repurchases under the Program to $1.3 billion.
During the year ended December 31, 2014, the Company repurchased 21,900,246 shares of its common stock under the Program at a total cost of $308 million. At December 31, 2014, the cumulative repurchases under the Program totaled 105,912,477
shares for a total cost of $1.3 billion, at an average price per share of $12.37 (including a nominal amount of commissions). As of December 31, 2014, $24 million remained available for repurchase under the Program.
The common stock repurchased has been classified as treasury stock and accounted for using the cost method. A total of 110,687,849 and 90,808,168 shares were held as treasury stock at December 31, 2014 and 2013, respectively. Restricted stock units under the Company’s employee benefit plans are issued from treasury stock. The Company has not retired any common stock repurchased since it began the Program in July 2010.
Subsequent to December 31, 2014, the Company repurchased an additional 1,892,432 shares at a cost of $24 million, bringing the cumulative repurchases total through February 25, 2015 to 107,804,909 shares at a total cost of $1.3 billion, at an average price per share of $12.37 (including a nominal amount of commissions).
In addition, the Company’s Board of Directors recently authorized the repurchase of up to $400 million of the Company’s common stock in one or more transactions, including through open market repurchases, Rule 10b5-1 plans and privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and it can be modified or terminated by the Company’s Board at any time. As of February 25, 2015, $400 million remains available under the Program.
17. SEGMENTS AND GEOGRAPHIC INFORMATION
The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally and is organized by geographic regions which provide better socio-political-economic understanding of our business. The management reporting structure is organized along six strategic SBUs - led by our CEO. Using the accounting guidance on segment reporting, the Company has determined that it has six reportable segments corresponding to its six SBUs:
•
US SBU;
•
Andes SBU;
•
Brazil SBU;
•
MCAC SBU;
•
Europe SBU (formerly EMEA); and
•
Asia SBU.
Corporate and Other - Corporate overhead costs which are not directly associated with the operations of our six reportable segments are included in "Corporate and Other." Also included are intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.
The Company uses Adjusted PTC as its primary segment performance measure. Adjusted PTC, a non-GAAP measure, is defined by the Company as pre-tax income from continuing operations attributable to AES excluding unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, gains or losses due to dispositions and acquisitions of business interests, losses due to impairments and costs due to the early retirement of debt. The Company has concluded that Adjusted PTC best reflects the underlying business performance of the Company and is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists the investor in determining which businesses have the greatest impact on the overall Company results.
Certain 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 Statement of Operations, not in revenue. Total revenue includes inter-segment revenue primarily related to the sale of coal between Andes and the US. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self-insurance activities which are reflected within segment adjusted PTC. All intra-segment activity has been eliminated with respect to revenue and adjusted PTC within the segment. Inter-segment activity has been eliminated within the total consolidated results. Asset information for businesses that were discontinued or classified as held-for-sale is segregated and is shown in the line “Discontinued businesses” in the accompanying segment tables.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
Information about the Company’s operations by segment for the periods indicated was as follows:
_____________________________
(1)
Adjusted pretax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees and the write-off of intercompany balances.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The table below presents information, by country, about the Company’s consolidated operations for each of the three years ended December 31, 2014, 2013, and 2012, and as of December 31, 2014 and 2013. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
(1)
Excludes revenue of $2 million, $23 million and $63 million for the years ended December 31, 2014, 2013 and 2012, respectively, and property, plant and equipment of $69 million as of December 31, 2013, related to Condon, Mid-West Wind, Red Oak and Ironwood which are reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
(2)
Excludes revenue of $230 million, $473 million and $457 million for the years ended December 31, 2014, 2013 and 2012, respectively, and property, plant and equipment of $1,100 million as of December 31, 2013, related to Dibamba, Kribi and Sonel, which are reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
(3)
Excludes revenue of $187 million and $491 million for the years ended December 31, 2013 and 2012, respectively, related to Kievoblenergo and Rivnooblenergo, which are reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(4)
Excludes revenue of $18 million for the year ended December 31, 2012, related to Tisza II, which is reflected as discontinued operations in the accompanying Consolidated Statements of Operations.
(5)
Excludes revenue of $6 million and $11 million for the years ended December 31, 2013 and 2012, respectively, and property, plant and equipment of $19 million as of December 31, 2013, related to Saurashtra and our carbon reduction projects, which are reflected as discontinued operations and assets held for sale in the accompanying Consolidated Statements of Operations and Consolidated Balance Sheets.
18. SHARE-BASED COMPENSATION
STOCK OPTIONS-AES grants options to purchase shares of common stock under stock option plans to employees and non-employee directors. 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 2014, 2013 and 2012 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, 2014, approximately 14 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 following table presents the weighted average fair value of each option grant and the underlying weighted average assumptions, as of the grant date, using the Black-Scholes option-pricing model:
The Company does not discount the grant date fair values to estimate post-vesting restrictions. Post-vesting restrictions include black-out periods when the employee is not able to exercise stock options based on their potential knowledge of information prior to the release of that information to the public.
The following table summarizes the components of stock-based compensation related to employee stock options recognized in the Company’s financial statements:
No cash was used to settle stock options or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2014, 2013 and 2012. As of December 31, 2014, $3 million of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted average period of 1.9 years.
A summary of the option activity for the year ended December 31, 2014 follows (number of options in thousands, dollars in millions except per option amounts):
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
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 2014 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, 2014. The amount of the aggregate intrinsic value will change based on the fair market value of the Company’s stock.
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2014, AES has estimated a weighted average forfeiture rate of 16.44% for stock options granted in 2014. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $3.7 million on a straight-line basis over a three year period (approximately $1.2 million per year) related to stock options granted during the year ended December 31, 2014.
RESTRICTED STOCK
Restricted Stock Units-The Company issues restricted stock units (“RSUs”) 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. Units granted prior to 2011 are required to be held for an additional two years before they can be converted into shares, and thus become transferable. There is no such requirement for units granted in 2011 and afterwards. In all circumstances, restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.
For the years ended December 31, 2014, 2013, and 2012, RSUs issued 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 granted to employees during the years ended December 31, 2014, 2013, and 2012 had grant date fair values per RSU of $14.60, $11.19 and $13.54, respectively.
The following table summarizes the components of the Company’s stock-based compensation related to its employee RSUs recognized in the Company’s consolidated financial statements:
(1)
Amount represents fair market value on the date of conversion.
There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2014, 2013, and 2012. As of December 31, 2014, $13 million of total unrecognized compensation cost related to RSUs 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, 2014.
A summary of the activity of RSUs for the year ended December 31, 2014 follows (number of RSUs in thousands):
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2014, AES has estimated a weighted average forfeiture rate of 14.17% for RSUs granted in 2014. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $14 million on a straight-line basis over a three year period related to RSUs granted during the year ended December 31, 2014.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The table below summarizes the RSUs that vested and were converted during the years ended December 31, 2014, 2013, and 2012 (number of RSUs in thousands):
Performance Stock Units-The Company issues performance stock units (“PSUs”) to officers under its long-term compensation plan. PSUs are restricted stock units of which 50% of the units awarded include a market condition and the remaining 50% include a performance condition. Vesting will occur if the applicable continued employment conditions are satisfied and (a) for the units subject to the market condition the Total Stockholder Return (“TSR”) on AES common stock exceeds the TSR of the Standard and Poor’s 500 Utilities Sector Index over the three-year measurement period beginning on January 1st of the grant year and ending on December 31st of the third year and (b) for the units subject to the performance condition if the Company’s actual Adjusted EBITDA meets the performance target over the three-year measurement period beginning on January 1st of the grant year and ending on December 31st of the third year. The market and performance conditions determine the vesting and final share equivalent per PSU and can result in earning an award payout range of 0% to 200%, depending on the achievement. In all circumstances, PSUs 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 PSUs issued to officers of the Company during 2014 is reflected in the award’s fair value on the grant date. The results of the valuation estimated the fair value at $15.19 per share, equating to 104% of the Company’s closing stock price on the date of grant. PSUs that included a market condition granted during the year ended December 31, 2014, 2013, and 2012 had a grant date fair value per RSU of $15.19, $13.28 and $19.75, respectively. The fair value of the PSUs with a performance condition had a grant date fair value of $14.63 equal to the closing price of the Company’s stock on the grant date. The Company believes that it is probable that the performance condition will be met; this will continue to be evaluated throughout the performance period. If the fair value of the market condition was not applied to PSUs issued to officers, the total grant date fair value of PSUs granted during the year ended December 31, 2014 would have decreased by $0.1 million.
Restricted stock units with a market condition awarded to officers of the Company prior to 2011 contained only the market condition measuring the TSR on AES common stock. These units were required to be held for an additional two years subsequent to vesting before they could be converted into shares and become transferable. There is no such requirement for the shares granted during 2011 and afterwards.
The following table summarizes the components of the Company’s stock-based compensation related to its PSUs recognized in the Company’s consolidated financial statements:
(1)
Amount represents fair market value on the date of conversion.
There was no cash used to settle PSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2014, 2013, and 2012. As of December 31, 2014, $7 million of total unrecognized compensation cost related to PSUs is expected to be recognized over a weighted average period of approximately 1.8 years. There were no modifications to PSU awards during the year ended December 31, 2014.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
A summary of the activity of PSUs for the year ended December 31, 2014 follows (number of PSUs in thousands):
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2014, AES has estimated a forfeiture rate of 16.44% for PSUs granted in 2014. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $7 million on a straight-line basis over a three year period (approximately $2.3 million per year) related to PSUs granted during the year ended December 31, 2014.
The table below summarizes the PSUs that vested and were converted during the years ended December 31, 2014, 2013, and 2012 (number of PSUs in thousands):
19. CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES
Our subsidiaries IPL and DPL had outstanding shares of cumulative preferred stock of $78 million at December 31, 2014 and 2013.
IPL had $60 million of cumulative preferred stock outstanding at December 31, 2014 and 2013, which represented five series of preferred stock. The total annual dividend requirements were approximately $3 million at December 31, 2014 and 2013. Certain series of the preferred stock were redeemable solely at the option of the issuer at prices between $100 and $118 per share. Holders of the preferred stock are entitled to elect a majority of IPL’s board of directors if IPL has not paid dividends to its preferred stockholders for four consecutive quarters. Based on the preferred stockholders’ ability to elect a majority of IPL’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity and presented in the mezzanine level of the Consolidated Balance Sheets in accordance with the relevant accounting guidance for noncontrolling interests and redeemable securities.
DPL had $18 million of cumulative preferred stock outstanding at December 31, 2014 and 2013, which represented three series of preferred stock issued by DP&L, a wholly owned subsidiary of DPL. The total annual dividend requirements were approximately $1 million at December 31, 2014. The DP&L preferred stock may be redeemed at DP&L’s option as determined by its board of directors at per-share redemption prices between $101 and $103 per share, plus cumulative preferred dividends. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the DP&L Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Based on the preferred stockholders’ ability to elect members of DP&L’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity and presented in the mezzanine level of the Consolidated Balance Sheets in accordance with the relevant accounting guidance for noncontrolling interests and redeemable securities.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
20. OTHER INCOME AND EXPENSE
Other Income
Other income generally includes contract terminations, gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies, and other income from miscellaneous transactions. The components are summarized below:
_____________________________
(1) Includes gain of $54 million for the property sale of Cambuci at Eletropaulo.
(2) Reversal of a liability in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.
Other Expense
Other expense generally includes losses on disposal of assets, legal contingencies, and losses from other miscellaneous transactions. The components are summarized below:
21. ASSET IMPAIRMENT EXPENSE
Ebute - During 2014, the Company identified impairment indicators at Ebute in Nigeria, resulting from the continued lack of gas supply, the increased likelihood of selling the asset group before the end of its useful life, and indications about the potential proceeds that could be received from a future sale. The Company determined that the carrying amount of the asset group was not recoverable. The Company recognized an asset impairment of $67 million, which represents the difference between the carrying amount of $103 million and fair value less cost to sell of $36 million. In November 2014, the Company completed the sale of its interest in Ebute. See Note 24-Dispositions for additional details. Ebute was reported in the Europe SBU reportable segment prior to its disposition in 2014.
UK Wind (Newfield) - During 2014, the Company tested the recoverability of long-lived assets at its Newfield wind development project in the United Kingdom after the UK government refused to grant a permit necessary for the project to continue. The Company determined that the carrying amount of the asset group was not recoverable. The Newfield asset group was determined to have no fair value using the income approach. As a result, the Company recognized an asset impairment expense of $12 million. UK Wind (Newfield) is reported in the Europe SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
East Bend (DP&L) - During 2014, the Company identified impairment indicators at East Bend, a 186 MW coal-fired plant in Ohio jointly owned by DP&L, resulting from the increased likelihood that the asset group would be disposed prior to the end of its useful life. The Company determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2 million using the market approach, and the Company recognized an asset impairment expense of $12 million during the first quarter of 2014. The Company's interest in East Bend was sold in December 2014. Prior to its sale, East Bend was reported in the US SBU reportable segment.
Beaver Valley - In January 2013, Beaver Valley, a wholly owned 125 MW coal-fired plant in Pennsylvania, entered into an agreement to early terminate its PPA with the offtaker in exchange for a lump-sum payment of $60 million which was received on January 9, 2013. The termination was effective January 8, 2013. Beaver Valley also terminated its fuel supply agreement. Under the PPA termination agreement, annual capacity agreements between the offtaker and PJM Interconnection, LLC (“PJM”) (a regional transmission organization) for 2013 - 2016 have been assigned to Beaver Valley. The termination of the PPA resulted in a significant reduction in the future cash flows of the asset group and was considered an impairment indicator. The carrying amount of the asset group was not recoverable. The carrying amount of the asset group exceeded the fair value of the asset group, resulting in an asset impairment expense of $46 million. Beaver Valley is reported in the US SBU reportable segment.
Conesville (DP&L) - During the fourth quarter of 2013, the Company tested the recoverability of long-lived assets at Conesville, a 129 MW coal-fired plant in Ohio jointly-owned by DP&L. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit failing Step 1 of the annual goodwill impairment test were determined to be impairment indicators. The Company performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The Conesville asset group was determined to have zero fair value using discounted cash flows under the income approach. As a result, the Company recognized an asset impairment expense of $26 million. Conesville is reported in the US SBU reportable segment.
Itabo (San Lorenzo)-During the third quarter of 2013, the Company tested the recoverability of long-lived assets at San Lorenzo, a 35 Megawatt ("MW") LNG fueled plant of Itabo. Itabo was informed by Super-Intendencia de Electridad (“SIE”), the system regulator in the Dominican Republic, that it would not receive capacity revenue going forward. This communication in combination with current adverse market conditions were determined to be an impairment indicator. The Company performed a long-lived asset impairment test considering different scenarios and determined that, based on undiscounted cash flows, the carrying amount of San Lorenzo was not recoverable. The fair value of San Lorenzo was determined using the market approach based on a broker quote and it was determined that its carrying amount of $23 million exceeded the estimated fair value of $7 million. As a result, the Company recognized an asset impairment expense of $16 million. Itabo is reported in the MCAC SBU reportable segment.
U.S. wind turbines and projects- In 2012, the Company recognized asset impairment expense of $41 million on certain wind turbines and projects. The wind turbines, held in storage, met the held-for-sale criteria due to less viable internal deployment scenarios and the ongoing receipt of offers from potential buyers. Accordingly, the Company measured the turbines at fair value less cost to sell under the market approach. In June 2013, the Company sold these turbines and recognized an after tax gain of $2 million. In addition, the Company determined that two early-stage wind development projects that were capitalizing certain project costs were no longer probable because of the Company’s shift in capital allocation for developing these projects. The Company assessed the value of the projects using the market approach and, after consultation with third party valuation firms and internal development staff, the fair value was determined to be zero resulting in full impairment. These wind turbines and projects were reported in the US SBU reportable segment.
Kelanitissa-In 2012, the Company recognized asset impairment expense of $19 million for the long-lived assets at Kelanitissa, a diesel-fired generation plant in Sri Lanka. The Company continued to evaluate the recoverability of its long-lived assets at Kelanitissa as a result of both the requirement to transfer the plant to the government at the end of the PPA and the expectation of lower future operating cash flows. The evaluations during this period indicated that the long-lived assets were no longer recoverable and, accordingly, were written down to their estimated fair value. Kelanitissa is reported in the Asia SBU reportable segment.
St. Patrick-In 2012, the Company received approval from its Board of Directors for the sale of its wholly owned subsidiary Ferme Eolienne Saint Patrick SAS (“St. Patrick”). Upon meeting the held-for-sale criteria including the Board’s approval, long-lived assets with a carrying amount of $33 million were written down to their fair value of $22 million (i.e., the sale price attributed to St. Patrick) and an impairment expense of $11 million was recorded. The sale transaction subsequently closed on June 28, 2012. St. Patrick was reported in the Europe SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
22. INCOME TAXES
Income Tax Provision
The following table summarizes the expense for income taxes on continuing operations for the periods indicated:
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 periods indicated:
Included in the favorable (14)% 2014 Taxes on foreign earnings percentage above is approximately (8)% related to the current year sale of approximately 45% of the Company's interest in Masin AES Pte Ltd., which owns the Company's interests in the Philippines, and the 2014 sale of the Company's interests in four U.K. wind projects. Neither of these transactions gave rise to income tax expense.
Income Tax Receivables and Payables
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 Noncurrent Assets and Other Noncurrent Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The following table summarizes the income taxes receivable and payable as of December 31, 2014 and 2013:
Chilean Tax Reform - On September 29, 2014, the Chilean government enacted comprehensive tax reforms which introduced significant changes to corporate income tax rates, a modification of the shareholder level tax beginning in 2017, and new “green” taxes primarily over CO2 emissions beginning in 2017. Specifically, two systems of income tax were introduced: Attributed Profit System (“APS”) and Partially Integrated System (“PIS”). The Company expects to elect the APS system which taxes shareholders on an accrued profits basis. Under PIS, shareholders would be taxed on a cash basis.
The corporate income tax rate was raised from 20% to 21% retroactive to January 1, 2014, and under APS is scheduled to increase in steps up to 25% for 2017 and beyond. Under PIS, the maximum rate is 27% and is effective for 2018 and beyond.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
The impact of remeasuring deferred taxes to account for the enacted change in future applicable income tax rates was recognized as discrete tax expense in the third quarter of this year and resulted in consolidated income tax expense of $46 million. The impacts of the shareholder level taxes and green taxes will be recognized in future periods and could be material.
Deferred Income Taxes-Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.
As of December 31, 2014, the Company had federal net operating loss carryforwards for tax purposes of approximately $3.4 billion expiring in years 2021 to 2034. Approximately $87 million of the net operating loss carryforward related to stock option deductions will be recognized in additional paid-in capital when realized. The Company also had federal general business tax credit carryforwards of approximately $18 million expiring primarily from 2021 to 2034, and federal alternative minimum tax credits of approximately $5 million that carry forward without expiration. The Company had state net operating loss carryforwards as of December 31, 2014 of approximately $7.8 billion expiring in years 2016 to 2034. As of December 31, 2014, the Company had foreign net operating loss carryforwards of approximately $3.7 billion that expire at various times beginning in 2015 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $34 million, $26 million of which expire in 2018 to 2025 and $8 million of which carryforward without expiration.
Valuation allowances decreased $93 million during 2014 to $997 million at December 31, 2014. This net decrease was primarily the result of valuation allowance activity at certain of our Brazilian subsidiaries and the release of valuation allowance against U.S. capital loss carryforwards.
Valuation allowances increased $195 million during 2013 to $1.1 billion at December 31, 2013. This net increase was primarily the result of valuation allowance activity at one of our Brazilian subsidiaries.
The Company believes that it is more likely than not that the net deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income. The Company continues to monitor the utilization of its deferred tax asset for its U.S. consolidated net operating loss carryforward. Although management believes it is more likely than not that this deferred tax asset will be realized through generation of sufficient taxable income prior to expiration of the loss carryforwards, such realization is not assured.
The following table summarizes the deferred tax assets and liabilities, as of December 31, 2014 and 2013:
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 $38 million, $70 million and $81 million for the years ended December 31, 2014, 2013 and 2012, respectively. The per share effect of these benefits after noncontrolling interests was $0.04, $0.09 and $0.10 for the years ended
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
December 31, 2014, 2013 and 2012, respectively. The benefit related to our operations in the Philippines expired in the fourth quarter of 2014. The Company’s income tax benefits related to these specific operations are estimated to be $21 million, $41 million and $60 million for the years ended December 31, 2014, 2013 and 2012. The per share effect of these benefits after noncontrolling interests was $0.02, $0.05 and $0.07 for the years ended December 31, 2014, 2013 and 2012.
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, 2014, 2013 and 2012:
Uncertain Tax Positions
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid in one year. The Company’s policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
As of December 31, 2014 and 2013, the total amount of gross accrued income tax related interest included in the Consolidated Balance Sheets was $14 million and $12 million, respectively. The total amount of gross accrued income tax related penalties included in the Consolidated Balance Sheets as of December 31, 2014 and 2013 was $1 million and $1 million, respectively.
The total expense (benefit) for interest related to unrecognized tax benefits for the years ended December 31, 2014, 2013 and 2012 amounted to $3 million, $(4) million and $3 million, respectively. For the years ended December 31, 2014, 2013 and 2012, the total expense (benefit) for penalties related to unrecognized tax benefits amounted to $0 million, $(3) million and $1 million, respectively.
We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:
As of December 31, 2014, 2013 and 2012, the total amount of unrecognized tax benefits was $395 million, $392 million and $475 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2014, 2013 and 2012 is $366 million, $360 million and $444 million, respectively, of which $24 million, $26 million and $45 million, respectively, would be in the form of tax attributes that would warrant a full valuation allowance.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2014 is estimated to be between $10 million and $15 million, primarily relating to statute of limitation lapses and tax exam settlements.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
Below is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the periods indicated:
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, 2014. Our effective tax rate and net income in any given future period could therefore be materially impacted.
23. DISCONTINUED OPERATIONS AND HELD-FOR-SALE BUSINESSES
As discussed in Note 1-General and Summary of Significant Accounting Policies, effective July 1, 2014, the Company prospectively adopted ASU No. 2014-08.
Discontinued operations include the results of the following businesses:
•
Cameroon (sold in June 2014);
•
Saurashtra (sold in February 2014);
•
U.S. Wind Projects (sold in January 2014);
•
Poland wind projects (sold in November 2013);
•
Ukraine utilities (sold in April 2013);
•
Tisza II (sold in December 2012);
•
Red Oak and Ironwood (sold in April 2012);
•
Eastern Energy in New York (disposed of in December 2012).
The following table summarizes the revenue, income from operations, income tax expense, impairment and loss on disposal of all discontinued operations prior to the adoption of the new accounting guidance for discontinued operations for the periods indicated:
Cameroon-In September 2013, a subsidiary of the Company executed agreements for the sale of AES White Cliffs B.V. (owner of 56% of AES SONEL S.A), AES Kribi Holdings B.V. (owner of 56% of Kribi Power Development Company S.A.) and AES Dibamba Holdings B.V., (owner of 56% of Dibamba Power Development Company S.A.). In June 2014, the Company sold its entire equity interest in all three businesses in Cameroon. Net proceeds from the sale transaction were $200 million with $156 million received and non-contingent consideration of $44 million to be received in 2016. The carrying amount of $44 million, which approximates fair value, is classified in other noncurrent assets and is secured by a $40 million letter of credit from a well-capitalized, multinational bank. Between meeting the held-for-sale criteria in September 2013
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
through the first quarter of 2014, the Company has recognized impairments of $101 million representing the difference between their aggregate carrying amount of $435 million and fair value less costs to sell of $334 million. During the second quarter of 2014, the Company recognized an additional loss on sale of $7 million. These businesses were previously reported in the Europe SBU reportable segment.
Saurashtra-In October 2013, the Company executed a sale agreement for the sale of its wholly owned subsidiary AES Saurashtra Private Ltd, a 39 MW wind project in India. The sale transaction closed on February 24, 2014 and net proceeds of $8 million were received. Saurashtra was previously reported in the Asia SBU reportable segment.
U.S. wind projects-In November 2013, the Company executed an agreement for the sale of its 100% membership interests in three wind projects with an aggregate generation capacity of 234 MW: Condon in California, Lake Benton I in Minnesota and Storm Lake II in Iowa. Under the terms of the sale agreement, the buyer has an option to purchase the Company's 100% interest in Armenia Mountain, a 101 MW wind project in Pennsylvania at a fixed price of $75 million. The option is exercisable between January 1, 2015 and April 1, 2015 (both dates inclusive). Upon meeting the held-for-sale criteria for Condon, Lake Benton I and Storm Lake II, the Company recognized an impairment of $47 million (of which $7 million was attributable to noncontrolling interests held by tax equity partners) representing the difference between their aggregate carrying amount of $77 million and the fair value less costs to sell of $30 million. The sale transaction closed on January 30, 2014 and net proceeds of $27 million were received. Approximately $3 million of the net proceeds received has been deferred and allocated to the buyer's option to purchase Armenia Mountain, which is reflected within continuing operations. The disposed wind projects were previously reported in the US SBU reportable segment.
Poland wind projects-In November 2013, the Company sold AES Polish Wind Holdings B.V., ("Poland Wind") a wholly owned subsidiary that held ownership interests ranging between 61%-89% in ten wind development projects in Poland. Net proceeds from the sale transaction were $7 million and a loss on disposal of $2 million was recognized. In the third quarter of 2013, the Company recognized impairments of $65 million on these projects when they were classified as held and used. Poland Wind was previously reported in the Europe SBU reportable segment.
Ukraine utilities-In April 2013, the Company completed the sale of its two utility businesses in Ukraine to VS Energy International and received net proceeds of $113 million after working capital adjustments. The Company sold its 89.1% equity interest in AES Kyivoblenergo, which serves 881,000 customers in the Kiev region, and its 84.6% percent equity interest in AES Rivneoblenergo, which serves 412,000 customers in the Rivne region. The Company recognized net impairments of $38 million during the 2013. These businesses were previously reported in the Europe SBU reportable segment.
Tisza II-In December 2012, the Company completed the sale of its 100% ownership interest in Tisza II, a 900 MW gas/oil fired plant in Hungary. Net proceeds from the sale transaction were $14 million and the Company recognized a loss on disposal of $87 million, net of tax (including the realization of cumulative foreign currency translation loss of $73 million). Tisza II was previously reported in the Europe SBU reportable segment.
Red Oak and Ironwood-In April 2012, the Company completed the sale of its 100% interest in Red Oak, an 832 MW coal-fired plant in New Jersey, and Ironwood, a 710 MW coal-fired plant in Pennsylvania, for $228 million and recognized a gain of $73 million, net of tax. Both Red Oak and Ironwood were previously reported in the US SBU reportable segment.
Eastern Energy-In March 2011, AES Eastern Energy (“AEE”) met the held for sale criteria and was reclassified from continuing operations to held for sale. AEE operated four coal-fired power plants: Cayuga, Greenidge, Somerset and Westover, representing generation capacity of 1,169 MW in the western New York power market. In 2010, AEE had recognized a pretax impairment expense of $827 million due to adverse market conditions. In December 2011, AEE along with certain of its affiliates filed for bankruptcy protection and was recorded as a cost method investment. In December 2012, the AEE bankruptcy proceedings were finalized and a gain of $30 million, net of tax, was recognized in gain on disposal of discontinued businesses. AEE was previously reported in the US SBU reportable segment.
24. DISPOSITIONS
Ebute-On November 20, 2014, the Company completed the sale of its interest in Ebute, which included its 95% interest in AES Nigeria Barge Limited (“AES Ebute”) and its 100% interest in AES Nigeria Barge Operations Limited (“AES NBO”). Proceeds from the sale were $22 million and the Company recognized a $6 million loss on the sale in the fourth quarter of 2014. Ebute does not meet the criteria to be reported as discontinued operations under ASU No. 2014-08, which was adopted by the Company on July 1, 2014. Accordingly, Ebute's results are reflected in the Consolidated Statements of Operations within continuing operations. Excluding the loss on sale, Ebute's pretax income (loss) attributable to AES was $(27) million, $(29) million and $32 million for the years ended December 31, 2014, 2013 and 2012, respectively. Ebute is reported in the Europe SBU reportable segment.
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
U.K. wind projects-On August 22, 2014, the Company sold 100% of its interests in four operating wind projects located in the U.K. with an aggregate generation capacity of 88 MW. Total net proceeds from the sale were $158 million and the Company recognized a pretax gain on sale of $78 million. These wind projects are reported in the Europe SBU reportable segment. These wind projects do not meet the criteria to be reported as discontinued operations under ASU 2014-08 and, accordingly, the results are reflected within continuing operations. Excluding the gain on sale, the pretax income (loss) attributable to AES for these disposed projects was $(18) million, $3 million, and $(3) million for the years ended December 31, 2014, 2013 and 2012, respectively.
Trinidad Generation Unlimited-On July 10, 2013, the Company completed the sale of its 10% equity interest in Trinidad Generation Unlimited, an equity method investment, to the government of Trinidad and received net proceeds of $31 million. The carrying amount of the investment was $28 million and a gain of $3 million was recognized.
Cartagena-On April 26, 2013, the Company sold its remaining interest in AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain upon the exercise of a purchase option included in the 2012 sale agreement where the Company sold its majority interest in the business. Net proceeds from the exercise of the option were approximately $24 million and the Company recognized a pretax gain of $20 million during the second quarter of 2013. In 2012, the Company had sold 80% of its 70.81% equity interest in Cartagena and had recognized a pretax gain of $178 million. Under the terms of the 2012 sale agreement, the buyer was granted an option to purchase the Company’s remaining 20% interest during a five-month period beginning March 2013, which was exercised on April 26, 2013 as described above.
Due to the Company’s continued ownership interest, which extended beyond one year from the completion of the sale of its 80% interest in February 2012, the prior-period operating results of AES Cartagena were not classified as discontinued operations.
InnoVent and St. Patrick-On June 28, 2012, the Company closed the sale of its equity interest in InnoVent and controlling interest in St. Patrick. Net proceeds from the sale transactions were $42 million. The prior period operating results of St. Patrick were not deemed material for reclassification to discontinued operations. See Note 21-Asset Impairment Expense and Note 9-Other Non-Operating Expense for further information.
China-On September 6, 2012 and December 31, 2012, the Company completed the sale of its interest in equity method investments in China. These investments included coal-fired, hydropower and wind generation facilities accounted for under the equity method of accounting. Net proceeds from the sale were approximately $133 million and the Company recognized a pretax gain of $27 million on the transaction, which is reflected as a gain on sale of investment. See Note 9-Other Non-Operating Expense for further information.
25. EARNINGS PER SHARE
Basic and diluted earnings per share are based on the weighted-average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.
The following tables present a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the years ended December 31, 2014, 2013 and 2012. In the table below, income represents the numerator and weighted-average shares represent the denominator:
The calculation of diluted earnings per share excluded 5 million, 6 million and 7 million options outstanding at December 31, 2014, 2013 and 2012, respectively, that could potentially dilute basic earnings per share in the future. These
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
options were not included in the computation of diluted earnings per share because their exercise price exceeded the average market price during the related period.
The calculation of diluted earnings per share excluded 1 million options outstanding at December 31, 2012, that could potentially dilute earnings per share in the future. These options were not included in the computation of diluted earnings per share for the year ended December 31, 2012, because their inclusion would be anti-dilutive given the loss from continuing operations in the related period. Had the Company generated income from continuing operations in the year ended December 31, 2012, 1 million potential shares of common stock related to the restricted stock units would have been included in diluted average shares outstanding.
The calculation of diluted earnings per share also excluded 1 million restricted stock units outstanding at both December 31, 2014 and 2013, that could potentially dilute basic earnings per share in the future. These restricted stock units were not included in the computation of diluted earnings per share because the average amount of compensation cost per share attributed to future service and not yet recognized exceeded the average market price during the related period and thus to include the restricted units would have been anti-dilutive. The calculation of diluted earnings per share also excluded 6 million restricted stock units outstanding at December 31, 2012, that could potentially dilute earnings per share in the future. These restricted units were not included in the computation of diluted earnings per share for the year ended December 31, 2012, because their impact would be anti-dilutive given the loss from continuing operations. Had the Company generated income from continuing operations in the year ended December 31, 2012, 4 million potential shares of common stock related to the restricted stock units would have been included in diluted average shares outstanding.
For the years ended December 31, 2014, 2013 and 2012, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive.
During the year ended December 31, 2014, 1 million shares of common stock were issued under the Company’s profit sharing plan.
26. RISKS AND UNCERTAINTIES
AES is a diversified power generation and utility company organized into six market-oriented SBUs. See additional discussion of the Company’s principal markets in Note 17-Segment and Geographic Information. Within our six SBUs, we have two primary lines of business: Generation and Utilities. The Generation line of business uses a wide range of fuels and technologies to generate electricity such as coal, gas, hydro, wind, solar and biomass. Our Utilities business is comprised of businesses that transmit, distribute, and in certain circumstances, generate power. In addition, the Company has operations in the renewables area. These efforts include projects primarily in wind and solar.
Operating and Economic Risks-The Company operates in several developing economies where macroeconomic conditions are usually more volatile than developed economies. Deteriorating market conditions often expose the Company to the risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets. Additionally, credit markets around the globe continue to tighten their standards, which could impact our ability to finance growth projects through access to capital markets. Currently, the Company has a below-investment grade rating from Standard & Poor’s of BB-. This could affect the Company's ability to finance new and/or existing development projects at competitive interest rates. As of December 31, 2014, the Company had $1.5 billion of unrestricted cash and cash equivalents.
During 2014, approximately 78% of our revenue, and 99% of our revenue from discontinued businesses, was generated outside the United States and a significant portion of our international operations is conducted in developing countries. We continue to invest in several developing countries to expand our existing platform and operations. 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;
•
inability to economically hedge energy prices;
•
volatility in commodity prices;
•
adverse changes in currency exchange rates;
•
government restrictions on converting currencies or repatriating funds;
•
unexpected changes in foreign laws, regulatory framework, or in trade, monetary or fiscal policies;
•
high inflation and monetary fluctuations;
•
restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
•
threatened or consummated expropriation or nationalization of our assets by foreign governments;
•
unwillingness of governments, government agencies, similar organizations or other counterparties to honor their commitments;
•
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, 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, indexation of certain PPAs to fuel prices, and currency fluctuations being experienced in many of these countries particularly Argentina. 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 reasonable increases in tariffs 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 Utility businesses where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:
•
changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;
•
changes in the definition or determination of controllable or noncontrollable costs;
•
adverse changes in tax law;
•
changes in the definition of events which may or may not qualify as changes in economic equilibrium;
•
changes in the timing of tariff increases;
•
other changes in the regulatory determinations under the relevant concessions; or
•
changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect our results of operations.
Foreign Currency Risks-AES operates businesses in many foreign countries and such operations could be impacted by significant fluctuations in foreign currency exchange rates. Fluctuations in currency exchange rate between U. S. Dollar and the following currencies could create significant fluctuations to earnings and cash flows: the Argentine peso, the Brazilian real, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian peso, the Philippine peso and the Kazakhstan tenge.
Concentrations-Due to the geographical diversity of its operations, the Company does not have any significant concentration of customers or sources of fuel supply. Several of the Company’s generation businesses rely on PPAs with one or a limited number of customers for the majority of, and in some cases all of, the relevant businesses' output over the term of the PPAs. However, no single customer accounted for 10% or more of total revenue in 2014, 2013 or 2012.
The cash flows and results of operations of our businesses depend on the credit quality of their customers and the continued ability of their customers and suppliers to meet their obligations under PPAs and fuel supply agreements. If a substantial portion of the Company’s long-term PPAs and/or fuel supply were modified or terminated, the Company would be adversely affected to the extent that it would be unable to replace such contracts at equally favorable terms.
Bulgaria- Maritza, the Company's generation facility in Bulgaria, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by our offtaker, NEK. As of December 31, 2014, Maritza’s outstanding accounts receivable were $262 million, of which $205 million were overdue. No allowance has been recognized on the receivables as the Company continues to assert that collection is probable.
The newly elected Bulgarian government has undertaken an initiative to reform its energy sector, which is necessary to restore NEK’s liquidity. NEK’s credit rating was downgraded and its transmission license was revoked by the Bulgarian
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
DECEMBER 31, 2014, 2013, AND 2012
Regulator, which are events of default under the PPA and triggered additional events of default by Maritza under the project debt agreements.
Although Maritza continued to collect overdue receivables during the fourth quarter of 2014 and thereafter, collections continue to be at risk, which could result in an allowance to be recorded against the remaining receivables and exacerbate liquidity problems at Maritza if the situation were to deteriorate significantly.
27. RELATED PARTY TRANSACTIONS
Certain of our businesses in Panama, the Dominican Republic and Kazakhstan are partially owned by governments either directly or through state-owned institutions. In the ordinary course of business, these businesses enter into energy purchase and sale transactions, and transmission agreements with other state-owned institutions which are controlled by such governments. At two of our generation businesses in Mexico, the offtakers exercise significant influence, but not control, through representation on these businesses’ Boards of Directors. These offtakers are also required to hold a nominal ownership interest in such businesses. In Chile, we provide capacity and energy under contractual arrangements to our investment which is accounted for under the equity method of accounting. Additionally, the Company provides certain support and management services to several of its affiliates under various agreements.
The Company’s Consolidated Statements of Operations included the following transactions with related parties for the periods indicated:
The following table summarizes the balances receivable from and payable to related parties included in the Company’s Consolidated Balance Sheets as of the periods indicated:
28. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data
The following tables summarize the unaudited quarterly statements of operations for the Company for 2014 and 2013. Amounts have been restated to reflect discontinued operations in all periods presented and 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, 2014, 2013, AND 2012
(1)
Includes pretax impairment expense of $166 million, $107 million, $31 million and $79 million, for the first, second, third and fourth quarters of 2014, respectively. See Note 9-Other Non-Operating Expense, Note 10-Goodwill and Other Intangible Assets, and Note 21-Asset Impairment Expense for further discussion.
(2)
Includes a pretax gain of approximately $283 million for the second quarter of 2014 related to the sale of a noncontrolling interest in Masinloc. See Note 16-Equity for further discussion. Includes pretax gain of approximately $78 million for the third quarter of 2014 related to the sale of the U.K. wind projects. See Note 24-Dispositions for further discussion. Includes pretax interest income of $59 million recognized on FONIVEMEM III receivables at AES Argentina in the fourth quarter of 2014. Also includes a pretax foreign currency derivative gain of $106 million recognized on the FONIVEMEM III receivables in the fourth quarter of 2014. See Note 7-Financing Receivables for further discussion. Includes pretax loss of $41 million recognized in Net equity in earnings of affiliates corresponding to the Company's share of an asset impairment at Elsta. See Note 8-Investments In And Advances To Affiliates for further discussion.
(3)
Includes pretax impairment expense of $48 million, $0 million, $196 million and $352 million, for the first, second, third and fourth quarters of 2013, respectively. See Note 9-Other Non-Operating Expense, Note 10-Goodwill and Other Intangible Assets, and Note 21-Asset Impairment Expense for further discussion.
29. SUBSEQUENT EVENTS
Stock Repurchase Program-The Company continued stock repurchases after December 31, 2014 under its stock repurchase program. In addition, the Company's Board of Directors authorized an increase in the Program by an additional $400 million. For additional information on stock repurchases after December 31, 2014, see Note 16-Equity.
IPALCO-On December 15, 2014, the Company entered into an agreement to sell 15% of AES US Investment, Inc. for $247 million. This transaction closed on February 11, 2015. See Note 16-Equity for further information.
Maritza-In February 2015, the Company signed a Memorandum of Understanding with the Government of Bulgaria to commence negotiations on proposed amendments to the existing PPA with NEK, which includes the payment of all outstanding receivables.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the CEO and 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, 2014, 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, 2014. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in 2013. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2014.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, 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, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited The AES Corporation’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework) (the COSO criteria). The AES Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, The AES Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, 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 as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2014 of The AES Corporation and our report dated February 25, 2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
McLean, Virginia
February 25, 2015
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following information is incorporated by reference from the Registrant’s Proxy Statement for the Registrant’s 2015 Annual Meeting of Stockholders which the Registrant expects will be filed on or around March 10, 2015 (the “2015 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; and
•
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 2015 Proxy Statement and is herein incorporated by reference.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The following information is contained in the 2015 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the heading Compensation Discussion and Analysis and the Compensation Committee Report on Executive Compensation under the heading Report of the Compensation Committee.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
(a)
Security Ownership of Certain Beneficial Owners.
See the information contained under the caption “Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers” of the 2015 Proxy Statement, 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 2015 Proxy Statement, which information is incorporated herein by reference.
(c)
Changes in Control.
None.
(d)
Securities Authorized for Issuance under Equity Compensation Plans.
The following table provides information about shares of AES common stock that may be issued under AES’ equity compensation plans, as of December 31, 2014:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2014)
(1)
The following equity compensation plans have been approved by the Company’s Stockholders:
(A)
The AES Corporation 2003 Long Term Compensation Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES’s stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES’s stockholders, bringing the total authorized shares to 38,000,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $14.78 (excluding PSU and RSU awards), with 13,859,232 shares available for future issuance.
(B)
The AES Corporation 2001 Plan for outside directors adopted in 2001 provided for 2,750,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $18.62. In conjunction with the 2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any remaining shares under this plan,
which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 2,061,723 shares is not included in Column (c) above.
(C)
The AES Corporation Second Amended and Restated Deferred Compensation Plan for directors provided for 2,000,000 shares authorized for issuance. Column (b) excludes the Director stock units granted thereunder. In conjunction with the 2010 amendment to the 2003 Long Term Compensation Plan, ongoing award issuance from this plan was discontinued in 2010 as Director stock units will be issued from the 2003 Long Term Compensation Plan. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance and thus the amount of 105,341 shares is not included in Column (c) above.
(D)
The AES Corporation Incentive Stock Option Plan adopted in 1991 provided for 57,500,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $35.44. This plan terminated on June 1, 2001, such that no additional grants may be granted under the plan after that date. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance in light of this plan’s termination and thus 24,354,930 shares are not included in Column (c) above.
(2)
Includes 4,993,450 (of which 832,757 are vested and 4,160,693 are unvested) shares underlying PSU and RSU awards (assuming performance at a maximum level), 1,487,156 shares underlying Director stock unit awards, and 7,061,847 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 13,542,453 shares.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information regarding related party transactions required by this item is included in the 2015 Proxy Statement found under the headings Transactions with Related Persons, Proposal I: Election of Directors and The Committees of the Board and are incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information concerning principal accountant fees and services included in the 2015 Proxy Statement contained under the heading Information Regarding The Independent Registered Public Accounting Firm’s Fees, Services and Independence and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Financial Statements.
(b)
Exhibits.
(c)
Schedules
Schedule I-Condensed Financial Information of Registrant
Schedule II-Valuation and Qualifying Accounts
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
THE AES CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule I-Condensed Financial Information of Registrant
S-2
Schedule II-Valuation and Qualifying Accounts
S-7
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.
See Notes to Schedule I
S-1
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
BALANCE SHEETS
See Notes to Schedule I.
S-2
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF OPERATIONS
See Notes to Schedule I.
S-3
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012
See Notes to Schedule I.
S-4
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF CASH FLOWS
See Notes to Schedule I.
S-5
THE AES CORPORATION
SCHEDULE I
NOTES TO SCHEDULE I
1. Application of Significant Accounting Principles
The Schedule I Condensed Financial Information of the Parent includes the accounts of The AES Corporation (the “Parent Company”) and certain holding companies.
Accounting for Subsidiaries and Affiliates-The Parent Company has accounted for the earnings of its subsidiaries on the equity method in the financial information.
Income Taxes-Positions taken on the Parent Company’s income tax return which satisfy a more-likely-than-not threshold will be recognized in the financial statements. The income tax expense or benefit computed for the Parent Company reflects the tax assets and liabilities 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-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.
2. Debt
Senior Notes and Loans Payable
Junior Subordinated Notes Payable
FUTURE MATURITIES OF DEBT-Recourse debt as of December 31, 2014 is scheduled to reach maturity as set forth in the table below:
3. Dividends from Subsidiaries and Affiliates
Cash dividends received from consolidated subsidiaries were $880 million, $818 million, and $1.14 billion for the years ended December 31, 2014, 2013, and 2012, respectively. There were no cash dividends received from affiliates accounted for by the equity method for the years ended December 31, 2014, 2013, and 2012.
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
S-6
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, 2014, by the terms of the agreements, to an aggregate of approximately $417 million representing 17 agreements with individual exposures ranging from less than $1 million up to $53 million. These amounts exclude normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.
LETTERS OF CREDIT-At December 31, 2014, the Company had $61 million in letters of credit outstanding under the senior unsecured credit facility representing 5 agreements with individual exposures ranging from less than $1 million up to $29 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. At December 31, 2014, the Company had $74 million in cash collateralized letters of credit outstanding representing 9 agreements with individual exposures ranging from less than $1 million up to $47 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. During 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts.
THE AES CORPORATION
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(IN MILLIONS)
S-7