Company: AES CORP
CIK: 874761
SIC: 4991
Filing Date: 2020-02-28 00:00:00

ITEM 1 - BUSINESS
ITEM 1. BUSINESS
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 - RISK FACTORS
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 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 associated with our operations;
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risks associated with governmental regulation and laws; and
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risks related to our indebtedness and financial condition.
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 Associated with our Operations
The operation of power generation, distribution and transmission facilities involves significant risks.
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
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requirements, or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, dam failures, tsunamis, 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.
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 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. We believe these countries may have higher growth rates and offer greater opportunities, 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, fiscal or environmental policies;
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high inflation and monetary fluctuations;
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restrictions on imports of solar panels, wind turbines, 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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unexpected delays in permitting and governmental approvals;
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unexpected changes or instability affecting our strategic partners in developing countries;
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risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, UK Bribery Act or other anti-bribery laws applicable to our operations, including, among other things, cost and disruption in responding to allegations or investigations (regardless of ultimate finding), civil and/or criminal fines, criminal prosecution of individuals, revocation or suspension of permits and/or licenses, civil litigation, reputational damage, loss in share price, and loss of business;
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unwillingness of governments and their 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 less beneficial 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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potentially adverse tax consequences of operating in multiple jurisdictions; and
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difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local 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 caused by regulatory and economic difficulties, political instability and currency devaluations. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.
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.
Some of our businesses sell or buy electricity in the spot markets when they operate at levels that differ from their power sales agreements or retail load obligations or when they do not have any powers sales agreements. 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 generally reflect the variable cost of the source generation which could include renewable sources at near zero pricing or thermal sources subject to fluctuating cost of fuels such as coal, natural gas or oil derivative fuels in addition to other factors described below. Consequently, any changes in the generation supply stack and cost of coal, natural gas, or oil derivative fuels 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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seasonality;
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hydrology and other weather conditions;
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illiquid markets;
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transmission, transportation constraints, inefficiencies and/or availability;
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renewables source contribution to the supply stack;
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new entrants;
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increased adoption of distributed generation;
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energy efficiency and demand side resources;
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available supplies of coal, natural gas, and crude oil and refined products;
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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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general economic conditions globally as well as in areas where we operate that impact demand and energy consumption; and
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bidding behavior and market bidding rules.
Wholesale power prices are declining in many markets and this could have a material adverse effect on our operations and opportunities for future growth.
The wholesale prices offered for electricity have declined significantly in recent years in many markets in which the Company has businesses. This price decline is due to a variety of factors, including the increased penetration of renewable generation resources, low-priced natural gas and demand side management. The levelized cost of electricity from new solar and wind generation sources has dropped substantially in recent years as solar panel costs and wind turbine costs have declined, while wind and solar capacity factors have increased. These renewable resources have no fuel costs and very low operational costs. In many instances, energy from these facilities are bid into the wholesale spot market at a price of zero or close to zero during certain times of the day, driving down the clearing price for all generators selling power in the relevant spot market. Also, in many markets, new PPAs have been awarded for renewable generation at prices significantly lower than the prices being awarded just a few years ago.
This trend of declining wholesale prices could continue and could have a material adverse impact on the financial performance of our existing generation assets to the extent they currently sell power into the spot market or will seek to sell power into the spot market once their PPAs expire. The trend of declining prices can also make it more difficult for us to obtain attractive prices under new long-term PPAs for any new generation facilities we may seek to develop. As a result, the trend can have an adverse impact on our opportunities for new investments.
Adverse economic developments in China could have a negative impact on demand for electricity in many of our markets.
The Chinese market has been driving global materials demand and pricing for commodities over the past decade. Many of these commodities are produced in areas that are also our key markets for the sale of electricity. After experiencing rapid growth for more than a decade, China’s economy has experienced decreasing foreign and domestic demand, weak investment, factory overcapacity and oversupply in the property market, and has experienced a significant slowdown in recent years. U.S. tariffs are also expected to have a negative impact on China's economic growth. In addition, the outbreak of the Coronavirus is a rapidly developing situation in China that has adversely impacted economic activity and conditions in China. In particular, efforts to control the spread of the Coronavirus have led to shutdowns of manufacturing facilities and disrupted supply chains. The extent of such impact is unknown at this time. Continued slowing in China’s economic growth, demand for commodities and/or material changes in policy could result in lower economic growth and lower demand for electricity in our key markets, which could have a material adverse effect on our results of operations, financial condition and prospects.
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We may not have adequate risk mitigation and/or insurance coverage for liabilities.
Power generation, distribution and transmission involves hazardous activities. We may become exposed to significant liabilities for which we may not have adequate risk mitigation and/or insurance coverage. Furthermore, through AGIC, AES’ captive insurance company, we take certain insurance risk on our businesses. 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. Our insurance does not cover every potential risk associated with our operations. Adequate coverage at reasonable rates is not always obtainable. In particular, the availability of insurance for coal-fired generation assets has decreased as certain insurers have opted to discontinue or limit offering insurance for such assets. Certain insurers have also withdrawn from insuring hydroelectric assets following significant losses in that business class. For these reasons, as well as the cyclical nature of the insurance markets, we cannot provide assurance that insurance coverage will continue to be available in the amounts or on terms similar to those presently available to us. In addition, insurance may not fully cover the liability or the consequences of any business interruptions such as natural catastrophes, 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 our business, results or operations, financial condition, and prospects.
We may not be able to enter into long-term contracts that reduce volatility in our results of operations.
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 more than 20 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 and renewables such as wind and solar have also caused, and could continue to cause, price pressure in certain power markets where we sell or
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intend to sell power. In addition, the introduction of low-cost disruptive technologies or the entry of non-traditional competitors into our sector and markets could adversely affect our ability to compete, which could have a material adverse effect on our businesses, operating results and financial condition.
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 some 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. Further, our suppliers may source certain materials from China or other areas impacted by Coronavirus, which may cause delays and/or disruptions to our development projects or operations.
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. Counterparties to these agreements may breach or may be unable to perform their obligations, due to bankruptcy, insolvency, financial distress or other factors. Furthermore, in the event of a bankruptcy or similar insolvency-type proceeding, our counterparty can seek to reject our existing PPA under the U.S. Bankruptcy Code or similar bankruptcy laws, including those in Puerto Rico. 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 financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers. Any failure of a 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.
Our businesses will need to continue to adapt to technological change and we may incur significant expenditures to adapt to these changes.
Emerging technologies may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to remain competitive, or may result in the obsolescence of certain of our operating assets. Our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer services and products that meet customer demands and evolving industry standards.
Technological changes that could impact our businesses include:
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technologies that change the utilization of electric generation, transmission and distribution assets, including the expanded cost-effective utilization of distributed generation (e.g., rooftop solar and community solar projects), and energy storage technology;
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advances in distributed and local power generation and energy storage that reduce the demand for large-scale renewable electricity generation and/or impact our customers’ ability to perform under long-term agreements; and
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more cost-effective batteries for energy storage, advances in solar or wind technology, and advances in alternative fuels and other alternative energy sources.
Emerging technologies may also allow new competitors to more effectively compete in our markets or disintermediate the services we provide our customers, including traditional utility and centralized generation services. If we incur significant expenditures in adapting to technological changes, fail to adapt to significant technological changes, fail to obtain access to important new technologies, fail to recover a significant portion of any remaining investment in obsolete assets, or if implemented technology fails to operate as intended, our businesses, operating results and financial condition could be materially adversely affected.
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Cyber-attacks and data security breaches could harm our business.
Our business is heavily reliant on electronic systems and network technologies to operate our generation, transmission and distribution infrastructure. We also use various financial, accounting and other infrastructure systems. Our infrastructure may be targeted by nation states, hacktivists, criminals, insiders or terrorist groups. Such an attack, by hacking, malware or other means, may interrupt our operations, cause property damage, affect our ability to control our infrastructure assets, cause the release of sensitive customer information or limit communications with third parties. Any loss or corruption of confidential or proprietary data through such breach may:
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impact our operations and strategic objectives;
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impact our customer and vendor relationships;
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result in substantial revenue loss;
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expose us to legal claims and/or regulatory investigations and proceedings;
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require extensive repair and restoration costs for additional security measures to avert future cyber-attacks; and
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impair our reputation and limit our competitiveness for future opportunities.
In addition, a breach of our financial and accounting systems could impact our ability to correctly record, process and report financial information.
We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. To date, cyber-attacks have not had a material impact on our operations or financial results. We continue to assess potential threats and vulnerabilities and make investments to address them, including global monitoring of networks and systems, identifying and implementing new technology, improving user awareness through employee security training, and updating our security policies as well as those for third-party providers.
We cannot guarantee the extent to which our security measures will prevent future cyber-attacks and security breaches or that our insurance coverage will adequately cover any losses we may experience. Furthermore, we do not control certain of joint ventures or our equity method investments and cannot guarantee that their efforts will be successful.
Certain of our businesses are sensitive to variations in weather and hydrology.
Our businesses are affected by variations in general weather patterns and unusually severe weather. Our businesses forecast electric sales based on best available information and expectations for 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.
Changes in weather can also affect the production of electricity at power generation facilities, including, but not limited to, our wind and solar facilities. For example, the level of wind resource affects the revenue produced by wind generation facilities. Because the levels of wind and solar resources are variable and difficult to predict, our results of operations for individual wind and solar facilities specifically, and our results of operations generally, may vary significantly from period to period, depending on the level of available resources. To the extent that resources are not available at planned levels, the financial results from these facilities may be less than expected. 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. Changes in temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric generation.
To the extent that hydrological conditions result in droughts or other conditions negatively affect our hydroelectric generation business, such as has happened in Panama in 2019, our results of operations can be materially adversely affected. Additionally, our contracts in certain markets where hydroelectric facilities are prevalent may require us to purchase power in the spot markets when our facilities are unable to operate (or operate at lower than anticipated levels) and the price of such spot power may increase substantially in times of low hydrology.
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Severe weather and natural disasters may present significant risks to our business.
Weather conditions directly influence the demand for electricity and natural gas and other fuels and affect the price of energy and energy-related commodities. In addition, severe weather and natural disasters, such as hurricanes, floods, tornadoes, icing events, earthquakes, dam failures and tsunamis can be destructive and could prevent us from operating our business in the normal course by causing power outages and property damage, reducing revenue, affecting the availability of fuel and water, causing injuries and loss of life, and requiring us to incur additional costs, for example, to restore service and repair damaged facilities, to obtain replacement power and to access available financing sources. Our power plants could be placed at greater risk of damage should changes in the global climate produce unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, including heatwaves, fewer cold temperature extremes, abnormal levels of precipitation resulting in river and coastal urban floods in North America or reduced water availability and increased flooding across Central and South America, and changes in coast lines due to sea level change.
Depending on the nature and location of the facilities and infrastructure affected, any such incident also could cause catastrophic fires; releases of natural gas, natural gas odorant, or other greenhouse gases; explosions, spills or other significant damage to natural resources or property belonging to third parties; personal injuries, health impacts or fatalities; or present a nuisance to impacted communities. Such incidents that do not directly affect our facilities may impact our business partners, supply chains and transportation, which could negatively impact construction projects and our ability to provide electricity and natural gas to our customers.
A disruption or failure of electric generation, transmission or distribution systems or natural gas production, transmission, storage or distribution systems in the event of a hurricane, tornado or other severe weather event, or otherwise, could prevent us from operating our business in the normal course and could result in any of the adverse consequences described above. At our businesses where cost recovery is available, recovery of costs to restore service and repair damaged facilities is or may be subject to regulatory approval, and any determination by the regulator not to permit timely and full recovery of the costs incurred.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, reputation and prospects.
Our development projects are subject to substantial uncertainties.
Certain of our subsidiaries and affiliates are in various stages of developing and constructing power plants. Some but not all of these power plant projects have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion of the development of these projects 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 important elements for a successful project. For example, our subsidiaries may instruct contractors to begin the construction process or seek to procure equipment even where they do not have financing, a PPA or critical permits in place (or conversely, to enter into a PPA, procurement agreement 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.
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We do not control certain aspects of our joint ventures or our equity method investments.
We have invested in some joint ventures in which 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 in which we do have majority control of the voting securities, we have entered into shareholder agreements granting 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 that 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, which means that we may be responsible for meeting certain obligations of the joint ventures, should our joint venture partner be unable to do so, if and to the extent provided for in our governing documents or applicable law.
In addition, we are generally dependent on the management team of our equity method investments to operate and control such projects or businesses. While we may exert influence pursuant to having positions on the boards of such investments and/or through certain limited governance rights, such as rights to veto significant actions, we do not always have this type of influence in every instance and the scope and impact of such influence may be limited. The management teams of our equity method investments 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, which could have a material adverse effect on value of such investments as well as our growth, business, financial condition, results of operations and prospects.
Our renewable energy projects and other initiatives face considerable uncertainties, including development, operational, and regulatory challenges.
Wind, solar, and energy storage projects are subject to substantial risks. 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. These wind resource estimates are not expected to reflect actual wind energy production in any given year, but long-term averages of a resource.
As a result, these types of renewable energy projects face considerable risk, 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 our more 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. 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.
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Government incentives and policies that support the development of renewable energy generation projects could change at any time.
AES’ U.S. renewable energy generation growth strategy depends in part on federal, state and local government policies and incentives that support the development, financing, ownership and operation of renewable energy generation projects. These policies and incentives include investment tax credits, production tax credits, accelerated depreciation, renewable portfolio standards, feed-in-tariffs and similar programs, renewable energy credit mechanisms, and tax exemptions. If these policies and incentives are changed or eliminated, or AES is unable to use them, it could result in a material adverse impact on AES’ U.S. renewable growth opportunities, including fewer future PPAs or lower prices for the sale of power in future PPAs, decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing.
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 several 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.
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 underlying exposure (usually the pricing node of the generation facility). 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, while we seek to protect against that by utilizing strong credit requirements and exchange trades, these protections may not fully cover the exposure in the event of a counterparty default.
For our businesses with PPA pricing that does not completely 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.
We may not be able to attract and retain skilled people.
Our operating success and ability to carry out growth initiatives depends, in part, on our ability to retain
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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.
Our utilities businesses may be negatively affected by a lack of growth or slower growth in the number of customers or in customer usage.
Customer growth and customer usage in our utilities businesses are affected by a number of factors outside our control, such as mandated energy efficiency measures, demand side management requirements, and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. A lack of growth, or a decline, in the number of customers or in customer demand for electricity may cause us to fail to fully realize the anticipated benefits from significant investments and expenditures and could have a material adverse effect on our growth, business, financial condition, results of operations and prospects.
Some of our subsidiaries participate in defined benefit pension plans and their net pension plan obligations may require additional significant contributions.
We have 28 defined benefit plans, five at U.S. subsidiaries and the remaining plans at foreign subsidiaries, which cover substantially all of the employees at these 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 incorrect, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. We periodically evaluate the value of the pension plan assets to ensure that they will be sufficient to fund the respective pension obligations. Our 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 generally 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 that participate in these plans are responsible for satisfying the funding requirements required by law in their respective jurisdictions for any shortfall of pension plan assets as compared to pension obligations under the pension plan. Satisfying such funding requirements 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 Policies and Estimates-Pension and Other Postretirement Plans and Note 15.-Benefit Plans included in Item 8.-Financial Statements and Supplementary Data included in this Form 10-K.
Impairment of goodwill or long-lived assets would negatively impact our consolidated results of operations and net worth.
As of December 31, 2019, the Company had approximately $1.1 billion of goodwill, which represented approximately 3% 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 may 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; lower forecasted revenue; increase in fuel costs, particularly when we are unable to pass through the impact to customers; increase in environmental compliance costs; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; developments in our strategy; divestiture of a significant component of our business; or adverse actions or assessments by a regulator. For example, during the annual goodwill impairment test performed as of October 1, 2019, the Company determined that the fair value of its Gener reporting unit exceeded its carrying value by 3%. Therefore, Gener's $868 million goodwill balance was considered to be "at risk" for impairment as of December 31, 2019, largely due to the Chilean Government's announcement to phase out coal generation by 2040, and a decline in long-term energy prices. See Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations-Key Trends and Uncertainties-Impairments. These types of events and the resulting analyses could result in goodwill impairment, which could substantially affect our results of
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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, similar to those described above for goodwill, are present, whereas goodwill is also evaluated for impairment on an annual basis.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, and prospects.
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 ability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any ability 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 or limit the dispatch of our generating facilities within 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 operating 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. The impacts described above could also result from our (or our subsidiaries') efforts to comply with European Market Infrastructure Regulation, which includes regulations related to the trading, reporting and clearing of derivatives. 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.
Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR.
CCR, which consists of bottom ash, fly ash and air pollution control wastes generated at our current and former coal-fired generation plant sites, is currently handled and/or has been handled in the past in the following ways: placement in onsite CCR ponds; disposal and beneficial use in onsite and offsite permitted, engineered landfills; use in various beneficial use applications, including encapsulated uses and structural fill; and used in permitted offsite mine reclamation. CCR currently remains onsite at several of our facilities, including in CCR ponds. The U.S. EPA's final CCR rule, which became effective in October 2015, regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR ponds, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On December 16, 2016, President Obama signed the WIN Act into law, which includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. The primary enforcement mechanisms under this regulation could be actions commenced by U.S. EPA, states, or territories, and private lawsuits. Compliance with the U.S. federal CCR rule; amendments to the federal CCR rule; or federal, state, territory, or foreign rules or programs addressing CCR may require us to incur substantial costs. In addition, the Company and our businesses may face CCR-related lawsuits in the United States and/or internationally that may expose us to unexpected potential liabilities. Furthermore, CCR-related litigation may also expose us to unexpected costs. In addition, CCR, and its production at several of our facilities, have been the subject of significant interest from environmental non-governmental organizations and have received national and local media attention. The direct and indirect effects of such media attention, and the demands of responding to and addressing it, may divert management time and attention. Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, reputation and prospects.
Our business in the United States is subject to the provisions of various laws and regulations administered in whole or in part by FERC and NERC, including PURPA, the FPA, and the EPAct 2005. Actions by FERC, NERC and by state utility commissions can have a material effect on our operations.
The AES Corporation is a registered electric holding company under the U.S. Public Utility Holding Company Act of 2005 ("PUHCA 2005") as enacted as part of the EPAct 2005. PUHCA 2005 eliminated many of the restrictions that had been in place under the U.S. Public Utility Holding Company Act of 1935, while continuing to provide FERC and state utility commissions with enhanced access to the books and records of certain utility holding companies. PUHCA 2005 also creates additional potential challenges and opportunities. By removing some barriers to mergers and other potential combinations, the creation of large, geographically dispersed utility holding companies is more likely. These entities may have enhanced financial strength and therefore an increased ability to compete with us in the U.S. market.
Other parts of the EPAct 2005 allow FERC to remove the PURPA purchase/sale obligations from utilities if there are adequate opportunities to sell into competitive markets. FERC has exercised this power with a rebuttable presumption that utilities located within the control areas of MISO, PJM, ISO New England, Inc., the New York Independent System Operator, Inc., and ERCOT are not required to purchase or sell power from or to QFs above a certain size. Additionally, FERC has the power to remove the purchase/sale obligations of individual utilities on a case-by-case basis. While these changes do not affect existing contracts, certain of our QFs that have had sales
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contracts expire are now facing a more difficult market environment and that is likely to continue for other AES QFs with existing contracts that will expire over time.
In accordance with Congressional mandates in the EPAct 1992 and the EPAct 2005, FERC has strongly encouraged competition in wholesale electric markets. Increased competition may have the effect of lowering our operating margins. Among other steps, 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 generation assets. Similarly, 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.
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. 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. As a result, FERC is authorized to assess a maximum penalty authority established by statute and such penalty authority has been and will continue to be adjusted periodically to account for inflation. 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 U.S. 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. Violations of NERC reliability standards are subject to FERC's penalty authority under the FPA and EPAct 2005.
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 and Utilities SBU for further information on the regulation faced by our U.S. utilities.
Our businesses are subject to stringent environmental laws, rules 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. Failure to comply with such laws and regulations or to obtain or comply with any associated environmental permits could result in fines or other sanctions. For example, in recent years, the EPA has issued notices of violation ("NOVs") to a number of 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 and obtained settlements with many companies for allegedly making major modifications to a coal-fired generating units without proper permit approvals and without installing best available control technology. The primary focus of these NOVs has been emissions of SO2 and NOx and the EPA has imposed fines and required companies to install improved pollution control technologies to reduce such emissions. In addition, state regulatory agencies and non-governmental environmental organizations have pursued civil lawsuits against power plants in situations that have resulted in judgments and/or settlements requiring the installation of expensive pollution controls or the accelerated retirement of certain electric generating units.
Furthermore, 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. 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. See the various descriptions of these laws and regulations contained in Item 1.-Business-Environmental and Land-Use Regulations of this Form 10-K.
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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 development of, environmental restrictions may force us to incur significant expenses or expenses that may exceed our estimates. There can be no assurance that we would be able to recover all or any increased environmental costs from our customers or that our business, financial condition, including recorded asset values or results of operations, would not be materially and adversely affected by such expenditures or any changes in domestic or foreign environmental laws and regulations.
Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses.
International, federal and various regional and state authorities regulate GHG emissions and have created financial incentives to reduce them. In 2019, the Company's subsidiaries operated businesses that had total CO2 emissions of approximately 55 million metric tonnes, approximately 23 million of which were emitted by our U.S. businesses (both figures are 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-fired 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 7 million metric tonnes (ownership adjusted). This overall estimate is based on a number of projections and assumptions that 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.
There currently is no U.S. federal legislation imposing mandatory GHG emission reductions (including for CO2) that affects our electric power generation facilities; however, in 2015, the EPA promulgated a rule establishing New Source Performance Standards for CO2 emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUs larger than 25 MW and in 2018 proposed revisions to the rule. In 2019, the EPA promulgated the Affordable Clean Energy (ACE) Rule replacing the EPA's 2015 Clean Power Plan (CPP), which was revoked in 2019. The ACE Rule establishes heat rate improvement measures as the best system of emissions reductions for existing coal-fired electric generating units. These actions have been challenged in court and the current Administration has announced plans to significantly amend or rescind the rules. In 2010, the EPA adopted regulations pertaining to GHG emissions that require new and existing sources of GHG emissions to potentially obtain new source review permits from the EPA prior to construction or modification. In 2016, the U.S. Supreme Court ruled that such permitting would only be required if such sources also must obtain a new source review permit for increases in other regulated pollutants.
For further discussion of the regulation of GHG emissions, including the U.S. Supreme Court's issued order staying implementation of the CPP, and the EPA's proposal to rescind the CPP, see Item 1.-Business-Environmental and Land-Use Regulations-United States Environmental and Land-Use Legislation and Regulations-Greenhouse Gas Emissions above.
In December 2015, the Parties to the United Nations Framework Convention on Climate Change convened for the 21st Conference of the Parties and the resulting Paris Agreement established a long-term goal of keeping the increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris Agreement will continue the trend toward efforts to de-carbonize the global economy and to further limit GHG emissions. On November 4, 2019, the U.S. announced that it had officially notified the U.N. that the U.S. will withdraw from the Paris Agreement as soon as November 4, 2020.
The impact of GHG regulation on our operations will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulation, 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. The costs of compliance could be substantial.
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Our non-utility, generation subsidiaries seek to pass on any costs arising from CO2 emissions to contract counterparties. Likewise, our utility subsidiaries seek to pass on any costs arising from CO2 emissions to customers. However, there can be no assurance that we will effectively pass such costs onto the contract counterparties or customers, respectively, or that the cost and burden associated with any dispute over which party bears such costs would not be burdensome and costly.
In addition to government regulators, many groups, including politicians, environmentalists, the investor community and other private parties have expressed increasing concern about GHG emissions. New regulation, such as the initiatives in Chile and the Puerto Rico Energy Public Policy Act, may adversely affect our operations. See Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations-Key Trends and Uncertainties-Decarbonization Initiatives. Responding to these decarbonization initiatives may present challenges to our business. We may be unable to develop our renewables platform as quickly as anticipated. Further, we may be unable to dispose of coal-fired generation assets at anticipated prices, the estimated useful lives of these assets may decrease, and the value of such assets may be impaired. These initiatives could also result in the early retirement of coal-fired generation facilities, which could result in stranded costs if regulators disallow full recovery of investments.
Negative public perception of our GHG emissions could have an adverse effect on our relationships with third parties, our ability to attract additional customers, our business development opportunities, and our ability to access finance and insurance for our coal-fired generation assets.
In addition, plaintiffs previously brought tort lawsuits against the Company because of its subsidiaries' GHG emissions. While these lawsuits were dismissed, future similar lawsuits may prevail or result in damages awards or other relief. We may also be subject to risks associated with the impact on weather conditions. See Certain of our businesses are sensitive to variations in weather and hydrology and Severe weather and natural disasters may present significant risks to our business and adversely affect our financial results within this section for more information. If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on our electric power generation businesses and on our consolidated results of operations, financial condition,cash flows and reputation.
Concerns about data privacy have led to increased regulation and other actions that could impact our businesses.
In the ordinary course of business, we collect and retain sensitive information, including personal identification information about customers and employees, customer energy usage and other information. The theft, damage or improper disclosure of sensitive electronic data collected by us can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation. The EU GDPR applies to the processing of personal information collected from individuals located in the EU, creates additional compliance obligations and significantly increases fines for noncompliance. Furthermore, the California Consumer Privacy Act ("CCPA") has recently introduced new requirements that have broad effect, the impact of which is uncertain at this time. Any actual or perceived failure to comply with the GDPR, the CCPA, the General Data Privacy Law in Brazil or other data privacy laws or regulations, or related contractual or other obligations, or any perceived privacy rights violation, could lead to investigations, claims, and proceedings by governmental entities and private parties, damages for contract breach, and other significant costs, penalties, and other liabilities, as well as harm to our reputation and market position. In addition, any actual or perceived failure on the part of one of our equity affiliates could result in a decrease in the value of our investment as well as harm to our reputation and future business prospects.
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 U.S. and various non-U.S. jurisdictions. As such, we are subject to the tax laws and regulations of the U.S. federal, state and local governments and of many non-U.S. 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.
The TCJA enacted December 22, 2017 introduced significant changes to current U.S. federal tax law. These changes are complex and are subject to additional guidance to be issued by the U.S. Treasury and the Internal Revenue Service. In addition, the reaction to the federal tax changes by the individual states is evolving. Our
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interpretations and assumptions around U.S. tax reform may evolve in future periods as further administrative guidance and regulations are issued, which may materially affect our effective tax rate or tax payments. For further details, please see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations-Key Trends and Uncertainties in this Form 10-K.
Additionally, longstanding international tax norms that determine how and where cross-border international trade is subjected to tax are evolving. The Organization for Economic Cooperation and Development, in coordination with the G8 and G20, through its Base Erosion and Profit Shifting project introduced a series of recommendations that many tax jurisdictions have adopted, or may adopt in the future, as law. As these and other tax laws, related regulations and double-tax conventions change, our financial results could be materially impacted. Given the unpredictability of these possible changes and their potential interdependency, it is very difficult to assess whether the overall effect of such potential tax changes would be cumulatively positive or negative for our earnings and cash flow, but such changes could adversely impact our results of operations.
U.S. federal, state and local, as well as non-U.S., 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.
Risks Related to our Indebtedness and Financial Condition
We have a significant amount of debt, a large percentage of which is secured, that could adversely affect our business and our ability to fulfill our obligations.
As of December 31, 2019, we had approximately $20 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings, if any, under The AES Corporation's senior secured credit facility and secured term loan 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 available for future secured debt or credit support and reduces our flexibility in operating 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 our vulnerability to general adverse industry and economic conditions, including but not limited to adverse changes in foreign exchange rates, interest rates and commodity prices;
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reducing available 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. If we were to 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. In addition, our ability to refinance existing or future indebtedness will depend on the capital markets and our financial condition at such time. Any refinancing of our debt could come at higher interest rates or may require us to comply with onerous covenants, which could restrict our business
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operations. See Note 11.-Debt included in Item 8.-Financial Statements and Supplementary Data 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 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. 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.
Our subsidiaries face various restrictions in their ability to distribute cash. 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. Business performance and local accounting and tax rules may also limit dividend distributions. 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.
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.
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 that, 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, letters of credit, letter of credit reimbursement agreements and agreements to pay, in certain circumstances, the project lenders or other parties.
As of December 31, 2019, we had approximately $20 billion of outstanding indebtedness on a consolidated basis, of which approximately $3.4 billion was recourse debt of The AES Corporation and approximately $16.7 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 $325 million as of December 31, 2019. 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 may have provided to or on behalf of such subsidiary;
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triggering defaults in The AES Corporation's outstanding debt. For example, The AES Corporation's senior secured credit facility, secured term loan, and outstanding senior notes include events of default for certain
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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; or
•
foreclosure on the assets that are pledged under the non-recourse loans, resulting in write-downs of assets and 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.
The AES Corporation has significant cash requirements and limited sources of liquidity.
The AES Corporation requires cash primarily to fund:
•
principal repayments of debt;
•
interest;
•
acquisitions;
•
construction and other project commitments;
•
other equity commitments, including business development investments;
•
equity repurchases and/or cash dividends on our common stock;
•
taxes; and
•
Parent Company overhead costs.
The AES Corporation's principal sources of liquidity are:
•
dividends and other distributions from its subsidiaries;
•
proceeds from debt and equity financings at the Parent Company level; and
•
proceeds from asset sales.
For a more detailed discussion of The AES Corporation's cash requirements and sources of liquidity, please see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity in 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, which could prove incorrect, 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 and other distributions. 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. In addition, our cash flow may not be sufficient to repay at maturity the entire principal outstanding under our credit facility, term loan, 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 depends on our ability to raise capital on favorable terms.
From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Our ability to arrange for financing on either a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:
•
general economic and capital market conditions;
•
the availability of bank credit;
•
the financial condition, performance and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing;
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•
the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances; and
•
changes in tax and securities laws which are conducive to raising capital.
Should 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.
Difficulty raising sufficient capital to fund development projects in less developed economies could affect our growth strategy.
Part of our growth strategy is to develop 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 may 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 for 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 relevant 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.
A downgrade in the credit ratings of The AES Corporation or its subsidiaries could adversely affect our access to the capital markets, increase our interest costs and/or adversely affect our liquidity and cash flow.
If any of the credit ratings of the The AES Corporation and its subsidiaries were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs could increase. In addition, the recent downgrade in the credit ratings of DPL Inc. and DP&L may impact the cost of refinancing their respective debt securities as they come due. 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.
The market price of our common stock may be volatile.
The market price and trading volumes of our common stock could fluctuate substantially in the future. Factors that could affect the price of our common stock include, among other factors, general conditions in our industry and the power markets in which we participate, environmental and economic developments, and general credit and capital markets conditions, as well as developments specific to us, including risks that could result in revenue and earnings volatility, failing to meet our publicly announced guidance or other risk factors described in Item 1A.-Risk Factors and key trends and other matters described in Item 7.-Management's Discussion and Analysis of Financial Conditions and Results of Operations.

ITEM 1B - UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 2 - PROPERTIES
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 - Business 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.
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ITEM 3 - LEGAL PROCEEDINGS
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 when 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 consolidated 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, 2019.
In December 2001, Grid Corporation of Odisha (“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. A hearing on the liability award has not taken place to date. 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.
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 mitigate the contaminated area located on the grounds of the pole factory and an indemnity payment of approximately R$6 million ($1 million). In October 2011, the State Attorney 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 that only CEEE was required to perform the removal work. In May 2012, CEEE began the removal work in compliance with the injunction. The case is now awaiting judgment. The removal costs are estimated to be approximately R$29 million ($7 million), and there could be additional remediation costs which cannot be estimated at this time. In June 2016, the Company sold AES Sul to CPFL Energia S.A. and as part of the sale, AES Guaiba, a holding company of AES Sul, retained the potential liability relating to this matter. The Company believes that there are 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 January 2015, DPL received NOVs from the EPA alleging violations of opacity at Stuart and Killen Stations, and in October 2015, IPL received a similar NOV alleging violations at Petersburg Station. In February 2017, the EPA issued a second NOV for DPL Stuart Station, alleging violations of opacity in 2016. On May 31, 2018, Stuart and Killen Stations were retired, and on December 20, 2019, they were transferred to an unaffiliated third-party purchaser, along with the associated environmental liabilities. In October 2015, IPL received a similar NOV alleging violations at Petersburg Station. In addition, in February 2016, IPL received an NOV from the EPA alleging violations of NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Station. It is too early to determine whether the NOVs could have a material impact on our business, financial condition or results of our operations. IPL would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that IPL would be successful in this regard.
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In September 2015, AES Southland Development, LLC and AES Redondo Beach, LLC filed a lawsuit against the California Coastal Commission (the “CCC”) over the CCC's determination that the site of AES Redondo Beach included approximately 5.93 acres of CCC-jurisdictional wetlands. The CCC has asserted that AES Redondo Beach has improperly installed and operated water pumps affecting the alleged wetlands in violation of the California Coastal Act and Redondo Beach Local Coastal Program and has ordered AES Redondo Beach to restore the site. Additional potential outcomes of the CCC determination could include an order requiring AES Redondo Beach to fund a wetland mitigation project and/or pay fines or penalties. AES Redondo Beach believes that it has meritorious arguments and intends to vigorously prosecute such lawsuit, but there can be no assurances that it will be successful.
In October 2015, Ganadera Guerra, S.A. (“GG”) and Constructora Tymsa, S.A. (“CT”) filed separate lawsuits against AES Panama in the local courts of Panama. The claimants allege that AES Panama profited from a hydropower facility (La Estrella) being partially located on land owned initially by GG and currently by CT, and that AES Panama must pay compensation for its use of the land. The damages sought from AES Panama are approximately $685 million (GG) and $100 million (CT). In October 2016, the court dismissed GG's claim because of GG's failure to comply with a court order requiring GG to disclose certain information. GG has refiled its lawsuit. Also, there are ongoing administrative proceedings concerning whether AES Panama is entitled to acquire an easement over the land and whether AES Panama can continue to occupy the land. AES Panama believes it has meritorious defenses and claims and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.
In January 2017, the Superintendencia del Medio Ambiente (“SMA”) issued a Formulation of Charges asserting that Alto Maipo is in violation of certain conditions of the Environmental Approval Resolution (“RCA”) governing the construction of Alto Maipo’s hydropower project, for, among other things, operating vehicles at unauthorized times and failing to mitigate the impact of water infiltration during tunnel construction (“Infiltration Water”). In February 2017, Alto Maipo submitted a compliance plan (“Compliance Plan”) to the SMA which, if approved by the agency, would resolve the matter without materially impacting construction of the project. In April 2018, the SMA approved the Compliance Plan (“April 2018 Approval”). Among other things, the Compliance Plan as approved by the SMA requires Alto Maipo to obtain from the Environmental Evaluation Service (“SEA”) a definitive interpretation of the RCA’s provisions concerning the authorized times to operate certain vehicles. In addition, Alto Maipo must obtain the SEA’s final approval concerning the control, discharge, and treatment of Infiltration Water. Alto Maipo continues to seek the relevant final approvals from the SEA. In May 2018, three lawsuits were filed with the Environmental Court of Santiago (“ECS”) challenging the April 2018 Approval. Alto Maipo does not believe that there are grounds to challenge the April 2018 Approval. The ECS has not decided the lawsuits to date. In July 2019, a separate lawsuit was filed in the Court of Appeals of Santiago (“CAS”) seeking emergency relief to invalidate the April 2018 Approval. Alto Maipo believes there is no merit to the lawsuit, which remains pending. Furthermore, in September 2019, a petition was filed in the CAS requesting an order stopping certain construction works immediately. The CAS rejected the petition. If Alto Maipo complies with the requirements of the Compliance Plan, and if the above-referenced lawsuits are dismissed, the Formulation of Charges will be discharged without penalty. Otherwise, Alto Maipo could be subject to penalties, and the construction of the project could be negatively impacted. Alto Maipo will pursue its interests vigorously in these matters; however, there can be no assurances that it will be successful in its efforts.
In June 2017, Alto Maipo terminated one of its contractors, Constructora Nuevo Maipo S.A. (“CNM”), given CNM’s stoppage of tunneling works, its failure to produce a completion plan, and its other breaches of contract. Also, Alto Maipo drew $73 million under letters of credit (“LC Funds”) in connection with its termination of CNM. Alto Maipo is pursuing arbitration against CNM to recover excess completion costs and other damages totaling at least $236 million (net of the LC Funds) relating to CNM’s breaches (“First Arbitration”). CNM denies liability and seeks a declaration that its termination was wrongful, damages that it alleges result from that termination, and other relief. CNM alleges that it is entitled to damages ranging from $70 million to $170 million (which include the LC Funds) plus interest and costs, based on various scenarios. Alto Maipo has contested these submissions. The evidentiary hearing in the First Arbitration took place May 20-31, 2019. Post-hearing briefs were submitted in September 2019. One of the three arbitrators on the arbitral Tribunal has been replaced. The new Tribunal has determined not to repeat the May 2019 evidentiary hearing and has scheduled closing arguments for June 10-11, 2020. Also, in August 2018, CNM purported to initiate a separate arbitration against AES Gener and the Company (“Second Arbitration”). In the Second Arbitration, CNM seeks to pierce Alto Maipo’s corporate veil and appears to seek an award holding AES Gener and the Company jointly and severally liable to pay any alleged net amounts that are found to be due to CNM in the First Arbitration or otherwise. The Second Arbitration has been consolidated into the First Arbitration. The arbitral Tribunal has bifurcated the Second Arbitration to determine in the first instance the
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jurisdictional objections raised by AES Gener and the Company to CNM’s piercing claims. The hearing on the jurisdictional objections will take place in or around October 2020. Each of Alto Maipo, AES Gener, and the Company believes it has meritorious claims and/or defenses and will pursue its interests vigorously; however, there can be no assurances that each will be successful in its efforts.
In October 2017, the Maritime Prosecution Office from Valparaíso issued a ruling alleging responsibility by AES Gener for the presence of coal waste on Ventanas beach, and proposed a fine before the Maritime Governor, of approximately $380,000. AES Gener submitted its statement of defense, denying the allegations. An evidentiary stage was concluded and then re-opened by order of the Maritime Governor on February 5, 2019 to allow AES Gener a six-month period to present reports and other evidence to challenge the grounds of the ruling. In September 2019, this period was extended for an additional six months, in order to allow the execution of a field test in the bay of Ventanas. AES Gener believes that it has meritorious defenses to the allegations; however, there are no assurances that it will be successful in defending this action.
In February 2018, Tau Power B.V. and Altai Power LLP (collectively, “AES Claimants”) initiated arbitration against the Republic of Kazakhstan (“ROK”) for the ROK’s failure to pay approximately $75 million (“Return Transfer Payment”) for the return of two hydropower plants (“HPPs”) pursuant to a concession agreement. The ROK has responded by denying liability and asserting purported counterclaims concerning the annual payment provisions in the concession agreement, a bonus allegedly due for the 1997 takeover of the HPPs, and dividends paid by the HPPs. The ROK seeks to recover the Return Transfer Payment (which is in an escrow account maintained by a third party) and appears to be seeking over $500 million on its counterclaims. The AES Claimants believe that the ROK’s defenses and counterclaims are without merit and have contested the ROK’s submissions on these issues. An arbitrator was appointed to decide the case. The final evidentiary hearing took place July 22-26, 2019. The parties are awaiting the arbitrator’s decision. The AES Claimants will pursue their case and assert their defenses vigorously; however, there can be no assurances that they will be successful in their efforts.
In December 2018, a lawsuit was filed in Dominican Republic civil court against the Company, AES Puerto Rico, and three other AES affiliates. The lawsuit purports to be brought on behalf of over 100 Dominican claimants, living and deceased, and appears to seek relief relating to CCRs that were delivered to the Dominican Republic in 2004. The lawsuit generally alleges that the CCRs caused personal injuries and deaths and demands $476 million in alleged damages. The lawsuit does not identify, or provide any supporting information concerning, the alleged injuries of the claimants individually. Nor does the lawsuit provide any information supporting the demand for damages or explaining how the quantum was derived. The relevant AES companies believe that they have meritorious defenses to the claims asserted against them and will defend themselves vigorously in this proceeding; however, there can be no assurances that they will be successful in their efforts.
In February 2019, a separate lawsuit was filed in Dominican Republic civil court against the Company, AES Puerto Rico, two other AES affiliates, and an unaffiliated company and its principal. The lawsuit purports to be brought on behalf of over 200 Dominican claimants, living and deceased, and appears to seek relief relating to CCRs that were delivered to the Dominican Republic in 2003 and 2004. The lawsuit generally alleges that the CCRs caused personal injuries and deaths and demands $900 million in alleged damages. The lawsuit does not identify, or provide any supporting information concerning, the alleged injuries of the claimants individually. Nor does the lawsuit provide any information supporting the demand for damages or explaining how the quantum was derived. The relevant AES companies believe that they have meritorious defenses to the claims asserted against them and will defend themselves vigorously in this proceeding; however, there can be no assurances that they will be successful in their efforts.
In March 2019, the Puerto Rico Department of Natural and Environmental Resources (“DNER”) issued an Administrative Order, which later amended (collectively, the “DNER Order”), alleging that AES Puerto Rico, LP (“AES Puerto Rico”) failed to comply with certain DNER requests for documents and information, that AES Puerto Rico has contaminated groundwater in excess of certain state water quality standards, and requesting AES Puerto Rico to submit a corrective/remedial action plan for DNER’s review and approval, among others. The DNER Order also proposes an administrative fine of $160,000. In April 2019, AES Puerto Rico timely filed its response to the DNER Order contesting the alleged violations and the proposed fine and also moved to dismiss the case. The Hearing Examiner assigned to the case denied AES Puerto Rico’s request for dismissal. In October 2019, the Hearing Examiner granted DNER's request to postpone the filing of the prehearing report and scheduling of the prehearing conference. The parties are currently discussing a potential resolution of the Order. AES Puerto Rico believes that it has meritorious defenses, but there are no assurances that it will be successful in defending this action should it proceed to a hearing.
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In October 2019, the Superintendency of the Environment (the "SMA") notified AES Gener of certain alleged breaches associated with the environmental permit of the Ventanas Complex, initiating a sanctioning process through Exempt Resolution N° 1 / ROL D-129-2019. The alleged charges include exceeding generation limits, failing to reduce emissions during episodes of poor air quality, exceeding limits on discharges to the sea, and exceeding noise limits. As the charges are currently classified, the maximum fine is approximately $6.5 million. On October 14, 2019, the SMA notified AES Gener of other alleged breaches at the Guacolda Complex under Exempt Resolution N° 1 / ROL D-146-2019. These allegations include failure to comply with all measures to mitigate atmospheric emissions, failure to comply with mitigation measures to avoid solid fuel discharges to the sea, failure to perform temperature monitoring in intake and water discharge at Unit 3, and a one-day exceedance of the seawater discharge limits. As the Guacolda charges are currently classified, the maximum fine is approximately $4 million. For each complex, additional fines are possible if the SMA determines that non-compliance resulted in an economic benefit. AES Gener has submitted proposed "Compliance Programs" to the SMA for the Ventanas Complex and the Guacolda Complex, respectively. If these submissions are approved by the SMA and satisfactorily fulfilled by AES Gener, the process would be concluded without sanctions and not generate further action.

ITEM 4 - RESERVED
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY
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 - The Board authorization permits the Parent 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 Stock Repurchase Program does not have an expiration date and can be modified or terminated by the Board of Directors at any time. The cumulative repurchase from the commencement of the Stock Repurchase Program in July 2010 through December 31, 2019 is 154.3 million shares at a total cost of $1.9 billion, at an average price per share of $12.12 (including a nominal amount of commissions). As of December 31, 2019, $264 million remained available for repurchase under the Stock Repurchase Program. No repurchases were made by The AES Corporation of its common stock in 2019, 2018, and 2017.
Market Information
Our common stock is traded on the New York Stock Exchange under the symbol "AES."
Dividends
The Parent Company commenced a quarterly cash dividend in the fourth quarter of 2012. The Parent Company has increased this dividend annually and the quarterly per-share cash dividends for the last three years are displayed below.
The fourth quarter 2019 cash dividend is to be paid in the first quarter of 2020. There can be no assurance the AES Board will declare a dividend in the future 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 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 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 20, 2020, there were approximately 3,856 record holders of our common stock.
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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 28 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 2014 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 - SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected financial data as of the dates and for the periods indicated. This data should be read together with

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Executive Summary
In 2019, AES achieved significant milestones towards its strategic objectives, including investing in sustainable growth and innovative solutions to deliver superior results. We completed construction of 2.2 GW of new projects and signed long-term PPAs for 2.8 GW of renewable capacity. Fluence, our joint venture with Siemens, maintained its leading global market share with 1.1 GW of projects delivered or awarded in 2019. We announced the merger of Simple Energy into Uplight and formed a 10-year strategic alliance with Google to develop and implement solutions to enable broad adoption of clean energy. Finally, following our efforts to reduce recourse debt, our Parent Company's credit rating was upgraded to investment grade by Fitch. See Overview of our Strategy included in Item 1.-Business of this Form 10-K for further information.
Compared with last year, diluted earnings per share from continuing operations decreased $1.03, from $1.48 to $0.45. This decrease was largely driven by prior year net gains on dispositions of Masinloc, Electrica Santiago and CTNG transmission lines, lower generation in Argentina and Chile and higher impairments in the current year, and the impact on margin from the sale of businesses in prior periods. These decreases were partially offset by current year contributions from new businesses, lower losses on extinguishment of debt in 2019, and prior year income tax expense to finalize the impact of the TCJA.
Adjusted EPS, a non-GAAP measure, increased $0.12, from $1.24 to $1.36, reflecting higher contributions from new businesses, including U.S. renewables and the Colon combined cycle facility in Panama, a lower effective tax rate, and lower Parent Company interest in 2019, partially offset by the impact on margin from the sale of businesses in prior periods.
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Review of Consolidated Results of Operations
Components of Revenue, Cost of Sales and Operating Margin - Revenue includes revenue earned from the sale of energy from our utilities and the production and sale of energy from our generation plants, which are classified as regulated and non-regulated, respectively, on the Consolidated Statements of Operations. 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, operations and maintenance costs, depreciation and amortization expenses, bad debt expense and recoveries, and 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.
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Consolidated Revenue and Operating Margin
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Revenue
(in millions)
Consolidated Revenue - Revenue decreased $547 million, or 5%, in 2019 compared to 2018. Excluding the unfavorable FX impact of $133 million, primarily in South America, this decrease was driven by:
•
$229 million in South America primarily driven by lower generation and prices in Argentina and lower contract sales and generation in Chile;
•
$173 million in Eurasia primarily due to the sales of the Masinloc power plant in March 2018 and the Northern Ireland businesses in June 2019; and
•
$172 million in US and Utilities primarily driven by the closure of generation facilities at DPL in the first half of 2018 and Shady Point in May 2019, and lower energy prices and sales due to higher temperatures and other favorable market conditions present in 2018 as compared to 2019 at Southland, partially offset by price increases due to the 2018 rate orders at IPL and DPL and an increase in energy pass-through costs in El Salvador.
These unfavorable impacts were partially offset by an increase of $156 million in MCAC driven by the commencement of operations at the Colon combined cycle facility in Panama in September 2018.
Operating Margin
(in millions)
Consolidated Operating Margin - Operating margin decreased $224 million, or 9%, in 2019 compared to 2018. Excluding the unfavorable impact of FX of $46 million, primarily in South America, this decrease was driven by:
•
$107 million in South America primarily due to the drivers discussed above;
•
$46 million in MCAC due to the outage at Changuinola as a result of upgrading the tunnel lining and lower hydrology in Panama as compared to the prior year, partially offset by the business interruption insurance
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recoveries at the Andres facility in Dominican Republic, higher contract sales at Panama, and the commencement of operations at the Colon combined cycle facility in Panama; and
•
$31 million in Eurasia primarily due to the drivers discussed above, partially offset by lower depreciation at the Jordan plants due to their classification as held-for-sale.
These unfavorable impacts were partially offset by a $21 million increase in US and Utilities mostly driven by the 2018 rate orders at IPL and DPL, partially offset by the lost margin from the sale and closure of generation facilities at Shady Point and DPL, and increased rock ash disposal at Puerto Rico.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Revenue
(in millions)
Consolidated Revenue - Revenue increased $206 million, or 2%, in 2018 compared to 2017. Excluding the unfavorable FX impact of $52 million, primarily in South America partially offset by Eurasia, this increase was driven by:
•
$357 million in South America primarily due to higher contract sales and prices in Colombia and the commencement of new PPAs at Angamos and Cochrane in Chile, as well as higher capacity prices in Argentina resulting from market reforms enacted in 2017;
•
$215 million in MCAC primarily due to to the commencement of operations at the Colon combined cycle facility as well as improved hydrology at Panama, higher pass-through fuel prices in Mexico, higher contracted energy sales due to commencement of operations at the Los Mina combined cycle facility in June 2017, and higher spot prices in the Dominican Republic; and
•
$68 million in US and Utilities driven primarily by higher market energy sales at Southland, higher regulated rates commencing in November 2017 at DPL, higher wholesale volume due to the new CCGT coming online as well as higher retail demand at IPL, and higher prices due to tariff reset and higher energy prices in El Salvador, partially offset by the sale and closure of several generation facilities at DPL.
These favorable impacts were partially offset by decreases of $366 million in Eurasia due to the sale of the Masinloc power plant in March 2018, as well as the sale of the Kazakhstan CHPs and expiration of the Kazakhstan HPP concession agreement in 2017.
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Operating Margin
(in millions)
Consolidated Operating Margin - Operating margin increased $108 million, or 4%, in 2018 compared to 2017. Excluding the favorable impact of FX of $8 million, primarily driven by Eurasia, this increase was driven by:
•
$154 million in South America primarily due to the drivers discussed above and the absence of maintenance costs for planned outages in 2018 versus maintenance performed in Q3 2017 at Gener Chile;
•
$70 million in MCAC primarily due to drivers discussed above; and
•
$40 million in US and Utilities mostly due to the drivers discussed above and the favorable impact of a one time reduction in the ARO liability at DPL's closed plants, Stuart and Killen.
These favorable impacts were partially offset by a decrease of $204 million in Eurasia due to the drivers discussed above.
See Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations-SBU Performance Analysis of this Form 10-K for additional discussion and analysis of operating results for each SBU.
Consolidated Results of Operations - Other
General and administrative expenses
General and administrative expenses include expenses related to corporate staff functions and initiatives, executive management, finance, legal, human resources and information systems, as well as global development costs.
General and administrative expenses increased $4 million, or 2%, to $196 million for 2019 compared to $192 million for 2018, with no material drivers.
General and administrative expenses decreased $23 million, or 11%, to $192 million for 2018 compared to $215 million for 2017, primarily due to reduced people costs, professional fees and business development activity.
Interest expense
Interest expense decreased $6 million, or 1%, to $1,050 million for 2019, compared to $1,056 million for 2018 primarily due to the reduction of debt mainly at the Parent Company and DPL, reduced interest rates on refinanced debt at DPL, and favorable foreign currency translation at Tietê, partially offset by lower capitalized interest due to the commencement of operations at Colon facility in September 2018, a decrease in AFUDC for the Eagle Valley CCGT project at IPL, and the loss of hedge accounting at Alto Maipo in 2018, which resulted in favorable unrealized mark-to-market adjustments recognized within interest expense.
Interest expense decreased $114 million, or 10%, to $1,056 million for 2018, compared to $1,170 million for 2017 primarily due to the reduction of debt at the Parent Company, favorable impacts from interest rate swaps in Chile, and increased capitalized interest at Alto Maipo.
Interest income
Interest income increased $8 million, or 3%, to $318 million for 2019, compared to $310 million for 2018 primarily in South America driven by a higher average interest rate on CAMMESA receivables.
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Interest income increased $66 million, or 27%, to $310 million for 2018, compared to $244 million for 2017 primarily due to higher interest rates and increased long-term receivables as a result of the adoption of the new revenue recognition standard in 2018.
Loss on extinguishment of debt
Loss on extinguishment of debt decreased $19 million, or 10%, to $169 million for 2019, compared to $188 million for 2018. This decrease was primarily due to losses of $171 million at the Parent Company resulting from the redemption of senior notes in 2018 compared to losses of $45 million at DPL, $31 million at Mong Duong, $29 million at Gener, $28 million at Colon, and $24 million at Cochrane in 2019 resulting from the redemption or refinancing of senior notes.
Loss on extinguishment of debt increased $120 million to $188 million for 2018, compared to $68 million for 2017. This increase was primarily due to higher losses at the Parent Company of $79 million from the redemption of senior notes in 2018 and a 2017 gain on early retirement of debt at AES Argentina of $65 million, partially offset by lower losses at other subsidiaries of $24 million in 2018.
See Note 11-Debt included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Other income
Other income increased $73 million, to $145 million for 2019, compared to $72 million for 2018 primarily due to gains on insurance recoveries associated with property damage at the Andres facility and upgrading the tunnel lining at Changuinola. These increases were partially offset by a gain on remeasurement of contingent liabilities for projects in Hawaii in 2018.
Other income decreased $48 million, or 40%, to $72 million for 2018, compared to $120 million for 2017 primarily due to the 2017 favorable settlement of legal proceedings at Uruguaiana related to YPF's breach of the parties’ gas supply agreement and a decrease in AFUDC in the US and Utilities SBU. These decreases were partially offset by a gain on remeasurement of contingent liabilities for projects in Hawaii in 2018.
Other expense
Other expense increased $22 million, or 38%, to $80 million for 2019, compared to $58 million for 2018 primarily due to losses recognized at commencement of sales-type leases at Distributed Energy and the loss on disposal of assets at Changuinola associated with upgrading the tunnel lining in 2019. This was partially offset by the loss on disposal of assets resulting from damage associated with a lightning incident at the Andres facility in the Dominican Republic in 2018.
Other expense remained flat at $58 million for 2018 as compared to 2017 primarily due to a loss resulting from damage associated with a lightning incident at the Andres facility in the Dominican Republic in 2018 and higher non-service pension and other postretirement costs in 2018. This was offset by the 2017 write-off of water rights for projects that were no longer being pursued in the South America SBU and a loss on disposal of assets at DPL as a result of the decision to close the coal-fired and diesel-fired generating units at Stuart and Killen.
See Note 21-Other Income and Expense included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Gain (loss) on disposal and sale of business interests
Gain on disposal and sale of business interests decreased to $28 million for 2019, as compared to $984 million for 2018 primarily due to the 2018 gains on sale of Masinloc of $772 million, CTNG of $126 million, and Electrica Santiago of $70 million.
Gain on disposal and sale of business interests was $984 million for 2018 as compared to a loss of $52 million for 2017, primarily due to the 2018 gains on sale discussed above, and the 2017 losses on sales of Kazakhstan CHPs and HPPs of $49 million and $33 million, respectively, partially offset by the 2017 recognition of a $23 million gain related to the expiration of a contingency at Masinloc.
See Note 25-Held-For-Sale and Dispositions included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
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Goodwill impairment expense
There were no goodwill impairments for the years ended December 31, 2019, 2018, or 2017.
See Note 9-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
Asset impairment expense decreased $23 million, or 11%, to $185 million for 2019, compared to $208 million for 2018. This decrease was primarily driven by $115 million as a result of an impairment analysis performed at Kilroot and Ballylumford upon meeting the held-for-sale criteria in 2019 and $60 million at Hawaii due to a decrease in the economic useful life of the coal-fired asset, compared to prior year impairments of $157 million at Shady Point due to an unfavorable economic outlook creating uncertainty around future cash flows and $37 million at Nejapa due to the landfill owner's failure to perform improvements necessary to continue extracting gas.
Asset impairment expense decreased $329 million, or 61%, to $208 million for 2018, compared to $537 million for 2017 mainly driven by 2017 impairments of $186 million recognized in Kazakhstan due to the classification of the CHPs and HPPs as held-for-sale and $296 million in the U.S. as a result of the decision to sell the DPL peaker assets and a decline in forward pricing at Laurel Mountain, partially offset by a 2018 impairment of $157 million due to decreased future cash flows and the decision to sell Shady Point.
See Note 22-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) in millions were as follows:
_____________________________
(1)
Primarily associated with the peso-denominated energy receivable indexed to the USD through the FONINVEMEM agreement which is considered a foreign currency derivative. See Note 7-Financing Receivables included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
(2)
Includes losses of $31 million, gains of $23 million, and losses of $21 million on foreign currency derivative contracts for the years ended December 31, 2019, 2018 and 2017, respectively.
The Company recognized net foreign currency transaction losses of $67 million for the year ended December 31, 2019, primarily driven by unrealized losses on foreign currency derivatives related to government receivables in Argentina and unrealized losses associated with the devaluation of long-term receivables denominated in the Argentine peso.
The Company recognized net foreign currency transaction losses of $72 million for the year ended December 31, 2018, primarily due to the devaluation of long-term receivables denominated in Argentine pesos, partially offset by gains at the Parent Company related to foreign currency derivatives.
The Company recognized net foreign currency transaction gains of $42 million for the year ended December 31, 2017 primarily driven by transactions associated with VAT activity in Mexico, the amortization of frozen embedded derivatives in the Philippines, and appreciation of the Euro in Bulgaria. These gains were partially offset by foreign currency derivative losses in Colombia due to a change in functional currency.
Other non-operating expense
Other non-operating expense was $92 million in 2019 due to the other-than-temporary impairment of the OPGC equity method investment as a result of the estimated market value of the Company's investment and other negative developments impacting future expected cash flows at the investee.
Other non-operating expense was $147 million in 2018 primarily due to the $144 million other-than-temporary impairment of the Guacolda equity method investment as a result of increased renewable generation in Chile lowering energy prices and impacting the ability of Guacolda to re-contract its existing PPAs after they expire.
There were no significant other non-operating expenses in 2017.
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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.
Income tax expense
Income tax expense decreased $356 million to $352 million in 2019 as compared to $708 million for 2018. The Company's effective tax rate was 35% for both years ended December 31, 2019 and 2018.
The 2019 effective tax rate was impacted by the nondeductible losses on the sale of the Company's entire 100% interest in the Kilroot coal and oil-fired plant and energy storage facility and the Ballylumford gas-fired plant in the United Kingdom and associated asset impairments during the second quarter. Further impacting the 2019 effective tax rate were the effects of the Argentine peso devaluation to tax expense, as well as to pretax income for nondeductible unrealized losses on foreign currency derivatives related to government receivables in Argentina. The 2018 effective tax rate was impacted by the increase in the Staff Accounting Bulletin No.118 ("SAB 118") adjustment with respect to the estimate of the one-time transition tax and deferred tax remeasurement under the TCJA. This impact was partially offset by the impact of the sale of the Company’s entire 51% equity interest in Masinloc. See Note 25- Held-for-Sale and Dispositions and Note 23-Income Taxes included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for details and impacts of the sales.
Income tax expense decreased $282 million to $708 million in 2018 as compared to $990 million for 2017. The Company's effective tax rates were 35% and 128% for the years ended December 31, 2018 and 2017, respectively.
The net decrease in the 2018 effective tax rate was primarily due to greater 2017 impacts related to U.S. tax reform one-time transition tax and remeasurement of deferred tax assets, relative to the 2018 U.S. tax reform impact to adjust the provisional estimate recorded under SAB 118, which provides SEC guidance on the application of the accounting standards for the initial enactment impacts of the TCJA. This net decrease was also attributable to the impact of the sale of the Company's entire 51% equity interest in Masinloc, offset by taxation of our foreign subsidiaries under U.S. GILTI rules.
Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at rates different than the U.S. statutory rate. Foreign earnings may be taxed at rates higher than the U.S. corporate rate of 21% and are also subject to current U.S. taxation under the GILTI rules introduced by the TCJA. 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. The Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments regarding employment and capital investment. See Note 23-Income Taxes included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for additional information regarding these reduced rates.
Net equity in earnings (losses) of affiliates
Net equity in earnings of affiliates decreased $211 million to losses of $172 million in 2019, compared to earnings of $39 million in 2018. This was primarily driven by a $158 million decrease in earnings due to a long-lived asset impairment at Guacolda, a $19 million decrease in earnings at OPGC due to a contract termination charge, and a $20 million decrease in earnings at sPower due to the impairment of certain development projects.
Net equity in earnings of affiliates decreased $32 million, or 45%, to $39 million for 2018, compared to $71 million for 2017 primarily due to losses at Fluence, which was formed in the first quarter of 2018, decreased income at Guacolda, and larger gains on projects that achieved commercial operations in 2017 than in 2018 at sPower, which was purchased in the third quarter of 2017.
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 income (loss) from discontinued operations
Net loss from discontinued operations was $1 million for the year ended December 31, 2019. Net income from discontinued operations was $216 million for the year ended December 31, 2018 primarily due to the after-tax gain on sale of Eletropaulo of $199 million recognized in the second quarter of 2018 and the recognition of a $26 million deferred gain upon liquidation of Borsod in October 2018.
Net loss from discontinued operations was $629 million for the year ended December 31, 2017 primarily due to the after-tax loss on deconsolidation of Eletropaulo of $611 million recognized in the fourth quarter of 2017. The
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remaining loss was due to a loss contingency recognized by our equity affiliate, partially offset by the income from operations of Eletropaulo prior to the date of deconsolidation.
See Note 24-Discontinued Operations included in Item 8.-Financial Statements and Supplementary Data of this Form 10-K for further information.
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $187 million, or 52%, to $175 million in 2019, compared to $362 million in 2018. This decrease was primarily due to:
•
Prior year gains on sales of Electrica Santiago and CTNG in Chile;
•
Lower earnings in Chile primarily due to current year long-lived asset impairment at Guacolda, losses on extinguishment of debt and lower contracted energy sales and prices;
•
HLBV allocation of losses to noncontrolling interests at Distributed Energy as a result of renewable projects reaching COD in 2019; and
•
Lower earnings in Panama primarily due to lower hydrology and the outage at Changuinola as a result of upgrading the tunnel lining.
These decreases were partially offset by:
•
Prior year other-than-temporary impairment of Guacolda.
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $22 million, or 6%, to $362 million in 2018, compared to $384 million in 2017. This decrease was primarily due to:
•
Other-than-temporary impairment of Guacolda;
•
Favorable impact of a legal settlement at Uruguaiana in 2017; and
•
Lower earnings due to deconsolidation of Eletropaulo in November 2017 and the sale of Masinloc in March 2018.
These decreases were partially offset by:
•
Gains on sales of Electrica Santiago and CTNG in Chile;
•
Higher earnings in Colombia primarily due to higher contract sales and prices; and
•
Higher earnings in Vietnam due to the adoption of the new revenue recognition standard.
Net income attributable to The AES Corporation
Net income attributable to The AES Corporation decreased $900 million, or 75%, to $303 million in 2019, compared to $1,203 million in 2018. This decrease was primarily due to:
•
Prior year gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG and Electrica Santiago, net of tax;
•
Current year long-lived asset impairments at Guacolda, Hawaii, Kilroot and Ballylumford, and other-than-temporary impairment at OPGC;
•
Current year loss on sale at Kilroot and Ballylumford;
•
Current year losses on extinguishment of debt at DPL, AES Gener, Mong Duong and Colon;
•
Current year losses recognized at commencement of sales-type leases at Distributed Energy;
•
The impact of sold businesses in our Eurasia SBU;
•
Lower margins at Argentina and Chile, primarily due to lower generation; and
•
Lower margins at Changuinola, driven by the outage as a result of upgrading the tunnel lining and lower hydrology in Panama.
These decreases were partially offset by:
•
Prior year income tax expense to finalize the initial impact of U.S. tax reform enacted in December 2017;
•
Prior year loss on extinguishment of debt at the Parent Company;
•
Prior year long-lived asset impairments at Shady Point and Nejapa, and other-than-temporary impairment at Guacolda;
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•
Current year gains on insurance proceeds associated with the lightning incident at the Andres facility in 2018 and the Changuinola tunnel leak;
•
Current year gain on sale of a portion of our interest in sPower’s operating assets and gain on disposal of Stuart and Killen at DPL; and
•
Higher earnings at our US and Utilities SBU, primarily as a result of renewable projects that came online in the current year.
Net income attributable to The AES Corporation increased $2,364 million to $1,203 million in 2018, compared to a loss of $1,161 million in 2017. This increase was primarily due to:
•
Gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG, and Electrica Santiago in 2018, and losses on the sales of Kazakhstan CHPs and HPPs in 2017;
•
Loss on deconsolidation of Eletropaulo (reflected within discontinued operations) in 2017;
•
Impact of U.S. tax reform enacted in December 2017;
•
Asset impairments at DPL, Laurel Mountain and in Kazakhstan in 2017;
•
Lower interest expense at the Parent Company and Gener; and
•
Higher margins at our South America, MCAC and US and Utilities SBUs.
These increases were partially offset by:
•
Higher tax expense in 2018 due to the new GILTI rules in the U.S.;
•
Asset impairment at Shady Point and other-than-temporary impairment of Guacolda;
•
Higher losses on extinguishment of debt;
•
Foreign exchange losses in 2018 primarily due to the devaluation of the Argentine peso and foreign currency gains in 2017;
•
Favorable impact of a legal settlement at Uruguaiana in 2017; and
•
Lower margins at our Eurasia SBU as a result of the sales of Masinloc and Kazakhstan.
SBU Performance Analysis
Segments
We are organized into four market-oriented SBUs: US and Utilities (United States, Puerto Rico and El Salvador); South America (Chile, Colombia, Argentina and Brazil); MCAC (Mexico, Central America and the Caribbean); and Eurasia (Europe and Asia).
Non-GAAP Measures
Adjusted Operating Margin, Adjusted PTC and Adjusted EPS 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.
For the year ended December 31, 2019, the Company changed the definitions of Adjusted PTC and Adjusted EPS to exclude gains and losses recognized at commencement of sales-type leases. We believe these transactions are economically similar to sales of business interests and excluding these gains or losses better reflects the underlying business performance of the Company.
Adjusted Operating Margin
We define Adjusted Operating Margin as Operating Margin, adjusted for the impact of NCI, excluding (a) unrealized gains or losses related to derivative transactions; (b) benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures; and (c) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation. The allocation of HLBV earnings to noncontrolling interests is not adjusted out of Adjusted Operating Margin. See Review of Consolidated Results of Operations for definitions of Operating Margin and cost of sales.
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 NCI, where AES consolidates the results of a subsidiary that is not wholly
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owned by the Company, as well as the variability due to unrealized gains or losses related to derivative transactions and strategic decisions to dispose of or acquire business interests. Adjusted Operating Margin should not be construed as an alternative to Operating Margin, which is determined in accordance with GAAP.
_____________________________
(1)
The allocation of HLBV earnings to noncontrolling interests is not adjusted out of Adjusted Operating Margin.
(2)
In February 2018, the Company announced a reorganization as a part of its ongoing strategy to simplify its portfolio, optimize its cost structure and reduce its carbon intensity.
Adjusted PTC
We define Adjusted PTC as pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities.
Adjusted PTC reflects the impact of NCI 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 Consolidated Statement of Operations, such as general and administrative expenses in the Corporate segment, as well as business development costs, interest expense and interest income, other expense and other income, realized foreign currency transaction gains and losses, and net equity in earnings of affiliates.
The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to The AES Corporation. We believe that Adjusted PTC better 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. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests, retire debt or implement restructuring initiatives, which affect results in a given period or periods. In addition, Adjusted PTC 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
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operates. Given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the Company's results.
Adjusted PTC should not be construed as an alternative to income from continuing operations attributable to The AES Corporation, which is determined in accordance with GAAP.
_____________________________
(1)
In February 2018, the Company announced a reorganization as a part of its ongoing strategy to simplify its portfolio, optimize its cost structure and reduce its carbon intensity.
Adjusted EPS
We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, the tax impact from the repatriation of sales proceeds, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation; and (g) tax benefit or expense related to the enactment effects of 2017 U.S. tax law reform and related regulations and any subsequent period adjustments related to enactment effects.
The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. We believe that Adjusted EPS better reflects the underlying business performance of the Company and is 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 or equity securities
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remeasurement, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests, retire debt or implement restructuring initiatives, which affect results in a given period or periods. Adjusted EPS should not be construed as an alternative to diluted earnings per share from continuing operations, which is determined in accordance with GAAP.
The Company reported a loss from continuing operations of $0.77 per share for the year ended December 31, 2017. 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 anti-dilutive common stock equivalents. The table below reconciles the weighted average shares used in GAAP diluted loss per share to the weighted average shares used in calculating the non-GAAP measure of Adjusted EPS. No reconciliation is necessary for the years ended December 31, 2019 and 2018 as the Company reported income from continuing operations.
_____________________________
(1)
Amount primarily relates to unrealized derivative losses in Argentina of $89 million, or $0.13 per share, mainly associated with foreign currency derivatives on government receivables.
(2)
Amount primarily relates to unrealized FX losses in Argentina of $25 million, or $0.04 per share, mainly associated with the devaluation of long-term receivables denominated in Argentine pesos, and unrealized FX losses at the Parent Company of $12 million, or $0.02 per share, mainly associated with intercompany receivables denominated in Euro.
(3)
Amount primarily relates to unrealized FX losses of $22 million, or $0.03 per share, associated with the devaluation of long-term receivables denominated in Argentine pesos, and unrealized FX losses of $14 million, or $0.02 per share, on intercompany receivables denominated in Euro and British pounds at the Parent Company.
(4)
Amount primarily relates to losses recognized at commencement of sales-type leases at Distributed Energy of $36 million, or $0.05 per share, and loss on sale of Kilroot and Ballylumford of $31 million, or $0.05 per share; partially offset by gain on sale of a portion of our interest in sPower’s operating assets of $28 million, or $0.04 per share, gain on disposal of Stuart and Killen at DPL of $20 million, or $0.03 per share, and gain on sale of ownership interest in Simple Energy as part of the Uplight merger of $12 million, or $0.02 per share.
(5)
Amount primarily relates to gain on sale of Masinloc of $772 million, or $1.16 per share, gain on sale of CTNG of $86 million, or $0.13 per share, gain on sale of Electrica Santiago of $36 million, or $0.05 per share, gain on remeasurement of contingent consideration at AES Oahu of $32 million, or $0.05 per share, gain on sale related to the Company's contribution of AES Advancion energy storage to the Fluence joint venture of $23 million, or $0.03 per share, and realized derivative gains associated with the sale of Eletropaulo of $21 million, or $0.03 per share; partially offset by loss on disposal of the Beckjord facility and additional shutdown costs related to Stuart and Killen at DPL of $21 million, or $0.03 per share.
(6)
Amount primarily relates to loss on sale of Kazakhstan CHPs of $49 million, or $0.07 per share, realized derivative losses associated with the sale of Sul of $38 million, or $0.06 per share, loss on sale of Kazakhstan HPPs of $33 million, or $0.05 per share, and costs associated with early plant closures at DPL of $24 million, or $0.04 per share; partially offset by gain on Masinloc contingent consideration of $23 million, or $0.03 per share, and gain on sale of Miami Fort and Zimmer of $13 million, or $0.02 per share.
(7)
Amount primarily relates to asset impairments at Kilroot and Ballylumford of $115 million, or $0.17 per share, and Hawaii of $60 million, or $0.09 per share; impairments at our Guacolda and sPower equity affiliates, impacting equity earnings by $105 million, or $0.16 per share, and $21 million, or $0.03 per share, respectively; and other-than-temporary impairment of OPGC of $92 million, or $0.14 per share.
(8)
Amount primarily relates to asset impairments at Shady Point of $157 million, or $0.24 per share, and Nejapa of $37 million, or $0.06 per share, and other-than-temporary impairment of Guacolda of $96 million, or $0.14 per share.
(9)
Amount primarily relates to asset impairments at Kazakhstan CHPs of $94 million, or $0.14 per share, Kazakhstan HPPs of $92 million, or $0.14 per share, Laurel Mountain of $121 million, or $0.18 per share, DPL of $175 million, or $0.27 per share, and Kilroot of $37 million, or $0.05 per share.
(10)
Amount primarily relates to losses on early retirement of debt at DPL of $45 million, or $0.07 per share, AES Gener of $35 million, or $0.05 per share, Mong Duong of $17 million, or $0.03 per share, and Colon of $14 million, or $0.02 per share.
(11)
Amount primarily relates to loss on early retirement of debt at the Parent Company of $171 million, or $0.26 per share.
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(12)
Amount primarily relates to losses on early retirement of debt at the Parent Company of $92 million, or $0.14 per share, AES Gener of $20 million, or $0.02 per share, and IPALCO of $9 million, or $0.01 per share; partially offset by a gain on early retirement of debt at AES Argentina of $65 million, or $0.10 per share.
(13)
Amount relates to a SAB 118 charge to finalize the provisional estimate of one-time transition tax on foreign earnings of $194 million, or $0.29 per share, partially offset by a SAB 118 income tax benefit to finalize the provisional estimate of remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $77 million, or $0.11 per share.
(14)
Amount relates to a one-time transition tax on foreign earnings of $675 million, or $1.02 per share, and the remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $39 million, or $0.06 per share.
(15)
Amount primarily relates to the income tax benefits associated with the impairments at OPGC of $23 million, or $0.03 per share, Guacolda of $13 million, or $0.02 per share, Hawaii of $13 million, or $0.02 per share, and Kilroot and Ballylumford of $11 million, or $0.02 per share, and income tax benefits associated with losses on early retirement of debt of $24 million, or $0.04 per share; partially offset by an adjustment to income tax expense related to 2018 gains on sales of business interests, primarily Masinloc, of $25 million, or $0.04 per share.
(16)
Amount primarily relates to the income tax expense under the GILTI provision associated with the gains on sales of business interests, primarily Masinloc, of $97 million, or $0.15 per share, and income tax expense associated with gains on sale of CTNG of $36 million, or $0.05 per share, and Electrica Santiago of $13 million, or $0.02 per share; partially offset by income tax benefits associated with the loss on early retirement of debt at the Parent Company of $36 million, or $0.05 per share, and income tax benefits associated with the impairment at Shady Point of $33 million, or $0.05 per share.
(17)
Amount primarily relates to the income tax benefits associated with asset impairments of $148 million, or $0.22 per share.
US and Utilities SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
_____________________________
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis-Non-GAAP Measures for definition and Item 1.-Business for the respective ownership interest for key businesses.
Fiscal year 2019 versus 2018
Operating Margin increased $21 million, or 3%, which was driven primarily by the following (in millions):
Adjusted Operating Margin decreased $19 million primarily due to the drivers above, adjusted for NCI and excluding unrealized gains and losses on derivatives and costs and benefits associated with early plant closures.
Adjusted PTC increased $58 million, primarily driven by an increase in earnings attributable to AES as a result of contributions from new renewable projects and lower interest expense at DPL, partially offset by the decrease in Adjusted Operating Margin described above and a decrease in AFUDC for the Eagle Valley CCGT project at IPL.
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Fiscal year 2018 versus 2017
Operating Margin increased $40 million, or 6%, which was driven primarily by the following (in millions):
Adjusted Operating Margin increased $55 million primarily due to the drivers above, adjusted for a $24 million unrealized loss on coal derivatives in Hawaii, partially offset by restructuring charges in the prior year.
Adjusted PTC increased $87 million, primarily driven by the increase in Adjusted Operating Margin described above, as well as an increase in the Company's share of earnings at Distributed Energy due to new solar project growth, lower interest expense, and the HLBV allocation of noncontrolling interest earnings at Buffalo Gap, partially offset by lower allowance for equity funds used during construction at IPALCO.
South America SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
_____________________________
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis-Non-GAAP Measures for definition and Item 1.-Business for the respective ownership interest for key businesses.
Fiscal year 2019 versus 2018
Operating Margin decreased $144 million, or 14%, which was driven primarily by the following (in millions):
Adjusted Operating Margin decreased $113 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC decreased $15 million, mainly driven by the decrease in Adjusted Operating Margin described above, partially offset by realized FX gains in Argentina and Chile in 2019 as compared to losses in 2018, and higher equity earnings in 2019 related to better operating results at Guacolda.
93 | 2019 Annual Report
Fiscal year 2018 versus 2017
Operating Margin increased $155 million, or 18%, which was driven primarily by the following (in millions):
Adjusted Operating Margin increased $112 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $73 million, mainly due to the increase in Adjusted Operating Margin described above and lower interest in Chile, partially offset by a $28 million decrease associated with a gain recognized in the prior year from the settlement of a legal dispute with YPF at Uruguaiana, higher interest expense in Brazil, lower equity earnings in Chile and higher realized foreign currency losses in Argentina.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
_____________________________
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis-Non-GAAP Measures for definition and Item 1.-Business for the respective ownership interest for key businesses.
Fiscal year 2019 versus 2018
Operating Margin decreased $47 million, or 9%, which was driven primarily by the following (in millions):
Adjusted Operating Margin decreased $39 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $67 million, mainly driven by the insurance recoveries associated with property damage at Andres and Changuinola, partially offset by a decrease in Adjusted Operating Margin described above.
94 | 2019 Annual Report
Fiscal year 2018 versus 2017
Operating Margin increased $69 million, or 15%, which was driven primarily by the following (in millions):
Adjusted Operating Margin increased $33 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $23 million, mainly driven by the increase in Adjusted Operating Margin as described above, partially offset by lower capitalized interest due to project completions in Panama and Dominican Republic and lower foreign currency gains in Mexico.
Eurasia SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
_____________________________
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis-Non-GAAP Measures for definition and Item 1.-Business for the respective ownership interest for key businesses.
Fiscal year 2019 versus 2018
Operating Margin decreased $39 million, or 17%, which was driven primarily by the following (in millions):
Adjusted Operating Margin decreased $46 million due to the drivers above, adjusted for NCI.
Adjusted PTC decreased $63 million, driven primarily by the decrease in Adjusted Operating Margin discussed above, as well as a decrease in earnings at OPGC and the sale of Elsta, our equity affiliate in the Netherlands.
Fiscal year 2018 versus 2017
Including favorable FX impacts of $8 million, Operating Margin decreased $195 million, or 46%, which was driven primarily by the following (in millions):
Adjusted Operating Margin decreased $112 million, primarily due to the drivers above, adjusted for NCI.
Adjusted PTC decreased $68 million, primarily driven by the decrease in Adjusted Operating Margin discussed above, partially offset by the positive impact in Vietnam due to increased interest income from the higher financing component of contract consideration as a result of adoption of the new revenue recognition standard in 2018.
95 | 2019 Annual Report
Key Trends and Uncertainties
During 2020 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.
Macroeconomic and Political
The macroeconomic and political environments in some countries where our subsidiaries conduct business have changed during 2019. This could result in significant impacts to tax laws and environmental and energy policies. Additionally, we operate in multiple countries and as such are subject to volatility in exchange rates at the subsidiary level. See

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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. In addition, our businesses are exposed to lower electricity prices due to increased competition, including from renewable sources such as wind and solar, as a result of lower costs of entry and lower variable costs. 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 USD, 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.
The disclosures presented 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 Exchange Act shall apply to the disclosures contained in this Item 7A. For further information regarding market risk, see Item 1A.-Risk
114 | 2019 Annual Report
Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations; Wholesale power prices are declining in many markets and this could have a material adverse effect on our operations and opportunities for future growth; We may not be adequately hedged against our exposure to changes in commodity prices or interest rates; and Certain of our businesses are sensitive to variations in weather and hydrology of this 2019 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 unhedged exposure on some of our capacity or have imperfect fuel pass-throughs. 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.
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. 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.
AES businesses will see changes in variable margin performance as global commodity prices shift. For 2020, we project pre-tax earnings exposure on a 10% move in commodity prices would be $15 million for power, $(5) million for natural gas, $(5) million for coal, and less than $(5) million for oil. 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 power, higher oil, higher 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 local market characteristics and risk management strategies. Spot power prices, contract indexation provisions, and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil, and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Exposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local 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 and Utilities SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. At Southland, our primary contracts are in capacity and the business has seen incremental location value in energy revenues. This will continue through 2020 when our Southland repowering contract begins.
In the South America 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. The majority of our PPAs include mechanisms of indexation that adjust the price of energy based on fluctuations in the price of coal, with the specific indices and timing varying by contract, in order to mitigate changes in the price of fuel. For the portion of our contracts not indexed to the price of coal, we have implemented a hedging strategy based on international coal financial instruments for up to 3 years. In Colombia, we operate under a shorter-term sales strategy and have commodity exposure to unhedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel. Additionally, in Brazil, 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 drier 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.
115 | 2019 Annual Report
In the MCAC SBU, our businesses have commodity exposure on unhedged volumes. Panama is highly contracted under a portfolio of PPA 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 and gas 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 under a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.
In the Eurasia SBU, our assets operating in Vietnam and Bulgaria have minimal exposure to commodity price risk as it has no or minor merchant exposure and fuel is subject to a pass-through mechanism. In India, around one-fifth of our new facility is under a short-term commercialization agreement until 2023, when 100% of capacity will be under a long-term PPA.
Foreign Exchange Rate Risk
In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the USD. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in USD or currencies other than their own functional currencies. Certain of our foreign subsidiaries calculate and pay taxes in currencies other than their own functional currency. We have varying degrees of exposure to changes in the exchange rate between the USD and the following currencies: Argentine peso, Brazilian real, Chilean peso, Colombian peso, Dominican peso, Euro, Indian rupee, and Mexican 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.
AES enters into foreign currency hedges to protect economic value of the business and minimize the impact of foreign exchange rate fluctuations to AES' portfolio. While protecting cash flows, the hedging strategy is also designed to reduce forward-looking earnings foreign exchange volatility. Due to variation of timing and amount between cash distributions and earnings exposure, the hedge impact may not fully cover the earnings exposure on a realized basis, which could result in greater volatility in earnings. The largest foreign exchange risks over a 12-month forward-looking period stem from the following currencies: Argentine peso, Brazilian real, Colombian peso, Euro, and Indian Rupee. As of December 31, 2019, assuming a 10% USD appreciation, cash distributions attributable to foreign subsidiaries exposed to movement in the exchange rate are projected to be impacted by less than $(5) million each for Brazilian real, Colombia peso, and Euro, and less than $5 million for Indian Rupee. These numbers have been produced by applying a one-time 10% USD appreciation to forecasted exposed cash distributions for 2020 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 cash distributions 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 variable and fixed-rate debt, as well as interest rate swap, cap, floor, and 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- 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 interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of December 31, 2019, the portfolio's pre-tax earnings exposure for 2020 to a one-time 100-basis-point increase in interest rates for our Argentine peso, Brazilian real, Chilean peso, Colombian peso, Euro, and USD denominated debt would be approximately $20 million on interest expense for the debt denominated in these currencies. These amounts do not take into account the historical correlation between these interest rates.
116 | 2019 Annual Report

ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of The AES Corporation:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of The AES Corporation (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and the financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, 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 27, 2020, expressed an unqualified opinion thereon.
Adoption of New Accounting Standards
As discussed in Note 1 to the consolidated financial statements, the Company changed its method for recognizing revenue as a result of the adoption of Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), and the amendments in ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10 and 2017-13 effective January 1, 2018.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
117 | 2019 Annual Report
Impairment Evaluation of Goodwill
Description of the Matter
The Company’s goodwill balance was $1,059 million at December 31, 2019, of which $868 million relates to the Gener reporting unit. As disclosed in Note 1 to the consolidated financial statements, the Company’s goodwill is tested for impairment at least annually at the reporting unit level. The goodwill impairment test at the Gener reporting unit involves the use of significant unobservable inputs to determine the fair value of the reporting unit. This estimate of fair value is compared to the carrying value of the reporting unit to determine whether goodwill is impaired.
Auditing the Company's measurement of the fair value of the Gener reporting unit involved a high degree of subjectivity given the lack of observable inputs to estimate the reporting unit’s fair value. Key inputs that had a significant impact on the valuation included the prospective financial information (including the estimated growth in renewable projects, forward electricity prices and developments in the Chilean capacity market) and the discount rate, which are forward-looking and based upon expectations about future economic and market conditions.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s goodwill impairment review process at the Gener reporting unit. For example, we tested controls over management’s review of the valuation model, the significant assumptions used to develop the estimates, and the completeness and accuracy of the data used in the valuations.
To test the estimated fair value of the Company’s Gener reporting unit, we performed audit procedures that included, among others, assessing the methodologies used to develop the estimate of fair value, testing the significant assumptions discussed above, and testing the completeness and accuracy of the underlying data used by the Company in its analyses. We compared the significant assumptions used by management to current industry and economic trends as well as historical results. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the reporting unit that would result from changes in the assumptions. We also involved a valuation specialist to assist in our evaluation of the overall methodologies and the discount rate used in the fair value estimate.
Evaluation of Impairment Indicators and Re-evaluation of Useful Lives
Description of the Matter
At December 31, 2019, the Company's property, plant and equipment had an aggregate net carrying value of approximately $22,574 million. As disclosed in Note 1 to the consolidated financial statements, when circumstances indicate the carrying amount of long-lived assets in a held-for-use asset group may not be recoverable, the Company evaluates the assets for potential impairment, and re-evaluates the remaining useful life. These circumstances may include, but are not limited to, changes in the regulatory environment, demand, power prices or fuel costs, technological advancements, physical deterioration, or an expectation it is more likely than not that the asset will be disposed of before the end of its useful life.
Auditing the Company's evaluation of impairment and estimated useful lives of coal generation assets involved significant auditor judgment considering the many geographic, regulatory and economic environments in which the Company operates. These audit procedures required an evaluation of a wide variety of circumstances for potential changes in useful lives or impairment indicators.
118 | 2019 Annual Report
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s identification of impairment indicators and estimation of useful lives (including any changes if necessary). This included management’s monitoring controls over businesses that have had been affected or are expected to be affected by the circumstances above.
Other audit procedures included, among others, making inquiries of management (including personnel in operations) to understand changes in the businesses, reading industry journals and publications to independently identify changes in the regulatory environments or the geographic areas and evaluating whether management has considered identified changes, if any. We considered businesses for which current power prices are significantly less than contractual prices within Power Purchase Agreements (PPAs) that are also near expiration. We also considered the Company’s ability to re-contract certain of its coal generation assets upon the expiration of a PPA, given the most recent legislative or regulatory changes. We evaluated the Company’s analysis of the useful lives of its coal generation assets, considering the existing PPAs and the Company’s ability to use the assets subsequent to the expiration of a PPA, based on any regulatory or market changes. For projects that were still under construction, we compared the Company's actual progress to their budgets, inspected engineering reports when considered appropriate, and considered project overruns. We reviewed disaggregated financial results for deterioration in earnings performance compared to prior periods, negative cash flows from operations, and working capital deficiencies and assessed whether these would represent impairment indicators, when applicable. We also considered and assessed conditions and trends in the industry and the underlying economies and evaluated sale or disposition activities.
We have served as the Company's auditor since 2008.
/s/ Ernst & Young LLP
Tysons, Virginia
February 27, 2020
Consolidated Balance Sheets
December 31, 2019 and 2018
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Operations
Years ended December 31, 2019, 2018, and 2017
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income (Loss)
Years ended December 31, 2019, 2018, and 2017
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Changes in Equity
Years ended December 31, 2019, 2018, and 2017
(1) See Note 1-General and Summary of Significant Accounting Policies for further information.
(2) Adjustment to the carrying amount of noncontrolling interest and redeemable stock of subsidiaries to fair value.
(3) See Note 25-Held-for-Sale and Dispositions for further information.
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Cash Flows
Years ended December 31, 2019, 2018, and 2017
See Accompanying Notes to Consolidated Financial Statements.
124 | Notes to Consolidated Financial Statements | December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
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, the liabilities of individual operating entities are non-recourse to the Parent Company 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 variable interest model. The preparation of these consolidated financial statements is in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP").
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements of the Company include the accounts of The AES Corporation and its controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. Intercompany transactions and balances are eliminated in consolidation. Investments in entities where the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.
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 on 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 qualified 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.
Equity securities with redemption features that are not solely within the control of the issuer are classified outside of permanent equity. Generally, initial measurement will be at fair value. Subsequent measurement and classification vary depending on whether the instrument is probable of becoming redeemable. When the equity instrument is not probable of becoming redeemable, subsequent allocation of income and dividends is classified in permanent equity. For those securities where it is probable that the instrument will become redeemable or that are currently redeemable, AES recognizes changes in the fair value at each accounting period against retained earnings or additional paid-in-capital in the absence of retained earnings, subject to the floor of the initial fair value. Further, the allocation of income and dividends, as well as the adjustment to fair value, is classified outside permanent equity. Instruments that are mandatorily redeemable are classified as a liability.
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’s proportionate share of the net income or loss of these companies is included in Net equity in earnings (losses) of affiliates on the Consolidated Statements of Operations.
The Company utilizes the cumulative earning approach to determine whether distributions received from equity method investees are returns on investment or returns of investment. 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 accounting to the extent that net income is greater than the share of net losses not previously recorded.
Upon acquiring the investment, we determine the fair value of the identifiable assets and assumed liabilities and the basis difference between each fair value and the carrying amount of the corresponding asset or liability in the financial statements of the investee. The AES share of the amortization of the basis difference is recognized in Net equity in earnings of affiliates in the Consolidated Statements of Operations over the life of the asset or liability.
The Company periodically assesses if impairment indicators exist at our equity method investments. When an impairment is observed, any excess of the carrying amount over its estimated fair value is recognized as impairment expense when the loss in value is deemed other-than-temporary and included in Other non-operating expense in the Consolidated Statements of Operations.
125 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
BUSINESS INTERESTS - Acquisitions and disposals of business interests are generally transactions pertaining to operational legal entities, which may be accounted for as a consolidated business, an asset, or an equity method investment. Losses on expected sales of business interests are limited to the impairment of long-lived assets as of the date of execution of the sales agreement, which are recognized in Asset impairment expense in the Consolidated Statements of Operations. Any additional gains/(losses) on sales, which are primarily due to reclassification of cumulative translation adjustments, are recognized in Gain (loss) on disposal and sale of business interests in the Consolidated Statements of Operations upon completion of the sale.
ALLOCATION OF EARNINGS - Certain of the Company's businesses are subject to profit-sharing arrangements where the allocation of cash distributions and the sharing of tax benefits are not based on fixed ownership percentages. These arrangements exist for certain U.S. renewable 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 hypothetical liquidation at book value (“HLBV”) method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions.
The HLBV method is used both to allocate the equity earnings attributable to AES when the Company accounts for the renewable business as an equity method investment and to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.
USE OF ESTIMATES - U.S. GAAP requires the Company to make estimates and assumptions that affect the asset and liability balances reported as of the date of the consolidated financial statements, as well as the revenues and expenses recognized 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; asset retirement obligations; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of regulatory assets; regulatory liabilities; the fair value of financial instruments; the fair value of assets and liabilities acquired as business combinations or as asset acquisitions by variable interest entities; contingent consideration arising from business combinations or asset acquisitions by variable interest entities; the measurement of equity method investments or noncontrolling interest using the HLBV method for certain renewable 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; the incremental borrowing rates used in the determination of lease liabilities; the determination of lease and non-lease components in certain generation contracts; environmental liabilities; and potential litigation claims and settlements.
HELD-FOR-SALE DISPOSAL GROUPS- A disposal group classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the disposal group exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long-lived assets until the completion of the sale, at which point, any additional loss is recognized. 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 lesser of the previously recognized expense or the subsequent excess.
Assets and liabilities related to a disposal group classified as held-for-sale are segregated in the current balance sheet in the period in which the disposal group is classified as held-for-sale. Assets and liabilities of held-for-sale disposal groups are classified as current when they are expected to be disposed of within twelve months. Transactions between the held-for-sale disposal group and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 25-Held-for-Sale and Dispositions for further information.
126 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
DISCONTINUED OPERATIONS - Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on the Company's operations and financial results. The Company reports financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the Consolidated Statements of Operations and Consolidated Balance Sheets are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Consolidated Statements of Cash Flows.
Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value less cost to sell, including gains or losses associated with noncontrolling interests upon completion of the disposal transaction. Adjustments related to components previously reported as discontinued operations under prior accounting guidance are presented as discontinued operations in the current period even if the disposed-of component to which the adjustments are related would not meet the criteria for presentation as a discontinued operation under current guidance. See Note 24-Discontinued Operations for further information.
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 noncurrent assets; derivative assets, included in Other current assets and Other noncurrent assets; and, derivative liabilities, included in Accrued and other liabilities (current) and Other noncurrent liabilities. The Company applies the fair value measurement guidance to nonfinancial assets and liabilities upon the acquisition of a business or an asset acquisition by a variable interest entity, or in conjunction with the measurement of an asset retirement obligation or a potential impairment loss on an asset group, equity method investments, or goodwill.
When determining the fair value measurements for assets and liabilities required to be reflected at their fair values, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the assets or liabilities, such as inherent risk, transfer restrictions and risk of nonperformance. The Company is prohibited from including transaction costs and any adjustments for blockage factors in determining fair value.
In determining fair value measurements, the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs. Assets and liabilities are categorized within a fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:
•
Level 1: Quoted prices in active markets for identical assets or liabilities;
•
Level 2: Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; or
•
Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair values of the assets or liabilities.
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, cash balances not restricted as to withdrawal or usage, deposits in banks, certificates of deposit and short-term marketable securities with original maturities of three months or less to be cash and cash equivalents.
RESTRICTED CASH AND DEBT SERVICE RESERVES - Cash balances restricted as to withdrawal or usage, primarily via contract, are considered restricted cash.
127 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows (in millions):
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 consist of marketable equity securities and debt securities with original maturities in excess of three months with remaining maturities of less than one year. Marketable debt securities where 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. Remaining marketable debt securities are classified as available-for-sale or trading and are carried at fair value.
Unrealized gains or losses on available-for-sale debt securities are reflected in AOCL, a separate component of equity, and the Consolidated Statements of Operations, respectively. Unrealized gains or losses on equity investments are reported in Other income. 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 historical collection experience, the age of accounts receivable and other currently available evidence supporting collectability, and records an allowance for doubtful accounts for the estimated uncollectible amount as appropriate. Certain of our businesses charge interest on accounts receivable. Interest income is recognized on an accrual basis. When 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 fuel and other raw materials used to generate power, and operational spare parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost or net realizable value. Cost is the sum of the purchase price and expenditures incurred to bring the inventory to its existing location. Inventory is primarily valued using the average cost method. Generally, if it is expected fuel inventory will not be recovered through revenue earned from power generation, an impairment is recognized to reflect the fuel at market value. The carrying amount of spare parts and supplies is typically reduced only in instances where the items are considered obsolete.
LONG-LIVED ASSETS - Long-lived assets include property, plant and equipment, assets under finance 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 construction project is deemed probable, or expensed at the time construction completion is determined to no longer be probable. The continued capitalization of such costs is subject to 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. Maintenance and repairs are charged to expense as incurred.
Depreciation, after consideration of salvage value and asset retirement obligations, is computed using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Capital spare parts, including rotable spare parts, are included in electric generation and
128 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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.
Certain of the Company's subsidiaries operate under concession contracts. Certain estimates are utilized to determine depreciation expense for the 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. These concession contracts are not within the scope of ASC 853-Service Concession Arrangements.
Intangible Assets Subject to Amortization - Finite-lived intangible assets are amortized over their useful lives which range from 1 - 50 years and are included in the Consolidated Balance Sheet line item Other intangible assets. The Company accounts for purchased emission allowances as intangible assets and records an expense when they are utilized or sold. Granted emission allowances are valued at zero.
Impairment of Long-lived Assets - When circumstances indicate the carrying amount of long-lived assets in a held-for-use asset group may not be recoverable, the Company evaluates the assets for potential impairment using internal projections of undiscounted cash flows resulting from the use and eventual disposal of the assets. Events or changes in circumstances that may necessitate a recoverability evaluation 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 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, an impairment expense is recognized for the amount by which the carrying amount of the asset group exceeds its fair value (subject to the carrying amount not being reduced below fair value for any individual long-lived asset that is determinable without undue cost and effort). An impairment expense for certain assets may be reduced by the establishment of a regulatory asset if recovery through approved rates is probable.
SERVICE CONCESSION ASSETS - Service concession assets are stated at cost, net of accumulated amortization, in accordance with ASC 853. Service concession assets represent the cost of all infrastructure to be transferred to the public-sector entity grantors at the end of the concession. These costs primarily represent construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction of the service concession infrastructure. Government subsidies, liquidated damages recovered for construction delays and income tax credits are recorded as a reduction to Service Concession Assets. Service concession assets are amortized and recognized in earnings as a cost of goods sold as infrastructure construction revenue is recognized. Services provided under concession arrangements are recognized on a straight line basis.
DEBT ISSUANCE COSTS - Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows used in financing activities.
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 1st.
Goodwill - Goodwill represents the excess of the purchase price of the business acquisition over the fair value of identifiable net assets acquired. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the synergies of the acquisition. Generally, each AES business with a goodwill balance constitutes a reporting unit as they are not similar to other businesses in a segment nor are they reported to segment management together with other businesses.
Goodwill is evaluated for impairment either under the qualitative assessment option or the quantitative test option to determine the fair value of the reporting unit. If goodwill is determined to be impaired, an impairment loss measured at the amount by which the reporting unit’s carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.
129 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Indefinite-Lived Intangible Assets - The Company's indefinite-lived intangible assets primarily include land-use rights and water rights. Indefinite-lived intangible assets are evaluated for impairment either under the qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense.
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, and benefits.
REGULATORY ASSETS AND LIABILITIES - The Company recognizes assets and liabilities that result from regulated ratemaking processes. Regulatory assets generally represent incurred costs which have been deferred due to the probable future recovery via customer rates. Generally, returns earned on regulatory assets are reflected in the Consolidated Statement of Operations within Interest Income. Regulatory liabilities generally represent obligations to refund customers. Management continually assesses whether regulatory assets are probable of future recovery and regulatory liabilities are probable of future payment 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 actuarial gains or losses 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 basis. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company's tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
The Company has elected to treat GILTI as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.
ASSET RETIREMENT OBLIGATIONS - The Company records the fair value of a 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.
FOREIGN CURRENCY TRANSLATION - A business's 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. Adjustments arising from the translation of the balance sheet of such subsidiaries are included in AOCL. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. dollars at the average exchange rates for the period. 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
130 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
other than the functional currency are included in determining net income. Accumulated foreign currency translation adjustments are reclassified from AOCL 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 is earned from the sale of electricity from our utilities and the production and sale of electricity and capacity from our generation facilities. Revenue is recognized upon the transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Utilities - Our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. The majority of our utility contracts have a single performance obligation, as the promises to transfer energy, capacity, and other distribution and/or transmission services are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. Utility revenue is classified as regulated on the Consolidated Statements of Operations.
In exchange for the right to sell or distribute electricity in a service territory, our utility businesses are subject to government regulation. This regulation sets the framework for the prices (“tariffs”) that our utilities are allowed to charge customers for electricity. Since tariffs are determined by the regulator, the price that our utilities have the right to bill corresponds directly with the value to the customer of the utility's performance completed in each period. The Company also has some month-to-month contracts. Revenue under these contracts is recognized using an output method measured by the MWh delivered each month, which best depicts the transfer of goods or services to the customer, at the approved tariff.
The Company has businesses where it sells and purchases power to and from ISOs and RTOs. Our utility businesses generally purchase power to satisfy the demand of customers that is not contracted through separate PPAs. In these instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. In limited situations, a utility customer may choose to receive generation services from a third-party provider, in which case the Company may serve as a billing agent for the provider and recognize revenue on a net basis.
Generation - Most of our generation fleet sells electricity under contracts to customers such as utilities, industrial users, and other intermediaries. Our generation contracts, based on specific facts and circumstances, can have one or more performance obligations as the promise to transfer energy, capacity, and other services may or may not be distinct depending on the nature of the market and terms of the contract. As the performance obligations are generally satisfied over time and use the same method to measure progress, the performance obligations meet the criteria to be considered a series. In measuring progress toward satisfaction of a performance obligation, the Company applies the "right to invoice" practical expedient when available, and recognizes revenue in the amount to which the Company has a right to consideration from a customer that corresponds directly with the value of the performance completed to date. Revenue from generation businesses is classified as non-regulated on the Consolidated Statements of Operations.
For contracts determined to have multiple performance obligations, we allocate revenue to each performance obligation based on its relative standalone selling price using a market or expected cost plus margin approach. Additionally, the Company allocates variable consideration to one or more, but not all, distinct goods or services that form part of a single performance obligation when (1) the variable consideration relates specifically to the efforts to transfer the distinct good or service and (2) the variable consideration depicts the amount to which the Company expects to be entitled in exchange for transferring the promised good or service to the customer.
Revenue from generation contracts is recognized using an output method, as energy and capacity delivered best depicts the transfer of goods or services to the customer. Performance obligations including energy or ancillary services (such as operations and maintenance and dispatch services) are generally measured by the MWh delivered. Capacity, which is a stand-ready obligation to deliver energy when required by the customer, is measured using MWs. In certain contracts, if plant availability exceeds a contractual target, the Company may receive a performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent a form of variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal.
131 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
In assessing whether variable quantities are considered variable consideration or an option to acquire additional goods and services, the Company evaluates the nature of the promise and the legally enforceable rights in the contract. In some contracts, such as requirement contracts, the legally enforceable rights merely give the customer a right to purchase additional goods and services which are distinct. In these contracts, the customer's action results in a new obligation, and the variable quantities are considered an option.
When energy or capacity is sold or purchased in the spot market or to ISOs, the Company assesses the facts and circumstances to determine gross versus net presentation of spot revenues and purchases. Generally, the nature of the performance obligation is to sell surplus energy or capacity above contractual commitments, or to purchase energy or capacity to satisfy deficits. Generally, on an hourly basis, a generator is either a net seller or a net buyer in terms of the amount of energy or capacity transacted with the ISO. In these situations, the Company recognizes revenue for the hours where the generator is a net seller and cost of sales for the hours where the generator is a net buyer.
Certain generation contracts contain operating leases where capacity payments are generally considered lease elements. In such cases, the allocation between the lease and non-lease elements is made at the inception of the lease following the guidance in ASC 842.
The transaction price allocated to a construction performance obligation is recognized as revenue over time as construction activity occurs, with revenue being fully recognized upon completion of construction. These contracts may include a difference in timing between revenue recognition and the collection of cash receipts, which may be collected over the term of the entire arrangement. The timing difference could result in a significant financing component for the construction performance obligation if determined to be a material component of the transaction price. The Company accounts for a significant financing component under the effective interest rate method, recognizing a long-term receivable for the expected future payments related to the construction performance obligation in the Loan Receivable line item on the Consolidated Balance Sheets. As payments are collected from the customer over the term of the contract, consideration related to the construction performance obligation is bifurcated between the principal repayment of the long-term receivable and the related interest income, recognized in the Consolidated Statements of Operations.
Contract Balances - The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. Accounts receivable represent unconditional rights to consideration and consist of both billed amounts and unbilled amounts typically resulting from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. We bill both generation and utilities customers on a contractually agreed-upon schedule, typically at periodic intervals (e.g., monthly). 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.
Our contract liabilities consist of deferred revenue which is classified as current or noncurrent based on the timing of when we expect to recognize revenue. The current portion of our contract liabilities is reported in Accrued and other liabilities and the noncurrent portion is reported in Other noncurrent liabilities on the Consolidated Balance Sheets.
Remaining Performance Obligations - The transaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the reporting period. The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the amount disclosed in Note 20-Revenue excludes contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled. As such, consideration for energy is excluded from the amount disclosed as the variable consideration relates to the amount of energy delivered and reflects the value the Company expects to receive for the energy transferred. Estimates of revenue expected to be recognized in future periods also exclude unexercised customer options to purchase additional goods or services that do not represent material rights to the customer.
LEASES - The Company has operating and finance leases for energy production facilities, land, office space, transmission lines, vehicles and other operating equipment in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.
132 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the subsidiaries’ incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its unsecured borrowings, which are then adjusted for the appropriate lease term and currency. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes the option to extend or terminate the lease if it is reasonably certain that the option will be exercised.
The Company has operating leases for certain generation contracts that contain provisions to provide capacity to a customer, which is a stand-ready obligation to deliver energy when required by the customer in which the Company is the lessor. Capacity payments are generally considered lease elements as they cover the majority of available output from a facility. The allocation of contract payments between the lease and non-lease elements is made at the inception of the lease. Lease payments from such contracts are recognized as lease revenue on a straight-line basis over the lease term, whereas variable lease payments are recognized when earned.
The Company has sales-type leases for battery energy storage systems ("BESS") in which the Company is the lessor. These arrangements allow customers the ability to determine when to charge and discharge the BESS, representing the transfer of control and constitutes the arrangement as a sales-type lease. Upon commencement of the lease, the book value of the leased asset is removed from the balance sheet and a net investment in sales-type lease is recognized based on the present value of fixed payments under the contract and the residual value of the underlying asset.
SHARE-BASED COMPENSATION - The Company grants share-based compensation in the form of stock options, restricted stock units, performance stock units, and performance cash 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. The Company uses a Black-Scholes option pricing model to estimate the fair value of stock options granted to its employees.
GENERAL AND ADMINISTRATIVE EXPENSES - General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. Additionally, all costs associated with 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 Note 5-Fair Value and Fair value in this section for additional discussion regarding the determination of fair value.
PPAs and fuel supply agreements are evaluated to assess if they contain either a derivative or an embedded derivative requiring separate valuation and accounting. 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 commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could be net settled and meet the definition of a derivative.
The Company typically designates its derivative instruments as cash flow hedges if they meet the criteria specified in ASC 815, Derivatives and Hedging. The Company enters into interest rate swap agreements in order to hedge the variability of expected future cash interest payments. Foreign currency contracts are used to reduce risks arising from the change in fair value of certain foreign currency denominated assets and liabilities. The objective of these practices is to minimize the impact of foreign currency fluctuations on operating results. The Company also enters into commodity contracts to economically hedge price variability inherent in electricity sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot electricity prices and stabilize estimated revenue streams. The Company does not use derivative instruments for speculative purposes.
For our hedges, changes in fair value are deferred in AOCL and are recognized into earnings as the hedged transactions affect earnings. If a derivative is no longer highly effective, hedge accounting will be discontinued
133 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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 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 are recognized in earnings, they are generally classified as interest expense for interest rate and cross-currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity and other derivatives. Cash flows arising from derivatives are included in the Consolidated Statements of Cash Flows as an operating activity given 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.
NEW ACCOUNTING PRONOUNCEMENTS - The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s consolidated financial statements.
ASC 842 - Leases
On January 1, 2019, the Company adopted ASC 842 Leases and its subsequent corresponding updates (“ASC 842”). Under this standard, lessees are required to recognize assets and liabilities for most leases on the balance sheet, and recognize expenses in a manner similar to the prior accounting method. For lessors, the guidance
134 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance eliminates previous real estate-specific provisions.
Under ASC 842, fewer of our contracts contain a lease. However, due to the elimination of the real estate-specific guidance and changes to certain lessor classification criteria, more leases qualify as sales-type leases and direct financing leases. Under these two models, a lessor derecognizes the asset and recognizes a lease receivable. According to ASC 842, the net investment in the lease includes the fair value of residual interest in the asset after the contract period as well as the present value of the fixed lease payments, but does not include any variable payments under the lease. Therefore, the net investment in the lease could be significantly different than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized net investment in the lease and the carrying amount of the underlying asset is recognized as a gain/loss at lease commencement.
During the course of adopting ASC 842, the Company applied various practical expedients including:
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The package of practical expedients (applied to all leases) that allowed lessees and lessors not to reassess:
a.
whether any expired or existing contracts are or contain leases,
b.
lease classification for any expired or existing leases, and
c.
whether initial direct costs for any expired or existing leases qualify for capitalization under ASC 842.
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The transition practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements, and
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The transition practical expedient for lessees that allowed businesses to not separate lease and non-lease components. The Company applied the practical expedient to all classes of underlying assets when valuing right-of-use assets and lease liabilities. Contracts where the Company is the lessor were separated between the lease and non-lease components.
The Company applied the modified retrospective method of adoption and elected to continue to apply the guidance in ASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The cumulative effect of the adoption of ASC 842 on our January 1, 2019 Consolidated Balance Sheet was as follows (in millions):
The primary impact of adoption was due to the recognition of a right-of-use-asset and lease liability for an operating land lease in Panama associated with the Colon LNG power plant and regasification terminal.
ASC 606 - Revenue from Contracts with Customers
On January 1, 2018, the Company adopted ASU 2014-09, "Revenue from Contracts with Customers," and its subsequent corresponding updates ("ASC 606"). Under this standard, an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company applied the modified retrospective method of adoption to the contracts that were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under ASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with the previous revenue recognition standard. For contracts that were modified before January 1, 2018, the Company reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price.
The cumulative effect to our January 1, 2018 Consolidated Balance Sheet resulting from the adoption of ASC 606 was as follows (in millions):
135 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The Mong Duong II power plant in Vietnam is the primary driver of changes in revenue recognition under the new standard. This plant is operated under a build, operate, and transfer contract and will be transferred to the Vietnamese government after the completion of a 25-year PPA. Under the previous revenue recognition standard, construction costs were deferred to a service concession asset, which was expensed in proportion to revenue recognized for the construction element over the term of the PPA. Under ASC 606, construction revenue and associated costs are recognized as construction activity occurs. As construction of the plant was substantially completed in 2015, revenues and costs associated with the construction were recognized through retained earnings, and the service concession asset was derecognized. A loan receivable was recognized for the future expected payments for the construction performance obligation. As the payments for the construction performance obligation occur over a 25-year term, a significant financing element was determined to exist which is accounted for under the effective interest rate method. The other performance obligation to operate and maintain the facility is measured based on the capacity made available.
The impact to our Consolidated Balance Sheet as of December 31, 2018 resulting from the adoption of ASC 606 as compared to the previous revenue recognition standard was as follows (in millions):
The impact to our Consolidated Statement of Operations for the year ended December 31, 2018 resulting from the adoption of ASC 606 as compared to the previous revenue recognition standard was as follows (in millions):
New Accounting Pronouncements Issued But Not Yet Effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company’s consolidated financial statements once adopted. Accounting pronouncements not listed below were assessed and determined to
136 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
be either not applicable or are expected to have no material impact on the Company’s consolidated financial statements.
ASU 2016-13 and its subsequent corresponding updates will update the impairment model for financial assets measured at amortized cost, known as the Current Expected Credit Loss (“CECL”) model. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, there will be no change to the measurement of credit losses, except that unrealized losses due to credit-related factors will be recognized as an allowance on the balance sheet with a corresponding adjustment to earnings in the income statement. There are various transition methods available upon adoption.
The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements; however, it is expected that the new current expected credit loss model will primarily impact the calculation of the Company’s expected credit losses on $1.5 billion in gross trade accounts receivable, the $1.4 billion loan receivable at Mong Duong, $64 million in financing receivables in Argentina, and $33 million in financing receivables in Chile. The Company does not expect a material impact to result from the application of CECL on our trade accounts receivable; however, we are continuing to evaluate the potential impacts on our Mong Duong loan receivable and our financing receivables. In particular, the Company is finalizing our determination of the reasonable and supportable forecast period and the appropriate mix of relevant internal and external credit quality information for these types of financial assets, where we have no historical loss experience and limited external market data available. Estimated credit losses, if material, will be presented on the face of the balance sheet as an allowance that reduces the amortized cost basis of affected financial assets. The standard will also impact the presentation of expected credit-related losses (if any) for the Company’s $326 million of available-for-sale debt securities, which will be presented parenthetically as an allowance on the consolidated balance sheet.
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 (in millions):
3. PROPERTY, PLANT AND EQUIPMENT
The following table summarizes the components of the electric generation and distribution assets and other property, plant and equipment (in millions) with their estimated useful lives (in years). The amounts are stated net of all prior asset impairment losses recognized.
137 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The following table summarizes depreciation expense (including the amortization of assets recorded under finance leases in 2019 or capital leases in prior periods, and the amortization of asset retirement obligations) and interest capitalized during development and construction on qualifying assets for the periods indicated (in millions):
Property, plant and equipment, net of accumulated depreciation, of $10 billion and $11 billion was mortgaged, pledged or subject to liens as of December 31, 2019 and 2018, respectively, including assets classified as held-for-sale.
The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation as of the dates indicated (in millions):
4. ASSET RETIREMENT OBLIGATIONS
The following table presents amounts recognized related to asset retirement obligations for the periods indicated (in millions):
The Company's asset retirement obligations include active ash landfills, water treatment basins and the removal or dismantlement of certain plants and equipment. The Company uses the cost approach to determine the initial value of ARO liabilities, which is estimated by discounting expected cash outflows to their present value using market-based rates at the initial recording of the liabilities. Cash outflows are based on the approximate future disposal costs as determined by market information, historical information or other management estimates. Subsequent downward revisions of ARO liabilities are discounted using the market-based rates that existed when the liability was initially recognized. These inputs to the fair value of the ARO liabilities are considered Level 3 inputs under the fair value hierarchy.
During the year ended December 31, 2019, the Company increased the asset retirement obligation and corresponding asset at IPL by $75 million and decreased the asset retirement obligation at DPL by $87 million. The increase at IPL reflects an increase to estimated ash pond closure costs, including groundwater remediation as required by the EPA under the Resource Conservation and Recovery Act. The decrease at DPL was attributable to a revision of the estimated liabilities resulting from the retirement of the Stuart and Killen facilities, and their subsequent transfer in December 2019.
138 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
During the year ended December 31, 2018, the $24 million increase in estimated cash flows was primarily attributable to an increase of $55 million in estimated ash pond closure costs and revised closure dates associated with an EPA rule regulating CCR at IPL and an increase in coal pile remediation costs at DPL. These were partially offset by a decrease of $32 million due to reductions in estimated closure costs associated with ash ponds and landfills at DPL resulting in a reduction to Cost of Sales on the Consolidated Statements of Operations.
5. 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. Because these amounts are 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 water rights, 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 either measured at fair value using quoted market prices or based on comparisons to market data obtained for similar assets. Debt securities primarily consist of unsecured debentures and certificates of deposit held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the market interest rates in Brazil. Debt securities are measured at fair value based on comparisons to market data obtained for similar assets.
Derivatives - Derivatives are measured at fair value using quoted market prices or the income approach utilizing volatilities, spot and forward benchmark interest rates (such as LIBOR and EURIBOR), foreign exchange rates, credit data, and commodity prices, as applicable. When significant inputs are not observable, the Company uses relevant techniques to determine the inputs, such as regression analysis or prices for similarly traded instruments available in the market.
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. Specifically, where there is limited forward curve data with respect to foreign exchange contracts, beyond the traded points, the Company utilizes the interest rate differential approach to construct the remaining portion of the forward curve. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable requiring the use of proxy yield curves of similar credit quality.
To determine the fair value of a derivative, cash flows are discounted using the relevant spot benchmark interest rate. The Company then makes a credit valuation adjustment ("CVA"), as applicable, 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 potential future scenarios in which the derivative is in an asset position is based on the counterparty's credit ratings, credit default swap spreads, and debt spreads, as available. The CVA for potential future scenarios in which the derivative is in a liability position 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
139 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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 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 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 based upon interest rates and other features of the 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 ("DCF") analyses. 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, 2019. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to December 31, 2019.
Nonrecurring measurements - For nonrecurring measurements derived using the income approach, fair value is generally determined using valuation models based on the principles of DCF. The income approach is most often used in the impairment evaluation of long-lived tangible assets, equity method investments, goodwill, and intangible assets. 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. Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management in the valuation process.
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. 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 is party 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.
140 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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.
Recurring Measurements - The following table presents, 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 dates indicated (in millions). For the Company's investments in marketable debt securities, the security classes presented were determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its marketable securities:
As of December 31, 2019, all AFS debt securities had stated maturities within one year. For the years ended December 31, 2019, 2018, and 2017, no other-than-temporary impairment of marketable securities were recognized in earnings or Other Comprehensive Income (Loss). Gains and losses on the sale of investments are determined using the specific-identification method. The following table presents gross proceeds from sale of AFS securities for the periods indicated (in millions):
_____________________________
(1)
Proceeds in the year ended December 31, 2018 include $119 million of non-cash proceeds from non-convertible debentures at Guaimbê Solar Complex. See Note 26-Acquisitions for further information.
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, 2019 and 2018 (presented net by type of derivative in millions). Transfers between Level 3 and Level 2 principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.
141 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) as of December 31, 2019 (in millions, except range amounts):
For interest rate derivatives and 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
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 the then-latest available carrying amount. The following table summarizes our major categories of assets measured at fair value on a nonrecurring basis and their level within the fair value hierarchy (in millions):
142 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
_____________________________
(1)
Represents the carrying values at the dates of initial measurement, before fair value adjustment.
(2)
See Note 22-Asset Impairment Expense for further information.
(3)
Per the Company's policy, pre-tax loss is limited to the impairment of long-lived assets. Any additional loss will be recognized on completion of the sale. See Note 22-Asset Impairment Expense and Note 25-Held-for-Sale and Dispositions for further information.
The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets held and used measured on a nonrecurring basis during the year ended December 31, 2019 (in millions, except range amounts):
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
The following table presents (in millions) 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 the periods indicated, but for which fair value is disclosed:
_____________________________
(1)
These amounts primarily relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and amounts impacted by the Stabilization Fund enacted by the Chilean government and are included in Other noncurrent assets in the accompanying Consolidated Balance Sheets. The fair value and carrying amount of the Argentina receivables exclude VAT of $11 million and $16 million as of December 31, 2019 and 2018, respectively.
143 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Volume of Activity - The following table presents the Company's maximum notional (in millions) over the remaining contractual period by type of derivative as of December 31, 2019, regardless of whether they are in qualifying cash flow hedging relationships, and the dates through which the maturities for each type of derivative range:
Accounting and Reporting - Assets and Liabilities - The following tables present the fair value of assets and liabilities related to the Company's derivative instruments as of the periods indicated (in millions):
144 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
As of December 31, 2019 and 2018, all derivative instruments subject to credit risk-related contingent features were in an asset position.
Earnings and Other Comprehensive Income (Loss) - The following table presents the pre-tax gains (losses) recognized in AOCL and earnings related to all derivative instruments for the periods indicated (in millions):
_____________________________
(1)
Cash flow hedge was discontinued on a cross-currency swap in 2019 because the underlying debt was prepaid. Cash flow hedge was discontinued in 2017 because it was probable the forecasted transaction will not occur.
AOCL is expected to decrease pre-tax income from continuing operations for the twelve months ended December 31, 2020 by $73 million, primarily due to interest rate derivatives.
7. FINANCING RECEIVABLES
Receivables with contractual maturities of greater than one year are considered financing receivables. The Company's financing receivables are primarily related to amended agreements or government resolutions that are due from CAMMESA, the administrator of the wholesale electricity market in Argentina. The following table presents financing receivables by country as of the dates indicated (in millions):
Argentina
Collection of the principal and interest on these receivables is subject to various business risks and uncertainties, including, but not limited to, the continued 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. The decrease in Argentina financing receivables was primarily due to planned collections and unfavorable FX impacts.
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
145 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
begins operations. In addition, AES Argentina receives an ownership interest in these newly built plants once the receivables have been fully repaid.
The FONINVEMEM receivables are denominated in Argentine pesos, but indexed to USD, which represents a foreign currency derivative. Due to differences between spot rates, used to remeasure the receivables, and discounted forward rates, used to value the foreign currency derivative, these two items will not perfectly offset over the life of the receivable. Once settled, the foreign currency derivative will offset the accumulated unrealized foreign currency losses resulting from the devaluation of the FONINVEMEM receivable. As of December 31, 2019 and 2018, 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 $94 million and $199 million, respectively.
The receivables under the FONINVEMEM Agreements have been actively collected since the related plants commenced operations in 2010 and 2016. In assessing the collectability of the receivables under these agreements, the Company also considers historic collection evidence in accordance with the agreements.
Other Agreements - Other agreements primarily consist of resolutions passed by the Argentine government in which AES Argentina will receive compensation for investments in new generation plants and technologies. The timing of collections depend on corresponding agreements and collectability of these receivables are assessed on an ongoing basis.
Chile
AES Gener has recorded noncurrent receivables pertaining to revenues recognized on regulated energy contracts that were impacted by the Stabilization Fund created by the Chilean government in October 2019. Historically, the government updated the prices for these contracts every six months to reflect the indexation the contracts have to exchange rates and commodities prices. The Stabilization Fund does not allow the pass-through of these contractual indexation updates to customers beyond the pricing in effect at July 1, 2019, until new lower-cost renewable contracts are incorporated into pricing in 2023. Consequently, costs incurred in excess of the July 1, 2019 price will be accumulated and borne by generators. It is expected that these noncurrent receivables will be collected prior to December 31, 2027.
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)
The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES effective ownership in Guacolda of 33%.
(2)
Simple Energy merged with Tendril on July 1, 2019 to form Uplight. Prior year information reported relates to Simple Energy.
(3)
The Eólica Mesa La Paz project received funding throughout 2019 and began operations during December 2019.
(4)
Represents a VIE in which the Company holds a variable interest, but is not the primary beneficiary.
(5)
Includes Bosforo, Fluence, Distributed Energy equity method investments, and others.
OPGC - In December 2019, an other-than-temporary impairment was identified at OPGC primarily due to the estimated market value of the Company's investment and other negative developments impacting future expected cash flows at the investee. A calculation of the fair value of the Company’s investment in OPGC was required to evaluate whether there was a loss in the carrying value of the investment. Based on management’s estimate of fair value of $212 million, the Company recognized an other-than-temporary impairment of $92 million in Other non-operating expense. The OPGC equity method investment is reported in the Eurasia SBU reportable segment.
Guacolda - In October 2019, Guacolda management reviewed the recoverability of the Guacolda asset group and determined the undiscounted cash flows did not exceed the carrying amount. Guacolda recognized a long-lived
146 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
asset impairment at the investee level, which negatively impacted the Company's Net equity in earnings (losses) of affiliates by $158 million. The Guacolda equity method investment is reported in the South America SBU reportable segment.
In October 2018, an other-than-temporary impairment was identified at Guacolda primarily as a result of increased renewable generation in Chile lowering energy prices, impacting management's ability to re-contract Guacolda's generation after expiration of existing PPAs. A calculation of the fair value of Gener's investment in Guacolda was required to evaluate whether there was a loss in the carrying value of the investment. Based on management's estimate of fair value of $209 million, the Company recognized an other-than-temporary impairment of $144 million in Other non-operating expense.
Gas Natural del Este - In September 2019, AES Andres completed an agreement with Energas Group to establish a joint venture for the purpose of selling natural gas and related terminal services, storage, regasification, and transportation to customers in the Dominican Republic. Gas Natural del Este, a wholly-owned subsidiary of the joint venture, acquired the Eastern Pipeline development project from AES Andres for total consideration of $55 million, resulting in a gain of $2 million. The transaction was considered a contribution of a nonfinancial asset in exchange for a noncontrolling interest in the joint venture. As the Company does not control the joint venture, it is accounted for as an equity method investment and is reported in the MCAC SBU reportable segment.
Simple Energy - On July 1, 2019, Simple Energy merged with Tendril, a previously unrelated party, to form Uplight, a new company that offers a comprehensive platform for utility customer engagement. As part of this merger, the Company contributed its ownership interest in Simple Energy and $53 million of cash in exchange for an ownership interest in the merged company. This transaction resulted in a gain on sale of $12 million and a total investment in Uplight of $98 million. As the Company does not control Uplight, it is accounted for as an equity method investment and reported as part of Corporate and Other.
In April 2018, the Company invested $35 million in Simple Energy, a provider of utility-branded marketplaces and omni-channel instant rebates, accounted for as an equity method investment.
sPower - In April 2019, the Company closed on the sale of approximately 48% of its interest in a portfolio of sPower’s operating assets for $173 million, subject to customary purchase price adjustments, of which $58 million was retained at sPower to pay down debt. This sale resulted in a pre-tax gain on sale of business interests of $28 million. After the sale, the Company’s ownership interest in this portfolio of sPower’s operating assets decreased from 50% to approximately 26%. The sPower equity method investment is reported in the US and Utilities SBU reportable segment.
Distributed Energy - In December 2018, Distributed Energy acquired the remaining equity interest in a partnership holding various solar projects for consideration of $23 million. This transaction resulted in a loss of $5 million, reported in Other expense in the Consolidated Statement of Operations. The projects, previously recorded as equity method investments, have been consolidated. See Note 26-Acquisitions for further discussion.
Fluence - On January 1, 2018, Siemens and AES closed on the creation of the Fluence joint venture with each party holding a 50% ownership interest. The Company contributed $7 million in cash and $20 million in non-cash assets from the AES Advancion energy storage development business as consideration for the transaction, and received an equity interest in Fluence with a fair value of $50 million. See Note 25-Held-for-Sale and Dispositions for further discussion. Fluence is a global energy storage technology and services company. As the Company does not control Fluence, the investment is accounted for as an equity method investment. The Fluence equity method investment is reported as part of Corporate and Other.
147 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
AES Barry Ltd. - The Company holds a 100% ownership interest in AES Barry Ltd. ("Barry"), a dormant entity in the U.K. 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, 2019 and 2018, other long-term liabilities included $44 million and $43 million related to this debt agreement.
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 (in millions):
At December 31, 2019, retained earnings included $14 million related to the undistributed earnings of the Company's 50%-or-less owned affiliates. Distributions received from these affiliates were $23 million, $83 million, and $69 million for the years ended December 31, 2019, 2018, and 2017, respectively. As of December 31, 2019, the underlying equity in the net assets of our equity affiliates exceeded the aggregate carrying amount of our investments in equity affiliates by $225 million.
9. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill - The following table summarizes the carrying amount of goodwill by reportable segment for the years ended December 31, 2019 and 2018 (in millions):
_____________________________
(1)
Goodwill and accumulated impairment losses at the Eurasia reportable segment were reduced by $122 million due to the sale of Kilroot in 2019.
148 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Other Intangible Assets - The following table summarizes the balances comprising Other intangible assets in the accompanying Consolidated Balance Sheets (in millions) as of the periods indicated:
_____________________________
(1)
Represent legal rights to receive system reliability payments from the regulator.
(2)
Acquired or purchased emissions allowances are finite-lived intangible assets that are expensed when utilized and included in net income for the year.
(3)
Includes management rights, sales concessions, renewable energy credits and incentives, and other individually insignificant intangible assets.
The following tables summarize other intangible assets acquired during the periods indicated (in millions):
The following table summarizes the estimated amortization expense by intangible asset category for 2020 through 2024:
Intangible asset amortization expense was $45 million, $47 million and $34 million for the years ended December 31, 2019, 2018 and 2017, respectively.
149 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
10. REGULATORY ASSETS AND LIABILITIES
The Company has recorded regulatory assets and liabilities (in millions) that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:
_____________________________
(1)
Past expenditures on which the Company earns a rate of return.
Our regulatory assets and current regulatory liabilities primarily consist of under or overcollection of costs that are generally non-controllable, such as purchased electricity, energy transmission, fuel costs, and other sector costs. These costs are recoverable or refundable as defined by the laws and regulations in our markets. Our regulatory assets also include defined pension and postretirement benefit obligations equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Other current and noncurrent regulatory assets primarily consist of:
•
Undercollections on rate riders such as wholesale margin sharing and MISO costs at IPL and storm costs at DPL;
•
Unamortized premiums reacquired or redeemed on long-term debt at IPL and DPL, which are amortized over the lives of the original issuances; and
•
OVEC costs at DPL.
Our noncurrent regulatory liabilities primarily consist of obligations for removal costs which do not have an associated legal retirement obligation. Our noncurrent regulatory liabilities also include deferred income taxes related to differences in income recognition between tax laws and accounting methods, which will be passed through to our regulated customers via a decrease in future retail rates. See Note 23-Income Taxes for further information.
In the accompanying Consolidated Balance Sheets the current regulatory assets and liabilities are reflected in Other current assets and Accrued and other liabilities, respectively, and the noncurrent regulatory assets and liabilities are reflected in Other noncurrent assets and Other noncurrent liabilities, respectively. All of the regulatory assets and liabilities as of December 31, 2019 and December 31, 2018 related to the US and Utilities SBU.
150 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
11. DEBT
NON-RECOURSE DEBT - The following table summarizes the carrying amount and terms of non-recourse debt at our subsidiaries as of the periods indicated (in millions):
_____________________________
(1)
Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
(2)
Excludes $3 million (current) and $67 million (noncurrent) finance lease liabilities included in the respective non-recourse debt line items on the Consolidated Balance Sheet as of December 31, 2019. See Note 14-Leases for further information.
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 that economically fix the variable component of the interest rates on the portion of the variable rate debt being hedged in an aggregate notional principal amount of approximately $1.8 billion on non-recourse debt outstanding at December 31, 2019.
Non-recourse debt as of December 31, 2019 is scheduled to reach maturity as shown below (in millions):
As of December 31, 2019, AES subsidiaries with facilities under construction had a total of approximately $470 million of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $1.1 billion in various 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.
151 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Significant transactions - During the year ended December 31, 2019, the Company's subsidiaries had the following significant debt transactions:
_____________________________
(1)
Issuances relate to the June 2017 long-term non-recourse debt financing to fund the Southland re-powering construction projects, a non-recourse bridge loan in September 2019, and long-term non-recourse debt financing issued in December 2019 to settle the bridge loan.
(2)
Includes transactions at DPL and its subsidiary, DP&L.
(3)
Non-cash transaction via an equity affiliate. See below for further information.
Cochrane - In November 2019, Cochrane issued $430 million aggregate principal of 5.50% senior unsecured notes due in 2027 and entered into a $445 million 6.25% senior secured facility agreement due in 2034. The net proceeds from the issuance and draw down were used to prepay the outstanding principal of $833 million under its variable rate notes due in 2030. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $24 million.
Gener - In March 2019, Gener issued $550 million aggregate principal of 7.125% senior unsecured notes due in 2079. The net proceeds from the issuance were used to purchase via tender offer the outstanding principal of $450 million of its 8.375% senior unsecured notes due in 2073.
In October 2019, Gener issued $450 million aggregate principal of 6.35% senior unsecured notes due in 2079. The net proceeds from the issuance were used to fund the acquisition of Los Cururos, purchase via tender offer $73 million and $55 million aggregate principal of its senior unsecured notes due in 2021 and 2025, respectively, and prepay the remaining outstanding principal of $119 million of its senior unsecured notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $29 million.
Mong Duong - In August 2019, Mong Duong refinanced $1.1 billion aggregate principal of its existing senior secured notes due in 2029 with variable interest rates ranging from LIBOR + 2.25% to LIBOR + 4.15% in exchange for a fixed rate loan with a newly formed SPV, accounted for as an equity affiliate, due in 2029 with interest rates that vary from 4.41% to 7.18%. This refinancing was a non-cash transaction as the SPV acquired all of the outstanding rights and obligations of the original Mong Duong lenders. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $31 million.
DP&L - In June 2019, DP&L issued $425 million aggregate principal of 3.95% First Mortgage Bonds due in 2049. The net proceeds from the issuance were used to prepay the outstanding principal of $435 million under its variable rate $445 million credit agreement due in 2022.
DPL - In April 2019, DPL issued $400 million aggregate principal of 4.35% senior unsecured notes due in 2029. The net proceeds from the issuance were used to redeem $400 million of the $780 million aggregate principal outstanding of its 7.25% senior unsecured notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $43 million.
Non-Recourse Debt Covenants, Restrictions and Defaults - The terms of the Company's non-recourse debt include certain financial and nonfinancial 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 and financial ratios, minimum levels of working capital and limitations on incurring additional indebtedness.
As of December 31, 2019 and 2018, approximately $372 million and $627 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.
152 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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 $1.2 billion at December 31, 2019.
The following table summarizes the Company's subsidiary non-recourse debt in default (in millions) as of December 31, 2019. Due to the defaults, these amounts are included in the current portion of non-recourse debt:
_____________________________
(1)
Classified as current held-for-sale liability on the Consolidated Balance Sheets.
The above defaults are not payment defaults. In Puerto Rico, the subsidiary non-recourse debt defaults were triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents due to the bankruptcy of the offtaker.
The AES Corporation's recourse debt agreements include cross-default clauses that will trigger if a subsidiary or group of subsidiaries for which the non-recourse debt is in default provides 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, 2019, the Company had no defaults which resulted in or were 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.
RECOURSE DEBT - The following table summarizes the carrying amount and terms of recourse debt of the Company as of the periods indicated (in millions):
The following table summarizes the principal amounts due under our recourse debt for the next five years and thereafter (in millions):
In September 2019, the Company prepaid $343 million aggregate principal of its LIBOR + 1.75% existing senior secured term loan due in 2022 and $100 million of its 4.875% senior unsecured notes due in 2023. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $5 million.
In December 2018, the Company prepaid $150 million aggregate principal of its existing senior secured term
153 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
loan due in 2022. As a result of the transaction, the Company recognized a loss on extinguishment of debt of $1 million.
In March 2018, the Company purchased via tender offers $671 million aggregate principal of its existing 5.50% senior unsecured notes due in 2024 and $29 million of its existing 5.50% senior unsecured notes due in 2025. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $44 million.
In March 2018, the Company issued $500 million aggregate principal of 4.00% senior notes due in 2021 and $500 million of 4.50% senior notes due in 2023. The Company used the proceeds from these issuances to purchase via tender offer in full the $228 million balance of its 8.00% senior notes due in 2020 and the $690 million balance of its 7.375% senior notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $125 million.
Recourse Debt Covenants and Guarantees - The Company's obligations under the senior secured credit facility and senior secured term loan are, subject to certain exceptions, secured by (i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company; and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.
The senior secured credit facility and senior secured term loan are 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 Company'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, evaluated quarterly, requiring the Company to maintain a minimum ratio of adjusted operating cash flow to interest charges on recourse debt of 2.5 times and a maximum ratio of recourse debt to adjusted operating cash flow of 5.75 times.
The terms of the Company's senior unsecured notes and senior secured term loan contain certain covenants including limitations on the Company's ability to incur liens or enter into sale and leaseback transactions.
12. COMMITMENTS
The Company enters into long-term contracts for construction projects, maintenance and service, transmission of electricity, operations services and purchases of electricity and fuel. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances. The following table shows the future minimum commitments for continuing operations under these contracts as of December 31, 2019 for 2020 through 2024 and thereafter as well as actual purchases under these contracts for the years ended December 31, 2019, 2018, and 2017 (in millions):
154 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
13. CONTINGENCIES
Guarantees and Letters of Credit - In connection with certain project financings, acquisitions and dispositions, power purchases 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 15 years.
The following table summarizes the Parent Company's contingent contractual obligations as of December 31, 2019. Amounts presented in the following table 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. There were no obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses.
_____________________________
(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.
During the year ended December 31, 2019, the Company paid letter of credit fees ranging from 1% to 3% 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. For the periods ended December 31, 2019 and 2018, the Company recognized liabilities of $4 million and $5 million for projected environmental remediation costs, respectively. 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, 2019. In aggregate, the Company estimates the range of potential losses related to environmental matters, where estimable, to be up to $15 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 recognized aggregate liabilities for all claims of approximately $55 million and $53 million as of December 31, 2019 and 2018, 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 regulatory matters and commercial disputes in international jurisdictions. 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.
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, 2019. The material contingencies where a loss is reasonably possible primarily include disputes with offtakers, suppliers and EPC contractors; alleged breaches of contract; alleged violation of laws and regulations; income tax and non-income tax matters with tax authorities; and regulatory matters. In aggregate, the Company estimates the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between $75 million and $503 million. The amounts
155 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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.
14. LEASES
LESSEE - Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the period indicated (in millions):
The following table summarizes supplemental balance sheet information related to leases as of the period indicated:
The following table summarizes the components of lease expense recognized in Cost of Sales on the Consolidated Statements of Operations for the year ended (in millions):
Operating cash outflows from operating leases included in the measurement of lease liabilities were $48 million for the twelve months ended December 31, 2019.
156 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The following table shows the future lease payments under operating and finance leases for continuing operations together with the present value of the net lease payments as of December 31, 2019 for 2020 through 2024 and thereafter (in millions):
LESSOR - Lease revenue included in the Consolidated Statements of Operations was $600 million for the twelve months ended December 31, 2019, of which $130 million was related to variable lease payments. Underlying gross assets and accumulated depreciation of operating leases included in Property, Plant and Equipment on the Consolidated Balance Sheets were $2.9 billion and $707 million, respectively, as of December 31, 2019.
The option to extend or terminate a lease is based on customary early termination provisions in the contract, such as payment defaults, bankruptcy, and lack of performance on energy delivery. The Company has not recognized any early terminations as of December 31, 2019. Certain leases may provide for variable lease payments based on usage or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments.
The following table shows the future lease receipts as of December 31, 2019 for 2020 through 2024 and thereafter (in millions):
The Company is constructing and operating projects that pair battery energy storage systems ("BESS") with solar energy systems, which allows the project more flexibility on when to provide energy to the grid. The Company will enter into PPAs for the full output of the facility that allow customers the ability to determine when to charge and discharge the BESS. These arrangements include both lease and non-lease elements under ASC 842, with the BESS component constituting a sales-type lease. Upon commencement of the lease, the book value of the leased asset is removed from the balance sheet and a net investment in sales-type lease is recognized based on the present value of fixed payments under the contract and the residual value of the underlying asset. Due to the variable nature of lease payments under these contracts, the Company recorded losses at commencement of sales-type leases of $36 million for the year ended December 31, 2019. These amounts are recognized in Other expense in the Consolidated Statement of Operations. See Note 21-Other Income and Expense for further information.
15. BENEFIT PLANS
Defined Contribution Plan - The Company sponsors four defined contribution plans ("the DC Plans"). Two plans cover U.S. non-union employees; one for Parent Company and certain US and Utilities SBU business employees, and one for DPL employees. The remaining two plans include union and non-union employees at IPL and union employees at DPL. The DC Plans are qualified under section 401 of the Internal Revenue Code. Most 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
157 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
considered an eligible employee under a plan. Within the DC Plans, the Company provides matching contributions in addition to other non-matching contributions. Participants are fully vested in their own contributions. The Company's contributions vest over various time periods ranging from immediate up to five years. For the years ended December 31, 2019, 2018 and 2017, costs for defined contribution plans were approximately $19 million, $21 million and $23 million, respectively.
Defined Benefit Plans - Certain of the Company's subsidiaries have defined benefit pension plans covering substantially all of their respective employees ("the DB Plans"). Pension benefits are based on years of credited service, age of the participant, and average earnings. Of the 28 active DB Plans as of December 31, 2019, 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 (in millions):
The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the funded status of the DB Plans, both domestic and foreign, as of the periods indicated (in millions):
The following table summarizes the Company's U.S. and foreign accumulated benefit obligation as of the periods indicated (in millions):
158 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The following table 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)
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. Unrecognized gains or losses are amortized using the “corridor approach,” under which the net gain or loss in excess of 10% of the greater of the projected benefit obligation or the market-related value of the assets, if applicable, is amortized.
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 2019. 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, 2019 is affected by the assumptions as of that date. Pension expense for 2019 is affected by the December 31, 2018 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the following table (in millions):
The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for the years indicated (in millions):
The following table summarizes the amounts reflected in AOCL, including AOCL attributable to noncontrolling interests, on the Consolidated Balance Sheet as of December 31, 2019, that have not yet been recognized as components of net periodic benefit cost (in millions):
159 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The following table summarizes the Company's target allocation for 2019 and pension plan asset allocation, both domestic and foreign, as of the periods indicated:
The U.S. DB 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 meets or exceeds the assumed actuarial rate; and
•
long-term competitive rate of return on investments, net of expenses, that equals 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 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. DB Plan assets by category of investment and level within the fair value hierarchy as of the periods indicated (in millions):
_____________________________
(1)
Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
(2)
In 2019, the U.S. plans moved all investments except cash and cash equivalents into collective trusts; therefore, the 2019 balances under the equity securities, debt securities, and real estate categories shown above represent investments through collective trusts. The plans have chosen collective trusts for which the underlying investments are mutual funds, mutual funds for which debt securities are the primary underlying investment, or real estate in alignment with the target asset allocation.
The investment strategy of the foreign DB 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 DB plan assets by category of investment and level within the fair value hierarchy as of the periods indicated (in millions):
_____________________________
(1)
Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
160 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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 (in millions):
16. REDEEMABLE STOCK OF SUBSIDIARIES
The following table is a reconciliation of changes in redeemable stock of subsidiaries (in millions):
The following table summarizes the Company's redeemable stock of subsidiaries balances as of the periods indicated (in millions):
_____________________________
(1)
Characteristics of quotas are similar to common stock.
Colon - Our partner in Colon made capital contributions of $10 million and $34 million during the year ended December 31, 2019 and 2018, respectively. Any subsequent adjustments to allocate earnings and dividends to our partner, or measure the investment at fair value, will be classified as temporary equity each reporting period as it is probable that the shares will become redeemable.
IPL - IPL had $60 million of cumulative preferred stock outstanding at December 31, 2019 and 2018, which represents five series of preferred stock. The total annual dividend requirements were approximately $3 million at December 31, 2019 and 2018. 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.
17. EQUITY
Equity Transactions with Noncontrolling Interests
Distributed Energy - In 2019 and 2018, Distributed Energy, through multiple transactions, sold noncontrolling interests in multiple project companies to tax equity partners. These transactions resulted in a $133 million and $98 million increase to noncontrolling interest in 2019 and 2018, respectively. Distributed Energy is reported in the US and Utilities SBU reportable segment.
Alto Maipo - In March 2017, AES Gener completed the legal and financial restructuring of Alto Maipo. As part of this restructuring, AES indirectly acquired the 40% ownership interest of the noncontrolling shareholder for a de minimis payment, and sold a 6.7% interest in the project to the construction contractor. This transaction resulted in a $196 million increase to the Parent Company’s Stockholders’ Equity due to an increase in additional paid-in-capital of $229 million, offset by the reclassification of accumulated other comprehensive losses from NCI to the Parent
161 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Company Stockholders’ Equity of $33 million. No gain or loss was recognized in net income as the sale was not considered to be a sale of in-substance real estate. After completion of the sale, the Company has an effective 62% economic interest in Alto Maipo. As the Company maintained control of the partnership after the sale, Alto Maipo continues to be consolidated by the Company within the South America SBU reportable segment.
Dominican Republic - In September 2017, Linda Group acquired 5% of our Dominican Republic business for $60 million, pre-tax. This transaction resulted in a net increase of $25 million to the Company’s additional paid-in-capital and noncontrolling interest, respectively. No gain or loss was recognized in net income as the sale was not considered 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.
The following table summarizes the net income attributable to The AES Corporation and all transfers (to) from noncontrolling interests for the periods indicated (in millions):
Accumulated Other Comprehensive Loss - The changes in AOCL by component, net of tax and noncontrolling interests, for the periods indicated were as follows (in millions):
162 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Reclassifications out of AOCL are presented in the following table. Amounts for the periods indicated are in millions and those in parenthesis indicate debits to the Consolidated Statements of Operations:
Common Stock Dividends - The Parent Company paid dividends of $0.1365 per outstanding share to its common stockholders during the first, second, third and fourth quarters of 2019 for dividends declared in December 2018, February, July and October 2019, respectively.
On December 6, 2019, the Board of Directors declared a quarterly common stock dividend of $0.1433 per share payable on February 14, 2020 to shareholders of record at the close of business on January 31, 2020.
Stock Repurchase Program - No shares were repurchased in 2019. The cumulative repurchases from the commencement of the Program in July 2010 through December 31, 2019 totaled 154.3 million shares for a total cost of $1.9 billion, at an average price per share of $12.12 (including a nominal amount of commissions). As of December 31, 2019, $264 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 153,891,260 and 154,905,595 shares were held as treasury stock at December 31, 2019 and 2018, 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.
18. 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 businesses internally and is mainly organized by geographic regions which provides a socio-political-economic understanding of our business. The management reporting structure is organized by four SBUs led by our President and Chief Executive Officer: US and Utilities, South America, MCAC, and Eurasia SBUs. Using the accounting guidance on segment reporting, the Company determined that its four operating segments are aligned with its four reportable segments corresponding to its SBUs.
Corporate and Other - Included in "Corporate and Other" are the results of the AES self-insurance company
163 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
and certain equity affiliates, corporate overhead costs which are not directly associated with the operations of our four reportable segments, and certain 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 The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities. The Company has concluded Adjusted PTC better 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 investors in determining which businesses have the greatest impact on the Company's results.
Revenue and Adjusted PTC are presented before inter-segment eliminations, which includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees, and the write-off of intercompany balances, as applicable. All intra-segment activity has been eliminated within the segment. Inter-segment activity has been eliminated within the total consolidated results.
The following tables present financial information by segment for the periods indicated (in millions):
164 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
The following table presents information, by country, about the Company's consolidated operations for each of the three years ended December 31, 2019, 2018, and 2017, and as of December 31, 2019 and 2018 (in millions). Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
_____________________________
(1)
Includes Puerto Rico revenues of $294 million, $257 million and $247 million for the years ended December 31, 2019, 2018 and 2017, respectively, and property, plant & equipment of $538 million and $553 million as of December 31, 2019 and 2018, respectively.
(2)
The Mong Duong II power project is operated under a build, operate and transfer contract. Future expected payments for the construction performance obligation are recognized in Loan receivable on the Consolidated Balance Sheets. See Note 20-Revenue for further information.
(3)
The Kilroot and Ballylumford property, plant and equipment was deconsolidated upon completion of the sale in June 2019. See Note 25-Held-For-Sale and Dispositions for further information.
(4)
The property, plant and equipment in Jordan was classified as held-for-sale as of December 31, 2019. See Note 25-Held-For-Sale and Dispositions for further information.
(5)
The Masinloc property, plant and equipment was classified as held-for-sale as of December 31, 2017, and deconsolidated upon completion of the sale in March 2018. See Note 25-Held-For-Sale and Dispositions for further information.
165 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
19. SHARE-BASED COMPENSATION
RESTRICTED STOCK
Restricted Stock Units - The Company issues 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. In all circumstances, RSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the RSU in cash or other assets of AES.
For the years ended December 31, 2019, 2018, and 2017, 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, 2019, 2018, and 2017 had grant date fair values per RSU of $17.53, $10.55 and $11.93, 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 (in millions):
_____________________________
(1)
Amount represents fair market value on the date of conversion.
Cash was not used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2019, 2018, and 2017. As of December 31, 2019, total unrecognized compensation cost related to RSUs of $10 million 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, 2019.
A summary of the activity of RSUs for the year ended December 31, 2019 follows (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 2019, AES has estimated a weighted average forfeiture rate of 11.95% for RSUs granted in 2019. 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 $10 million on a straight-line basis over a three-year period.
The following table summarizes the RSUs that vested and were converted during the periods indicated (RSUs in thousands):
OTHER SHARE BASED COMPENSATION
The Company has three other share-based award programs. The Company has recorded expenses of $22 million, $20 million and $8 million for 2019, 2018 and 2017, respectively, related to these programs.
Stock options - AES grants options to purchase shares of common stock under stock option plans to 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 issued in 2017, 2018 and 2019 have a three-year vesting schedule and vest in one-third increments over
166 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
the three-year period. The stock options have a contractual term of 10 years. 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.
Performance Stock Units - In 2017, 2018 and 2019, the Company issued PSUs to officers under its long-term compensation plan. PSUs are stock units which include performance conditions. Performance conditions are based on the Company's Proportional Free Cash Flow targets for 2017, 2018 and 2019. The 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. The Company believes that it is probable that the performance condition will be met and will continue to be evaluated throughout the performance period. In all circumstances, PSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the stock units in cash or other assets of AES.
Performance Cash Units - In 2017, 2018 and 2019, the Company issued PCUs to its officers under its long-term compensation plan. The value of these units is dependent on the market condition of total stockholder return on AES common stock as compared to the total stockholder return of the Standard and Poor's 500 Utilities Sector Index, Standard and Poor's 500 Index and MSCI Emerging Market Index over a three-year measurement period. Since PCUs are settled in cash, they qualify for liability accounting and periodic measurement is required.
20. REVENUE
The following table presents our revenue from contracts with customers and other revenue for the periods indicated (in millions):
_____________________________
(1)
Other non-regulated revenue primarily includes lease and derivative revenue not accounted for under ASC 606.
Contract Balances - The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. The contract liabilities from contracts with customers were $117 million and $109 million as of December 31, 2019 and December 31, 2018, respectively.
During the years ended December 31, 2019 and 2018, we recognized revenue of $13 million and $36 million, respectively, that was included in the corresponding contract liability balance at the beginning of the periods.
A significant financing arrangement exists for our Mong Duong plant in Vietnam. The plant was constructed under a build, operate, and transfer contract and will be transferred to the Vietnamese government after the completion of a 25 year PPA. The performance obligation to construct the facility was substantially completed in
167 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
2015. Approximately $1.4 billion of contract consideration related to the construction, but not yet collected through the 25 year PPA, was reflected as a loan receivable as of December 31, 2019.
Remaining Performance Obligations - The transaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the reporting period. As of December 31, 2019, the aggregate amount of transaction price allocated to remaining performance obligations was $12 million, primarily consisting of fixed consideration for the sale of renewable energy credits (RECs) in long-term contracts in the U.S. We expect to recognize revenue on approximately one-fifth of the remaining performance obligations in 2020 and 2021, with the remainder recognized thereafter.
21. OTHER INCOME AND EXPENSE
Other income generally includes gains on insurance recoveries in excess of property damage, gains on asset sales and liability extinguishments, favorable judgments on contingencies, gains on contract terminations, allowance for funds used during construction and other income from miscellaneous transactions. Other expense generally includes losses on asset sales and dispositions, losses on legal contingencies, defined benefit plan non-service costs, and losses from other miscellaneous transactions. The components are summarized as follows (in millions):
_____________________________
(1)
Associated with recoveries for property damage at the Andres facility in the Dominican Republic from a lightning incident in September 2018 and the upgrade of the tunnel lining at Changuinola.
(2)
Related to the amendment of the Oahu purchase agreement. See Note 26 -Acquisitions for further information.
(3)
In December 2016, the Company and YPF entered into a settlement in which all parties agreed to give up any and all legal action related to gas supply contracts that were terminated in 2008 and have been in dispute since 2009. In January 2017, the YPF board approved the agreement and paid the Company $60 million, thereby resolving all uncertainties around the dispute.
(4)
Related to losses recognized at commencement of sales-type leases at Distributed Energy. See Note 14-Leases for further information.
(5)
Associated with a loss due to damage from a lightning incident at the Andres facility in the Dominican Republic in September 2018 and a loss associated with upgrading the tunnel lining at Changuinola in 2019.
22. ASSET IMPAIRMENT EXPENSE
Hawaii - During the fourth quarter of 2019, the Company tested the recoverability of its long-lived coal-fired asset in Hawaii. Uncertainty around the ability to contract the asset upon expiration of its existing PPA resulted in management's decision to reassess the economic useful life of the generation facility. A decrease in the economic useful life was identified as an impairment indicator. The Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant and equipment and intangible assets, was determined to
168 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
have a fair value of $103 million using the income approach. As a result, the Company recognized asset impairment expense of $60 million as of December 31, 2019. Hawaii is reported in the US and Utilities SBU reportable segment.
Kilroot and Ballylumford - During the fourth quarter of 2017, the Company tested the recoverability of its long-lived assets at Kilroot, a coal and oil-fired plant in Northern Ireland, as Kilroot was not successful in bidding its coal units into the December 2017 capacity auction for the newly implemented I-SEM market. The Company determined that the carrying amount of the asset group was not recoverable. The Kilroot asset group was determined to have a fair value of $20 million using the income approach. As a result, the Company recognized asset impairment expense of $37 million during the year ended December 31, 2017, which was limited to the carrying value of the coal units.
In April 2019, the Company entered into an agreement to sell its entire 100% interest in the Kilroot coal and oil-fired plant and energy storage facility and the Ballylumford gas-fired plant in the United Kingdom. Upon meeting the held-for-sale criteria, the Company performed an impairment analysis and determined that the carrying value of the asset group of $232 million was greater than its fair value less costs to sell of $114 million. As a result, the Company recognized asset impairment expense of $115 million. The Company completed the sale of Kilroot and Ballylumford in June 2019. Prior to their sale, Kilroot and Ballylumford were reported in the Eurasia SBU reportable segment. See Note 25-Held-for-Sale and Dispositions for further information.
Shady Point - In December 2018, the Company entered into an agreement to sell Shady Point, a coal-fired generation facility in the U.S. Due first to the uncertainty around future cash flows, and then upon meeting the held-for-sale criteria, the Company performed an impairment analysis of the Shady Point asset group in the second, third and fourth quarters of 2018, resulting in the recognition of total asset impairment expense of $157 million for the year ended December 31, 2018. Using the market approach, the asset group was determined to have a fair value of $30 million as of December 31, 2018. The sale was completed in May 2019. Prior to the sale, Shady Point was reported in the US and Utilities SBU reportable segment. See Note 25-Held-for-Sale and Dispositions for further information.
Nejapa - During the fourth quarter of 2018, the Company tested the recoverability of its long-lived assets at Nejapa, a landfill gas plant in El Salvador. Decreased production as a result of the landfill owner's failure to perform improvements necessary to continue extracting gas from the landfill was identified as an impairment indicator. The Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant, and equipment and intangible assets, was determined to have a fair value of $5 million using the income approach. As a result, the Company recognized asset impairment expense of $37 million as of December 31, 2018. Nejapa is reported in the US and Utilities SBU reportable segment.
DPL - In March 2017, the Board of Directors of DPL approved the retirement of the DPL operated and co-owned Stuart coal-fired and diesel-fired generating units, and the Killen coal-fired generating unit and combustion turbine on or before June 1, 2018. The Company performed an impairment analysis and determined that the carrying amounts of the facilities were not recoverable. The Stuart and Killen asset groups were determined to have fair values of $3 million and $8 million, respectively, using the income approach. As a result, the Company recognized total asset impairment expense of $66 million. The Stuart and Killen units were retired in May 2018. Prior to their retirement, Stuart and Killen were reported in the US and Utilities SBU reportable segment.
In December 2017, DPL entered into an agreement for the sale of six of its combustion turbine and diesel-fired generation facilities and related assets ("DPL peaker assets"). Upon meeting the held-for-sale criteria, the Company performed an impairment analysis and determined that the carrying value of the asset group of $346 million was greater than its fair value less costs to sell of $237 million. As a result, the Company recognized asset impairment expense of $109 million. DPL completed the sale of the peaker assets in March 2018. Prior to their sale, the DPL peaker assets were reported in the US and Utilities SBU reportable segment. See Note 25-Held-for-Sale and Dispositions for further information.
Laurel Mountain - During the fourth quarter of 2017, the Company tested the recoverability of its long-lived assets at Laurel Mountain, a wind farm in the U.S. Impairment indicators were identified based on a decline in forward pricing. The Company determined that the carrying amount was not recoverable. The Laurel Mountain asset group was determined to have a fair value of $33 million using the income approach. As a result, the Company recognized asset impairment expense of $121 million. Laurel Mountain is reported in the US and Utilities SBU reportable segment.
169 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Kazakhstan Hydroelectric - In April 2017, the Republic of Kazakhstan stated the concession agreements would not be extended for Shulbinsk HPP and Ust-Kamenogorsk HPP, two hydroelectric plants in Kazakhstan, and initiated the process to transfer these plants back to the government. Upon meeting the held-for-sale criteria in the second quarter of 2017, the Company performed an impairment analysis and determined the carrying value of the asset group of $190 million, which included cumulative translation losses of $100 million, was greater than its fair value less costs to sell of $92 million. As a result, the Company recognized asset impairment expense of $92 million limited to the carrying value of the long-lived assets. The Company completed the transfer of the plants in October 2017. Prior to their transfer, the Kazakhstan hydroelectric plants were reported in the Eurasia SBU reportable segment. See Note 25-Held-for-Sale and Dispositions for further information.
Kazakhstan CHPs - In January 2017, the Company entered into an agreement for the sale of Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan. Upon meeting the held-for-sale criteria in the first quarter of 2017, the Company performed an impairment analysis and determined that the carrying value of the asset group of $171 million, which included cumulative translation losses of $92 million, was greater than its fair value less costs to sell of $29 million. As a result, the Company recognized asset impairment expense of $94 million limited to the carrying value of the long-lived assets. The Company completed the sale of its interest in the Kazakhstan CHP plants in April 2017. Prior to their sale, the plants were reported in the Eurasia SBU reportable segment. See Note 25-Held-for-Sale and Dispositions for further information.
23. INCOME TAXES
U.S. Tax Reform - In 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “TCJA”). The TCJA significantly changed U.S. corporate income tax law. Among other changes effective in 2017, the TCJA required companies to pay a one-time tax on certain unrepatriated earnings of foreign subsidiaries. Many other changes took effect in 2018, including a limit on the deductibility of interest expense and a new regime for taxing certain earnings of foreign subsidiaries.
The Company recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of ASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, the Company’s 2017 financial statements reflected provisional amounts for those impacts for which the accounting under ASC 740 was incomplete, but a reasonable estimate could be determined. As of December 31, 2018, the Company's accounting for the initial impacts of the TCJA was complete under SAB 118.
For the year ended December 31, 2018 the Company increased its estimate of the one-time transition tax by $194 million to $869 million. The estimated tax expense recognized for the year ended December 31, 2017 relating to the remeasurement of deferred tax assets and liabilities from an income tax rate of 35% to 21%, decreased $77 million, resulting in a total remeasurement benefit of $38 million.
In 2019, the U.S. Treasury issued final regulations related to the one-time transition tax which further amended the guidance of previously proposed regulations. As a result, $17 million of tax benefit was recorded in 2019, decreasing the total one-time transition tax to $852 million. This impact was partially offset by $7 million of deferred tax remeasurement expense, decreasing the total remeasurement benefit to $31 million.
Argentine Tax Reform - In December 2017, the Argentine government enacted reforms to its income tax laws that resulted in a decrease to statutory income tax rates for our Argentine businesses from 35% to 30% in 2018-2019 and to 25% for 2020 and future years. The impact of remeasuring deferred taxes to account for the enacted change in future applicable income tax rates was recognized as income tax benefit in the fourth quarter of 2017, resulting in a decrease of $21 million to consolidated income tax expense. In December 2019, the Argentine government delayed certain impacts of the 2017 reform. The corporate income tax rate for 2020 and 2021 will remain at 30%, reducing to 25% only from 2022. The impact of remeasuring deferred taxes for this latest change to enacted income tax rates was recognized as income tax expense of $4 million in the fourth quarter of 2019.
170 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Income Tax Provision - The following table summarizes the expense for income taxes on continuing operations for the periods indicated (in millions):
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:
For 2019, the 12% taxes on foreign earnings item includes $19 million of tax benefit associated with the Company's equity investment in Guacolda. Included in the 2019 change in tax law amount of (1)% are the downward adjustments to the U.S. one-time transition tax expense and deferred tax remeasurement benefit resulting from the issuance of the final regulations in 2019, offset by the impact of deferred tax remeasurement expense related to the December 2019 Argentina tax law change.
For 2018, the 6% change in tax law item relates primarily to changes in estimate under SAB 118 of the impacts of adoption of the TCJA. The Company recognized tax expense of $194 million related to revised estimates of the one-time transition tax in accordance with proposed regulations issued by the U.S. Treasury in 2018. The adjustment was due in large part to the approach the proposed regulations adopted to determine the fair value of our interests in publicly traded subsidiaries. The Company also recognized tax benefit of $77 million related to revised estimates of deferred tax remeasurement. Included in the 9% taxes on foreign earnings item is $124 million of U.S. GILTI tax expense related to foreign subsidiaries, including the sale of our interest in Masinloc.
For 2017, the 90% change in tax law item relates primarily to the impact of U.S. and Argentine tax reform. The impact of the U.S one-time transition tax and remeasurement of deferred taxes represents 88% and 5%, respectively, which is partially offset by the tax benefit resulting from Argentine tax reform representing 3%.
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 the periods indicated (in millions):
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.
171 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
As of December 31, 2019, the Company had federal net operating loss carryforwards for tax return purposes of approximately $0.8 billion expiring in years 2033 to 2036. The Company also had federal general business tax credit carryforwards of approximately $23 million expiring primarily from 2021 to 2039, and federal alternative minimum tax credits of approximately $8 million that may be fully recovered by 2021 under the TCJA. Additionally, the Company had state net operating loss carryforwards as of December 31, 2019 of approximately $6.9 billion expiring primarily in years 2020 to 2039. As of December 31, 2019, the Company had foreign net operating loss carryforwards of approximately $2.7 billion that expire at various times beginning in 2020 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $14 million, $12 million of which expire in 2021.
Valuation allowances decreased $44 million during 2019 to $824 million at December 31, 2019. This net decrease was primarily the result of valuation allowance activity at certain U.S. states.
Valuation allowances decreased $120 million during 2018 to $868 million at December 31, 2018. This net decrease was primarily the result of valuation allowance activity at certain of our Brazil subsidiaries and U.S. states.
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 following table summarizes deferred tax assets and liabilities, as of the periods indicated (in millions):
The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the U.S. Except for the one-time transition tax in the U.S., no taxes have been recorded with respect to our indefinitely reinvested 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 foreign withholding and state income taxes. Under the TCJA, future distributions from foreign subsidiaries will generally be subject to a federal dividends received deduction in the U.S. As of December 31, 2019, the cumulative amount of U.S. GAAP foreign un-remitted earnings upon which additional income taxes have not been provided is approximately $4 billion. 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 $26 million, $35 million and $26 million for the years ended December 31, 2019, 2018 and 2017, respectively. The per share effect of these benefits after noncontrolling interests was $0.02, $0.04 and $0.03 for the years ended December 31, 2019, 2018 and 2017, respectively. Included in the Company's income tax benefits is the benefit related to our operations in Vietnam, which is estimated to be $13 million, $19 million and $13 million for the years ended December 31, 2019, 2018 and 2017, respectively. The per share effect of these benefits related to our operations in Vietnam after noncontrolling interest was $0.01, $0.01 and $0.01 for the years ended December 31, 2019, 2018 and 2017, respectively.
The following table shows the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and noncontrolling interests, for the periods indicated (in millions):
172 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Uncertain Tax Positions - Uncertain tax positions have been classified as noncurrent income tax liabilities unless they are 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. The following table shows the total amount of gross accrued income taxes related to interest and penalties included in the Consolidated Balance Sheets for the periods indicated (in millions):
The following table shows the expense/(benefit) related to interest and penalties on unrecognized tax benefits for the periods indicated (in millions):
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, 2019, 2018 and 2017, the total amount of unrecognized tax benefits was $465 million, $463 million and $348 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2019, 2018 and 2017 is $448 million, $446 million and $332 million, respectively, of which $33 million, $33 million and $29 million, respectively, would be in the form of tax attributes that would warrant a full valuation allowance. Further, the total amount of unrecognized tax benefit that would benefit the effective tax rate as of 2019 would be reduced by approximately $161 million of tax expense related to remeasurement from 35% to 21%.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2019 is estimated to be between $0 million and $10 million, primarily relating to statute of limitation lapses and tax exam settlements.
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the periods indicated (in millions):
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
173 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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, 2019. Our effective tax rate and net income in any given future period could therefore be materially impacted.
24. DISCONTINUED OPERATIONS
Due to a portfolio evaluation in the first half of 2016, management decided to pursue a strategic shift to reduce the Company's exposure to the Brazilian distribution market.
Eletropaulo - In November 2017, Eletropaulo converted its preferred shares into ordinary shares and transitioned the listing of those shares to the Novo Mercado, which is a listing segment of the Brazilian stock exchange with the highest standards of corporate governance. Upon conversion of the preferred shares into ordinary shares, AES no longer controlled Eletropaulo, but maintained significant influence over the business. As a result, the Company deconsolidated Eletropaulo. After deconsolidation, the Company's 17% ownership interest was reflected as an equity method investment. The Company recorded an after-tax loss on deconsolidation of $611 million, which primarily consisted of $455 million related to cumulative translation losses and $243 million related to pension losses reclassified from AOCL.
In December 2017, all remaining criteria were met for Eletropaulo to qualify as a discontinued operation. Therefore, its results of operations and financial position were reported as such in the consolidated financial statements for all periods presented.
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo through a bidding process hosted by the Brazilian securities regulator, CVM. Gross proceeds of $340 million were received at our subsidiary in Brazil, subject to the payment of taxes. Upon disposal of Eletropaulo, the Company recorded a pre-tax gain on sale of $243 million (after-tax $199 million).
Excluding the gain on sale, Eletropaulo's pre-tax loss attributable to AES was immaterial for the year ended December 31, 2018. Eletropaulo's pre-tax loss attributable to AES, including the loss on deconsolidation, for the year ended December 31, 2017 was $633 million. Prior to its classification as discontinued operations, Eletropaulo was reported in the South America SBU reportable segment.
Borsod - In 2011, Borsod, which held two coal and biomass-fired generation plants in Hungary, filed for liquidation and was deconsolidated with its historical operating results reflected in discontinued operations under prior accounting guidance. In October 2018, the liquidation was completed and the Company recognized a deferred gain of $26 million, primarily comprised of a $20 million write-off of cumulative translation balances. Prior to its liquidation, Borsod was reported in the Eurasia SBU reportable segment.
174 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Excluding the gain on sale of Eletropaulo and the deferred gain on liquidation of Borsod, income from discontinued operations and cash flows from operating and investing activities of discontinued operations were immaterial for the year ended December 31, 2018.
The following table summarizes the major line items constituting loss from discontinued operations for the period indicated (in millions):
_____________________________
(1)
Includes a loss contingency recognized by our equity method investment in discontinued operations.
The following table summarizes the operating and investing cash flows from discontinued operations for the period indicated (in millions):
25. HELD-FOR-SALE AND DISPOSITIONS
Held-for-Sale
Jordan - In February 2019, the Company entered into an agreement to sell its 36% ownership interest in two generation plants, IPP1 and IPP4, and a solar plant in Jordan for $86 million, subject to customary post-closing adjustments, plus capital contributions to the solar project of approximately $5 million. The sale of IPP1 and IPP4 is expected to close in the first half of 2020 and the sale of the solar plant is expected to close in the second half of 2020. As of December 31, 2019, the generation plants and solar plant were classified as held-for-sale, but did not meet the criteria to be reported as discontinued operations. On a consolidated basis, the carrying value of the plants held-for-sale as of December 31, 2019 was $153 million. Pre-tax income attributable to AES was $19 million, $10 million and $11 million for the years ended December 31, 2019, 2018 and 2017, respectively. Jordan is reported in the Eurasia SBU reportable segment.
Redondo Beach - In October 2018, the Company entered into an agreement to sell land held by AES Redondo Beach, a gas-fired generating facility in California. The sale is expected to close by the end of the first quarter of 2020. As of December 31, 2019, the $24 million carrying value of the land held by Redondo Beach was classified as held-for-sale. Redondo Beach is reported in the US and Utilities SBU reportable segment.
Dispositions
Stuart and Killen - In December 2019, DPL completed the transfer of the co-owned Stuart coal-fired and diesel-fired generating units and the Killen coal-fired generating unit and combustion turbine retired in May 2018, including the associated environmental liabilities. The transfer resulted in cash expenditures of $51 million and a gain on disposal of $20 million. Prior to their transfer, Stuart and Killen were reported in the US and Utilities SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
Kilroot and Ballylumford - In June 2019, the Company completed the sale of its entire interest in the Kilroot coal and oil-fired plant and energy storage facility and the Ballylumford gas-fired plant in the United Kingdom for $118 million, subject to customary post-closing adjustments, resulting in a pre-tax loss on sale of $33 million primarily due to the write-off of cumulative translation adjustments and accumulated other comprehensive income balances. The sale did not meet the criteria to be reported as discontinued operations. Prior to the sale, Kilroot and Ballylumford were reported in the Eurasia SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
175 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
Shady Point - In May 2019, the Company completed the sale of Shady Point, a U.S. coal-fired generating facility, for $29 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Shady Point was reported in the US and Utilities SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
CTNG - In December 2018, AES Gener completed the sale of CTNG, an entity that holds transmission lines in Chile, for $225 million, resulting in a pre-tax gain on sale of $126 million after post-closing adjustments. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, CTNG was reported in the South America SBU reportable segment.
Electrica Santiago - In May 2018, AES Gener completed the sale of Electrica Santiago for total consideration of $287 million, resulting in a final pre-tax gain on sale of $70 million after post-closing adjustments. Electrica Santiago consisted of four gas and diesel-fired generation plants in Chile. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Electrica Santiago was reported in the South America SBU reportable segment.
Masinloc - In March 2018, the Company completed the sale of its entire 51% equity interest in Masinloc for cash proceeds of $1.05 billion, resulting in a pre-tax gain on sale of $772 million after post-closing adjustments, subject to U.S. income tax. Masinloc consisted of a coal-fired generation plant in operation, a coal-fired generation plant under construction and an energy storage facility all located in the Philippines. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Masinloc was reported in the Eurasia SBU reportable segment.
In 2014, the Company completed the sale of 45% of its ownership interest in Masinloc for $436 million, including $23 million of consideration that was contingent upon the achievement of certain tax restructuring efficiencies. In December 2017, the related contingency expired and the $23 million of contingent consideration was recognized as a gain in Gain (loss) on disposal and sale of business interests in the Consolidated Statement of Operations.
DPL peaker assets - In March 2018, DPL completed the sale of six of its combustion turbine and diesel-fired generation facilities and related assets ("DPL peaker assets") for total proceeds of $239 million, resulting in a loss on sale of $2 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the DPL peaker assets were reported in the US and Utilities SBU reportable segment.
Beckjord facility - In February 2018, DPL transferred its interest in Beckjord, a coal-fired generation facility retired in 2014, including its obligations to remediate the facility and its site. The transfer resulted in cash expenditures of $15 million, inclusive of disposal charges, and a loss on disposal of $12 million. Prior to the transfer, Beckjord was reported in the US and Utilities SBU reportable segment.
Advancion Energy Storage - In January 2018, the Company deconsolidated the AES Advancion energy storage development business and contributed it to the Fluence joint venture, resulting in a gain on sale of $23 million. See Note 8-Investments in and Advances to Affiliates for further discussion. Prior to the transfer, the AES Advancion energy storage development business was reported as part of Corporate and Other.
Zimmer and Miami Fort - In December 2017, DPL and AES Ohio Generation completed the sale of Zimmer and Miami Fort, two coal-fired generating plants, for net proceeds of $70 million, resulting in a gain on sale of $13 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, Zimmer and Miami Fort were reported in the US and Utilities SBU reportable segment.
Kazakhstan Hydroelectric - Affiliates of the Company (the “Affiliates”) previously operated Shulbinsk HPP and Ust-Kamenogorsk HPP (the “HPPs”), two hydroelectric plants in Kazakhstan, under a concession agreement with the Republic of Kazakhstan (“RoK”). In April 2017, the RoK initiated the process to transfer these plants back to the RoK. The RoK indicated that arbitration would be necessary to determine the correct Return Share Transfer Payment ("RST") and, rather than paying the Affiliates, deposited the RST into an escrow account. In exchange, the Affiliates transferred 100% of the shares in the HPPs to the RoK, under protest and with a full reservation of rights. The Company recorded a loss on disposal of $33 million in the fourth quarter of 2017. In February 2018, the Affiliates initiated the arbitration process in international court to recover at least $75 million of the RST placed in escrow, based on the September 30, 2017 RST calculation. As of December 31, 2019, the arbitration proceedings are ongoing, and additional losses are not considered probable at this time. However, additional losses may be incurred if some or all of the disputed consideration is not paid by the RoK via a mutually acceptable settlement, or
176 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
upon any unfavorable decision rendered by the arbiter. The transfer did not meet the criteria to be reported as discontinued operations. Prior to their transfer, the Kazakhstan HPPs were reported in the Eurasia SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
Kazakhstan CHPs - In April 2017, the Company completed the sale of Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan, for net proceeds of $24 million. The Company recognized a pre-tax loss on sale of $49 million, primarily related to cumulative translation losses. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the Kazakhstan CHP plants were reported in the Eurasia SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
Excluding any impairment charge or gain/loss on sale, pre-tax income (loss) attributable to AES of disposed businesses was as follows (in millions):
_____________________________
(1)
After the retirement of Stuart and Killen in 2018, the Company entered into contracts to buy back all open capacity years for the plants at prices lower than the PJM capacity revenue prices. As such, the Company continued to earn capacity margin until the plants were transferred in December 2019.
(2)
Reductions in the asset retirement obligations for ash ponds and landfills at Stuart and Killen in 2018 resulted in a $32 million reduction to cost of sales. See Note 4-Asset Retirement Obligations for further information.
26. ACQUISITIONS
Los Cururos - In November 2019, AES Gener completed the acquisition of the Los Cururos wind farm and transmission lines in Chile from EPM Chile S.A. for total consideration of $143 million, including $5 million in working capital adjustments paid in the first quarter of 2020. The transaction was accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Any differences arising from post-closing adjustments will be allocated accordingly. Los Cururos is reported in the South America SBU reportable segment.
Distributed Energy - In December 2018, Distributed Energy acquired the outstanding noncontrolling interest in a partnership holding various solar projects from its tax equity partner for $23 million of consideration in a non-cash transaction through the assumption of debt, increasing the Company's ownership to 100%. The partnership was previously classified as an equity method investment. The transaction was accounted for as an asset acquisition, therefore the Company remeasured the equity investment at fair value and recognized a loss of $5 million in Other expense in the Consolidated Statement of Operations. The fair value of the investment, along with the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Distributed Energy is reported in the US and Utilities SBU reportable segment.
Oahu - In November 2018, AES Oahu amended a 2017 agreement to acquire 100% of Na Pua Makani Power Partners, a partnership designed to develop and hold a wind project in Hawaii. The fair value of the initial consideration was $53 million, of which $48 million was contingent on meeting predefined development milestones. The transaction was accounted for as an acquisition of a variable interest entity that did not meet the definition of a business, therefore the assets acquired and liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration. As a result of the amendment, the Company paid $11 million in 2018 and the contingent consideration was reduced to $5 million, resulting in a $32 million gain on remeasurement of contingent consideration recorded in Other income in the Consolidated Statement of Operations. AES Oahu is reported in the US and Utilities SBU reportable segment.
Guaimbê Solar Complex - In September 2018, AES Tietê completed the acquisition of the Guaimbê Solar Complex (“Guaimbê”) from Cobra do Brasil for $152 million, comprised of the exchange of $119 million of non-convertible debentures in project financing and additional cash consideration of $33 million. The transaction was
177 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Guaimbê is reported in the South America SBU reportable segment.
Alto Sertão II - In August 2017, the Company completed the acquisition of the Alto Sertão II Wind Complex (“Alto Sertão II”) from Renova Energia S.A. for $179 million, plus the assumption of $346 million of non-recourse debt. At closing, the Company made a cash payment of $143 million, which excluded holdbacks related to indemnifications. In September 2018, an additional $12 million was paid to settle a portion of the remaining indemnification liability. In the first quarter of 2018, the Company finalized the purchase price allocation related to the acquisition of Alto Sertão II. There were no significant adjustments made to the preliminary purchase price allocation recorded in the third quarter of 2017 when the acquisition was completed. The assets acquired and liabilities assumed at the acquisition date were recorded at fair value, including a contingent liability for earn-out payments of $18 million, based on the final purchase price allocation at March 31, 2018. Subsequent changes to the fair value of the earn-out payments will be reflected in earnings. Alto Sertão II is reported in the South America SBU reportable segment.
27. 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 RSUs and stock options. The effect of such potential common stock is computed using the treasury stock method.
The following table is 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, 2019, 2018 and 2017, where income represents the numerator and weighted-average shares represent the denominator.
The calculation of diluted earnings per share excluded stock awards which would be anti-dilutive. The calculation of diluted earnings per share excluded 2 million and 7 million stock awards outstanding for the years ended December 31, 2018 and 2017, respectively, that could potentially dilute basic earnings per share in the future.
For the year ended December 31, 2017, the calculation of diluted earnings per share also excluded 4 million outstanding restricted stock units that could potentially dilute earnings per share in the future, because their impact would be anti-dilutive given the loss from continuing operations. Had the Company generated income, 2 million potential shares of common stock related to the restricted stock units would have been included in diluted weighted-average shares outstanding.
28. RISKS AND UNCERTAINTIES
AES is a diversified power generation and utility company organized into four market-oriented SBUs. See additional discussion of the Company's principal markets in Note 18-Segments and Geographic Information. Within our four 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 comprises 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, solar, and energy storage.
Operating and Economic Risks - The Company operates in several developing economies where macroeconomic conditions are typically more volatile than developed economies. Deteriorating market conditions and evolving industry expectations to transition away from fossil fuel sources for generation expose the Company to
178 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
the risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets, and potential changes in the estimated useful lives of our coal-fired generation assets. 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 an investment grade rating from Fitch of BBB-, and a below-investment grade rating from Standard & Poor's of BB+ and Moody's of Ba1. This could affect the Company's ability to finance new and/or existing development projects at competitive interest rates. As of December 31, 2019, the Company had $1 billion of unrestricted cash and cash equivalents.
During 2019, 68% of our revenue was generated outside the U.S. 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 solar panels, wind turbines, coal, oil, gas, or other raw materials required by our generation businesses to operate;
•
threatened or consummated expropriation or nationalization of our assets by foreign governments;
•
unwillingness of governments, government agencies, similar organizations, or other counterparties to honor their 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;
•
potentially adverse tax consequences of operating in multiple jurisdictions; and
•
difficulties in enforcing our contractual rights, enforcing judgments, or obtaining a just result in local 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. 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;
179 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
•
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.
Goodwill - The Company considers a reporting unit at risk of impairment when its fair value does not exceed its carrying amount by more than 10%. During the annual goodwill impairment test performed as of October 1, 2019, the Company determined that the fair value of its Gener reporting unit exceeded its carrying value by 3%. Therefore, Gener's $868 million goodwill balance was considered to be "at risk" as of December 31, 2019, largely due to the Chilean Government's announcement to phase out coal generation by 2040, and a decline in long-term energy prices.
The Company monitors its reporting units at risk of impairment for interim impairment indicators, and believes that the estimates and assumptions used in the calculations are reasonable as of December 31, 2019. Should the fair value of any of the Company’s reporting units fall below its carrying amount because of reduced operating performance, market declines, changes in the discount rate, regulatory changes, or other adverse conditions, goodwill impairment charges may be necessary in future periods.
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 the USD and the following currencies could create significant fluctuations in earnings and cash flows: the Argentine peso, the Brazilian real, the Chilean peso, the Colombian peso, the Dominican Republic peso, the Euro, the Indian rupee, and the Mexican peso.
Argentina - In September 2019, currency controls were established by the Argentine government in order to control the devaluation of the Argentine peso and keep Argentine central bank reserves at acceptable levels. Restrictions on the flow of capital have limited the availability of international credit, and economic conditions in Argentina have further deteriorated, triggering additional devaluation of the Argentine peso and a deterioration of the country’s risk profile.
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 2019, 2018 or 2017.
The cash flows and results of operations of our businesses depend on the credit quality of our customers and the continued ability of our 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.
29. RELATED PARTY TRANSACTIONS
Certain of our businesses in Panama and the Dominican Republic 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 (in millions):
180 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
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 (in millions):
_____________________________
(1)
Includes $1.1 billion of debt to Mong Duong Finance Holdings B.V., an SPV accounted for as an equity affiliate as of December 31, 2019 (See Note 11-Debt); $415 million and $382 million of debt to Banco General S.A., a bank in Panama where our minority partner in Colon is part of its board of directors as of December 31, 2019 and 2018, respectively; and $287 million and $165 million of debt to Strabag, our EPC contractor and minority partner in Alto Maipo as of December 31, 2019 and 2018, respectively.
30. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data - The following tables summarize the unaudited quarterly Condensed Consolidated Statements of Operations for the Company for 2019 and 2018 (amounts in millions, except per share data). 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.
181 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2019, 2018, and 2017
_____________________________
(1)
Includes pre-tax impairment expense of $116 million and $69 million, in the second and fourth quarters of 2019, respectively (See Note 22-Asset Impairment Expense), other-than-temporary impairment of OPGC of $92 million and net equity in losses of affiliates, primarily at Guacolda, of $175 million, in the fourth quarter of 2019 (See Note 8-Investments in and Advances to Affiliates).
(2)
Includes pre-tax gains on sales of business interests of $788 million, $89 million and $128 million, in the first, second and fourth quarters of 2018, respectively, and pre-tax losses of $21 million in the third quarter of 2018 (See Note 25-Held-for-Sale and Dispositions), pre-tax impairment expense of $92 million, $74 million and $42 million, in the second, third and fourth quarters of 2018, respectively (See Note 22-Asset Impairment Expense), other-than-temporary impairment of Guacolda of $144 million in the fourth quarter of 2018 (See Note 8-Investments in and Advances to Affiliates), SAB 118 charges to finalize the provisional estimate of one-time transition tax on foreign earnings of $33 million and $161 million in the third and fourth quarters of 2018, respectively, and a SAB 118 income tax benefit to finalize the provisional estimate of remeasurement of deferred tax assets and liabilities to the lower corporate tax rate of $77 million in the fourth quarter of 2018 (See Note 23-Income Taxes).
(3)
Includes gain on sale of Eletropaulo of $199 million in the second quarter of 2018 (See Note 24-Discontinued Operations).

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

ITEM 9A - CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange Act") is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to the 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, 2019, 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
182 | 2019 Annual Report
•
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, 2019. 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, 2019.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2019, 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, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
183 | 2019 Annual Report
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of The AES Corporation:
Opinion on Internal Control over Financial Reporting
We have audited The AES Corporation’s internal control over financial reporting as of December 31, 2019, 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). In our opinion, The AES Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “financial statements”), and our report dated February 27, 2020, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting 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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control Over Financial Reporting
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.
/s/ Ernst & Young LLP
Tysons, Virginia
February 27, 2020
184 | 2019 Annual Report

ITEM 9B - OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.
185 | 2019 Annual Report
PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS
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 2020 Annual Meeting of Stockholders which the Registrant expects will be filed on or around March 6, 2020 (the "2020 Proxy Statement"):
•
information regarding the directors required by this item found under the heading Board of Directors;
•
information regarding AES' Code of Ethics found under the heading Additional Governance Matters - 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 Additional Governance Matters - Other Governance Information - Section 16(a) Beneficial Ownership Reporting Compliance; and
•
information regarding AES' Financial Audit Committee found under the heading Board and Committee Governance Matters - Financial Audit Committee (the “Audit Committee”).
Certain information regarding executive officers required by this Item is presented 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 2020 Proxy Statement and is herein incorporated by reference.

ITEM 11 - EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 402 of Regulation S-K is contained in the 2020 Proxy Statement under "Director Compensation" and "Executive Compensation" (excluding the information under the caption “Report of the Compensation Committee”) and is incorporated herein by reference.
The information required by Item 407(e)(5) of Regulation S-K is contained under the caption “Report of the Compensation Committee Report” of the Proxy Statement. Such information shall not be deemed to be “filed.”

ITEM 12 - SECURITY OWNERSHIP
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
(a)
Security Ownership of Certain Beneficial Owners and Management.
See the information contained under the heading Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers of the 2020 Proxy Statement, which information is incorporated herein by reference.
(b)
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, 2019:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2019)
_____________________________
(1)
The following equity compensation plans have been approved by The AES Corporation'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' stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 38,000,000. In 2015, an additional amendment to the Plan to provide an additional 7,750,000 shares was approved by AES' stockholders, bringing the total authorized shares to 45,750,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $12.54 (excluding performance stock units, restricted stock units and director stock units), with 13,964,029 shares available for future issuance.
186 | 2019 Annual Report
(B)
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 142,811 shares is not included in Column (c) above.
(2)
Includes 3,214,738 (of which 477,532 are vested and 2,737,206 are unvested) shares underlying PSU and RSU awards (assuming 2017 and 2018 PSUs median performance and 2019 PSU maximum performance), 1,654,985 shares underlying Director stock unit awards, and 3,177,764 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 8,047,487 shares.

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information regarding related party transactions required by this item is included in the 2020 Proxy Statement found under the headings Transactions with Related Persons and Board and Committee Governance Matters and are incorporated herein by reference.

ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item 14 is included in the 2020 Proxy Statement under the headings Information Regarding The Independent Registered Public Accounting Firm, Audit Fees, Audit Related Fees, and Pre-Approval Policies and Procedures and is incorporated herein by reference.
187 | 2019 Annual Report
PART IV

ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE
(a)
Financial Statements.
Financial Statements and Schedules:
Page
Consolidated Balance Sheets as of December 31, 2019 and 2018
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2019, 2018 and 2017
Consolidated Statements of Changes in Equity for the years ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
Schedules
S-2-S-7
(b)
Exhibits.
3.1
Sixth Restated Certificate of Incorporation of The AES Corporation is incorporated herein by reference to Exhibit 3.1 of the Company's Form 10-K for the year ended December 31, 2008.
3.2
By-Laws of The AES Corporation, as amended and incorporated herein by reference to Exhibit 3.1 of the Company's Form 8-K filed on December 10, 2019.
There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request. Since these documents are not required filings under Item 601 of Regulation S-K, the Company has elected to file certain of these documents as Exhibits 4.(a)-4.(i).
4.(a)
Senior Indenture, dated as of December 8, 1998, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated herein by reference to Exhibit 4.01 of the Company's Form 8-K filed on December 11, 1998 (SEC File No. 001-12291).
4.(b)
Ninth Supplemental Indenture, dated as of April 3, 2003, between The AES Corporation and Wells Fargo Bank, National Association (as successor by consolidation to Wells Fargo Bank Minnesota, National Association) is incorporated herein by reference to Exhibit 4.6 of the Company's Form S-4 filed on December 7, 2007.
4.(c)
Sixteenth Supplemental Indenture, dated April 30, 2013, between The AES Corporation and Wells Fargo Bank, N.A., as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on April 30, 2013 (SEC File No. 001-12291).
4.(d)
Seventeenth Supplemental Indenture, dated March 7, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 7, 2014.
4.(e)
Nineteenth Supplemental Indenture, dated April 6, 2015, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on April 6, 2015.
4.(f)
Twentieth Supplemental Indenture, dated May 25, 2016, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 25, 2016.
4.(g)
Twenty-First Supplemental Indenture, dated August 28, 2017, between The AES Corporation and Deutsche Bank Trust Company, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on August 28, 2017.
4.(h)
Twenty-Second Supplemental Indenture, dated March 15, 2018, between The AES Corporation and Deutsche Bank Trust Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 15, 2018.
4.(i)
Twenty-Fourth Supplemental Indenture, dated March 15, 2018 between The AES Corporation and Deutsche Bank Trust Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 21, 2018.
10.1
The AES Corporation Profit Sharing and Stock Ownership Plan are incorporated herein by reference to Exhibit 4(c)(1) of the Registration Statement on Form S-8 (Registration No. 33-49262) filed on July 2, 1992. (P)
10.2
The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 of the Company's Form 10-K for the year ended December 31, 1995 (SEC File No. 00019281). (P)
10.3
Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 of the Registration Statement on Form S-1 (Registration No. 33-40483). (P)
10.4
Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 of Amendment No. 1 to the Registration Statement on Form S-1 (Registration No. 33-40483). (P)
10.5
Deferred Compensation Plan for Directors, as amended and restated, on February 17, 2012 is incorporated herein by reference to Exhibit 10.5 of the Company's Form 10-K for the year ended December 31, 2012.
10.6
The AES Corporation Stock Option Plan for Outside Directors, as amended and restated, on December 7, 2007 is incorporated herein by reference to Exhibit 10.6 of the Company's Form 10-K for the year ended December 31, 2012.
10.7
The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.63 of the Company's Form 10-K for the year ended December 31, 1994 (SEC File No. 00019281). (P)
10.7A
Amendment to The AES Corporation Supplemental Retirement Plan, dated March 13, 2008 is incorporated herein by reference to Exhibit 10.9.A of the Company's Form 10-K for the year ended December 31, 2007.
188 | 2019 Annual Report
10.8
The AES Corporation 2001 Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company's Form 10-K for the year ended December 31, 2000 (SEC File No. 001-12291).
10.9
Second Amended and Restated Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.13 of the Company's Form 10-K for the year ended December 31, 2000 (SEC File No. 001-12291).
10.10
The AES Corporation 2001 Non-Officer Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company's Form 10-K for the year ended December 31, 2002 (SEC File No. 001-12291).
10.10A
Amendment to the 2001 Stock Option Plan and 2001 Non-Officer Stock Option Plan, dated March 13, 2008 is incorporated herein by reference to Exhibit 10.12A of the Company's Form 10-K for the year ended December 31, 2007.
10.11
The AES Corporation 2003 Long Term Compensation Plan, as Amended and Restated, dated April 23, 2015, is incorporated herein by reference to Exhibit 99.1 of the Company's Form 8-K filed on April 23, 2015.
10.12
Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Outside Directors) is incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on April 27, 2010.
10.13
Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.13 of the Company's Form 10-K for the year ended December 31, 2015.
10.14
Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (filed herewith).
10.15
Form of AES Performance Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.15 of the Company's Form 10-K for the year ended December 31, 2015.
10.16
Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.4 of the Company's Form 10-Q for the quarter ended June 30, 2015.
10.17
Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (filed herewith).
10.18
The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, dated December 29, 2008 is incorporated herein by reference to Exhibit 10.15 of the Company's Form 10-K for the year ended December 31, 2008.
10.18A
Amendment to The AES Corporation Restoration Supplemental Retirement Plan, dated December 9, 2011 is incorporated herein by reference to Exhibit 10.17A of the Company's Form 10-K for the year ended December 31, 2012.
10.19
The AES Corporation International Retirement Plan, as amended and restated on December 29, 2008 is incorporated herein by reference to Exhibit 10.16 of the Company's Form 10-K for the year ended December 31, 2008.
10.19A
Amendment to The AES Corporation International Retirement Plan, dated December 9, 2011 is incorporated herein by reference to Exhibit 10.18A of the Company's Form 10-K for the year ended December 31, 2012.
10.20
The AES Corporation Severance Plan, as amended and restated on August 4, 2017 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter ended June 30, 2017.
10.21
The AES Corporation Amended and Restated Executive Severance Plan dated October 5, 2018 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter ended September 30, 2018.
10.22
The AES Corporation Performance Incentive Plan, as Amended and Restated on April 23, 2015 is incorporated herein by reference to Exhibit 99.2 of the Company's Form 8-K filed on April 23, 2015.
10.23
The AES Corporation Deferred Compensation Program For Directors dated February 17, 2012 is incorporated herein by reference to Exhibit 10.22 of the Company's Form 10-K filed on December 31, 2011.
10.24
Mutual Agreement, between Andrés Gluski and The AES Corporation dated October 7, 2011 is incorporated herein by reference to Exhibit 10.2 of the Company's Form 10-Q for the period ended September 30, 2011.
10.25
Form of Retroactive Consent to Provide for Double-Trigger Change-In-Control Transactions is incorporated herein by reference to Exhibit 10.7 of the Company's Form 10-Q for the period ended June 30, 2015.
10.26
Amendment No. 3, dated as of December 20, 2019, to the Sixth Amended and Restated Credit and Reimbursement Agreement, dated as of July 26, 2013 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 23, 2019.
10.26A
Seventh Amended and Restated Credit and Reimbursement Agreement dated as of December 20, 2019 among The AES Corporation, a Delaware corporation, the Banks listed on the signature pages thereof, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citibank, N.A., Mizuho Bank Ltd. and Crédit Agricole Corporate and Investment Bank, as Joint Lead Arrangers and Joint Book Runners is incorporated herein by reference to Exhibit 10.1.A of the Company's Form 8-K filed on December 23, 2019.
10.27
Collateral Trust Agreement dated as of December 12, 2002 among The AES Corporation, AES International Holdings II, Ltd., Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, an individual trustee is incorporated herein by reference to Exhibit 4.2 of the Company's Form 8-K filed on December 17, 2002 (SEC File No. 001-12291).
10.28
Security Agreement dated as of December 12, 2002 made by The AES Corporation to Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is incorporated herein by reference to Exhibit 4.3 of the Company's Form 8-K filed on December 17, 2002 (SEC File No. 001-12291).
10.29
Credit Agreement dated as of May 24, 2017 among The AES Corporation, as borrower, the bank listed therein and Bank of America, N.A., as administrative agent is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on May 24, 2017.
189 | 2019 Annual Report
10.30
Charge Over Shares dated as of December 12, 2002 between AES International Holdings II, Ltd. and Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is incorporated herein by reference to Exhibit 4.4 of the Company's Form 8-K filed on December 17, 2002 (SEC File No. 001-12291).
10.31
Consulting Agreement by and between The AES Corporation and Brian A. Miller dated February 26, 2018 is incorporated herein by reference to Exhibit 10.33 of the Company's Form 10-K for the year ending December 31, 2017.
21.1
Subsidiaries of The AES Corporation (filed herewith).
23.1
Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP (filed herewith).
Powers of Attorney (filed herewith).
31.1
Rule 13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith).
31.2
Rule 13a-14(a)/15d-14(a) Certification of Gustavo Pimenta (filed herewith).
32.1
Section 1350 Certification of Andrés Gluski (filed herewith).
32.2
Section 1350 Certification of Gustavo Pimenta (filed herewith).
The AES Corporation Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL (Inline Extensible Business Reporting Language): (i) the Cover Page, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Operations, (iv) Consolidated Statements of Comprehensive Income (Loss), (v) Consolidated Statements of Changes in Equity, (vi) Consolidated Statements of Cash Flows, and (vii) Notes to Consolidated Financial Statements. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
(c)
Schedule
Schedule I-Financial Information of Registrant
190 | 2019 Annual Report
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE AES CORPORATION
(Company)
Date:
February 27, 2020
By:
/s/ ANDRÉS GLUSKI
Name:
Andrés Gluski
President, Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
Name
Title
Date
*
President, Chief Executive Officer (Principal Executive Officer) and Director
Andrés Gluski
February 27, 2020
*
Director
Janet G. Davidson
February 27, 2020
*
Director
Charles L. Harrington
February 27, 2020
*
Director
Tarun Khanna
February 27, 2020
*
Director
Holly K. Koeppel
February 27, 2020
*
Director
James H. Miller
February 27, 2020
*
Director
Alain Monié
February 27, 2020
*
Chairman of the Board and Lead Independent Director
John B. Morse
February 27, 2020
*
Director
Moises Naim
February 27, 2020
*
Director
Jeffrey W. Ubben
February 27, 2020
/s/ GUSTAVO PIMENTA
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Gustavo Pimenta
February 27, 2020
/s/ SHERRY L. KOHAN
Vice President and Controller (Principal Accounting Officer)
Sherry L. Kohan
February 27, 2020
*By:
/s/ PAUL L. FREEDMAN
February 27, 2020
Attorney-in-fact
S-1 | 2019 Annual Report
THE AES CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule I-Condensed Financial Information of Registrant
S-2
Schedules other than that listed above are omitted as the information is either not applicable, not required, or has been furnished in the consolidated financial statements or notes thereto included in Item 8 hereof.
See Notes to Schedule I
S-2 | 2019 Annual Report
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
BALANCE SHEETS
See Notes to Schedule I.
S-3 | 2019 Annual Report
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF OPERATIONS
See Notes to Schedule I.
S-4 | 2019 Annual Report
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017
See Notes to Schedule I.
S-5 | 2019 Annual Report
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF CASH FLOWS
See Notes to Schedule I.
S-6 | 2019 Annual Report
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 as well as effects of U.S. tax law reform enacted in 2017.
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 and Secured Notes and Loans Payable ($ in millions)
FUTURE MATURITIES OF RECOURSE DEBT - As of December 31, 2019 scheduled maturities are presented in the following table (in millions):
3. Dividends from Subsidiaries and Affiliates
Cash dividends received from consolidated subsidiaries were $1.0 billion, $1.9 billion and $1.2 billion for the years ended December 31, 2019, 2018, and 2017, respectively. For the years ended December 31, 2019 and 2018, $200 million and $1.2 billion, respectively, of the dividends paid to the Parent Company are derived from the sale of business interests and are classified as an investing activity for cash flow purposes. All other dividends are classified as operating activities. There were no cash dividends received from affiliates accounted for by the equity method for the years ended December 31, 2019, 2018, and 2017.
S-7 | 2019 Annual Report
4. Guarantees and Letters of Credit
GUARANTEES - In connection with certain project financing, acquisitions and dispositions, power purchases 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. These obligations and commitments, excluding those collateralized by letter of credit and other obligations discussed below, were limited as of December 31, 2019 by the terms of the agreements, to an aggregate of approximately $865 million, representing 38 agreements with individual exposures ranging up to $157 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, 2019, the Parent Company had $19 million in letters of credit outstanding under the senior secured credit facility, representing 28 agreements with individual exposures up to $4 million, and $342 million in letters of credit outstanding under the senior unsecured credit facility, representing 11 agreements with individual exposures ranging from $1 million to $296 million. During the year ended December 31, 2019, the Parent Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.

Market Capitalization: 11109338.706027985
1-Year Return: -0.08529257774353027
252-Day Return: $252_day_return