Filed: 24 Feb 21, 7:00pm
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
|☒||ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
For the Fiscal Year Ended December 31, 2020
|☐||TRANSITION REPORT FILED PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
Commission file number 1-12291
THE AES CORPORATION
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction of incorporation or organization)||(I.R.S. Employer Identification No.)|
|4300 Wilson Boulevard|
|(Address of principal executive offices)||(Zip Code)|
|Registrant's telephone number, including area code:||(703)||522-1315|
|Securities registered pursuant to Section 12(b) of the Act:|
|Title of Each Class||Trading Symbol(s)||Name of Each Exchange on Which Registered|
|Common Stock, par value $0.01 per share||AES||New York Stock Exchange|
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
|Large accelerated filer||☒||Accelerated filer||☐||Smaller reporting company||☐||Emerging growth company||☐||Non-accelerated filer||☐|
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2020, the last business day of the Registrant's most recently completed second fiscal quarter (based on the adjusted closing sale price of $14.16 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $9.42 billion.
The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 22, 2021 was 665,479,845.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant's Proxy Statement for its 2021 annual meeting of stockholders are incorporated by reference in Parts II and III
The AES Corporation Fiscal Year 2020 Form 10-K
Table of Contents
|PART IV - ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE|
|1 | 2020 Annual Report|
Glossary of Terms
The following is a list of frequently used terms and abbreviations that appear in the text of this report and have the definitions indicated below:
|Adjusted EPS||Adjusted Earnings Per Share, a non-GAAP measure|
|Adjusted PTC||Adjusted Pre-tax Contribution, a non-GAAP measure of operating performance|
|AES||The Parent Company and its subsidiaries and affiliates|
|AES Brasil||AES Tietê Energia S.A|
|AFUDC||Allowance for Funds Used During Construction|
|ANEEL||Brazilian National Electric Energy Agency|
|AOCL||Accumulated Other Comprehensive Loss|
|ARO||Asset Retirement Obligations|
|ASC||Accounting Standards Codification|
|ASEP||National Authority of Public Services in Panama|
|BACT||Best Available Control Technology|
|BESS||Battery energy storage system|
|BOT||Build, Operate and Transfer|
|CAA||U.S. Clean Air Act|
|CAMMESA||Wholesale Electric Market Administrator in Argentina|
|CCEE||Brazilian Chamber of Electric Energy Commercialization|
|CCGT||Combined Cycle Gas Turbine|
|CCR||Coal Combustion Residuals, which includes bottom ash, fly ash and air pollution control wastes generated at coal-fired generation plant sites|
|CDPQ||La Caisse de dépôt et placement du Quebéc|
|CECL||Current Expected Credit Loss|
|CEO||Chief Executive Officer|
|CFE||Federal Electricity Commission in Mexico|
|CFO||Chief Financial Officer|
|COD||Commercial Operation Date|
|CSAPR||U.S. Cross-State Air Pollution Rule|
|CTNG||Compañia Transmisora del Norte Grande|
|CWA||U.S. Clean Water Act|
|DG Comp||Directorate-General for Competition of the European Commission|
|DMR||Distribution Modernization Rider|
The Dayton Power & Light Company. DP&L is wholly-owned by DPL and also does business as AES Ohio
|DPP||Dominican Power Partners|
|EPA||U.S. Environmental Protection Agency|
|EPC||Engineering, Procurement, and Construction|
|ERCOT||Electric Reliability Council of Texas|
|ESP||Electric Security Plan|
|EURIBOR||Euro Inter Bank Offered Rate|
|EVN||Electricity of Vietnam|
|FERC||U.S. Federal Energy Regulatory Commission|
|FONINVEMEM||Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market in Argentina|
|FPA||U.S. Federal Power Act|
|GAAP||Generally Accepted Accounting Principles in the United States|
|GILTI||Global Intangible Low Taxed Income|
|GSF||Generation Scaling Factor|
|HLBV||Hypothetical Liquidation Book Value|
|IDEM||Indiana Department of Environmental Management|
|IPALCO||IPALCO Enterprises, Inc.|
Indianapolis Power & Light Company, which also does business as AES Indiana
|IPP||Independent Power Producers|
|2 | 2020 Annual Report|
|ISO||Independent System Operator|
|ITC||Investment Tax Credit|
|IURC||Indiana Utility Regulatory Commission|
|LIBOR||London Inter Bank Offered Rate|
|LNG||Liquefied Natural Gas|
|MISO||Midcontinent Independent System Operator, Inc.|
|MMBtu||Million British Thermal Units|
|MRE||Energy Reallocation Mechanism|
|NAAQS||U.S. National Ambient Air Quality Standards|
|NEK||Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria)|
|NERC||North American Electric Reliability Corporation|
|NOV||Notice of Violation|
|NPDES||National Pollutant Discharge Elimination System|
|NSPS||New Source Performance Standards|
|O&M||Operations and Maintenance|
|ONS||National System Operator in Brazil|
|OPGC||Odisha Power Generation Corporation, Ltd.|
|OTC Policy||Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling|
|OVEC||Ohio Valley Electric Corporation, an electric generating company in which DP&L has a 4.9% interest|
|Parent Company||The AES Corporation|
|PCU||Performance Cash Units|
|Pet Coke||Petroleum Coke|
|PJM||PJM Interconnection, LLC|
|PPA||Power Purchase Agreement|
|PREPA||Puerto Rico Electric Power Authority|
|PSD||Prevention of Significant Deterioration|
|PSU||Performance Stock Unit|
|PUCO||The Public Utilities Commission of Ohio|
|PURPA||U.S. Public Utility Regulatory Policies Act|
|QIA||Qatar Investment Authority|
|RSU||Restricted Stock Unit|
|RTO||Regional Transmission Organization|
|SADI||Argentine Interconnected System|
|SBU||Strategic Business Unit|
|SEC||U.S. Securities and Exchange Commission|
|SEET||Significantly Excessive Earnings Test|
|SEN||Sistema Electrico Nacional in Chile|
|SIN||National Interconnected System in Colombia|
|SIP||State Implementation Plan|
|SWRCB||California State Water Resources Board|
|TCJA||Tax Cuts and Jobs Act|
|TDSIC||Transmission, Distribution, and Storage System Improvement Charge|
|USD||United States Dollar|
|VAT||Value Added Tax|
|VIE||Variable Interest Entity|
|Vinacomin||Vietnam National Coal-Mineral Industries Holding Corporation Ltd.|
|3 | 2020 Annual Report|
In this Annual Report the terms “AES,” “the Company,” “us,” or “we” refer to The AES Corporation and all of its subsidiaries and affiliates, collectively. The terms “The AES Corporation” and “Parent Company” refer only to the parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates.
Forward-Looking Information and Risk Factor Summary
In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.
Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
•the economic climate, particularly the state of the economy in the areas in which we operate and the state of the economy in China, which impacts demand for electricity in many of our key markets, including the fact that the global economy faces considerable uncertainty for the foreseeable future, which further increases many of the risks discussed in this Form 10-K;
•changes in inflation, demand for power, interest rates and foreign currency exchange rates, including our ability to hedge our interest rate and foreign currency risk;
•changes in the price of electricity at which our generation businesses sell into the wholesale market and our utility businesses purchase to distribute to their customers, and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk;
•changes in the prices and availability of coal, gas and other fuels (including our ability to have fuel transported to our facilities) and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts;
•changes in and access to the financial markets, particularly changes affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments and other corporate purposes;
•our ability to fulfill our obligations, manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our revolving credit facility and other existing financing obligations;
•our ability to receive funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise;
•changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria;
•our ability to purchase and sell assets at attractive prices and on other attractive terms;
•our ability to compete in markets where we do business;
•our ability to operate power generation, distribution and transmission facilities, including managing availability, outages and equipment failures;
•our ability to manage our operational and maintenance costs and the performance and reliability of our generating plants, including our ability to reduce unscheduled down times;
•our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these agreements;
•variations in weather, especially mild winters and cooler summers in the areas in which we operate, the occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other storms and disasters, wildfires and low levels of wind or sunlight for our wind and solar facilities;
•pandemics, or the future outbreak of any other highly infectious or contagious disease, including the COVID-19 pandemic;
•the performance of our contracts by our contract counterparties, including suppliers or customers;
|4 | 2020 Annual Report|
•severe weather and natural disasters;
•our ability to raise sufficient capital to fund development projects or to successfully execute our development projects;
•the success of our initiatives in renewable energy projects and energy storage projects;
•the availability of government incentives or policies that support the development of renewable energy generation projects;
•our ability to keep up with advances in technology;
•changes in number of customers or in customer usage;
•the operations of our joint ventures and equity method investments that we do not control;
•our ability to achieve reasonable rate treatment in our utility businesses;
•changes in laws, rules and regulations affecting our international businesses, particularly in developing countries;
•changes in laws, rules and regulations affecting our utilities businesses, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities;
•changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business and solar projects, our other renewables projects and our initiatives in GHG reductions and energy storage, including government policies or tax incentives;
•changes in environmental laws, including requirements for reduced emissions, GHG legislation, regulation, and/or treaties and CCR regulation and remediation;
•changes in tax laws, including U.S. tax reform, and challenges to our tax positions;
•the effects of litigation and government and regulatory investigations;
•the performance of our acquisitions;
•our ability to maintain adequate insurance;
•decreases in the value of pension plan assets, increases in pension plan expenses, and our ability to fund defined benefit pension and other postretirement plans at our subsidiaries;
•losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets;
•changes in accounting standards, corporate governance and securities law requirements;
•our ability to maintain effective internal controls over financial reporting;
•our ability to attract and retain talented directors, management and other personnel;
•cyber-attacks and information security breaches; and
These factors, in addition to others described elsewhere in this Form 10-K, including those described under Item 1A.—Risk Factors and in subsequent securities filings, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward-looking information.
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.
ITEM 1. BUSINESS
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 and Item 3.—Legal Proceedings.
|5 | 2020 Annual Report|
Incorporated in 1981, AES is a global energy company accelerating the future of energy. Together with our many stakeholders, we are improving lives by delivering the greener, smarter energy solutions the world needs. Our diverse workforce is committed to continuous innovation and operational excellence, while partnering with our customers on their strategic energy transitions and continuing to meet their energy needs today.
AES is leading the energy transition by investing in sustainable growth and innovative solutions to deliver superior results. We are taking advantage of favorable trends in clean power generation, transmission and distribution, and LNG infrastructure.
Through our presence in key growth markets, we are well-positioned to benefit from the global transition toward a more sustainable power generation mix. Our robust backlog of projects under construction or under signed PPAs continues to increase, driven by our focus on select markets where we can take advantage of our global scale and synergies with our existing businesses. In 2020, we signed long-term PPAs for 3 GW, representing 10% of our existing capacity, and in line with our expectation of signing 2 to 3 GW of new PPAs annually.
We are enhancing some of our current contracts by extending existing PPAs and adding renewable energy. We call this approach Green Blend and Extend. With this strategy, we leverage our existing platforms, contracts and relationships to grow our business, while meeting our customers' energy needs on a reliable and sustainable basis. We are negotiating new long-term renewable PPAs with existing customers, which preserves the value of thermal contracts and creates incremental value with long-term contracted renewables. Customers receive carbon-free energy at less than the marginal cost of thermal power, enabling them to meet their sustainability goals and affordable energy needs. We are executing on this strategy in Chile and Mexico and see significant potential additional opportunities in those markets, as well as in the United States.
We recently merged all of our renewables businesses in the U.S. into one team: AES Clean Energy, representing one of the top renewables growth platforms in the U.S. AES Clean Energy offers its customers an expanded portfolio of innovative solutions based on cutting-edge technologies that are designed to accelerate their energy futures.
We are facilitating access to reliable and affordable cleaner energy through our LNG import terminals, allowing
|6 | 2020 Annual Report|
the displacement of the use of heavy fuel oil and diesel. We have two LNG regasification terminals in Central America and the Caribbean, with a total of 150 TBTU of LNG storage capacity. These terminals were built to supply not only the gas for our co-located combined cycle plants, but also to meet the growing demand for natural gas in the region. In order to meet this demand, we are expanding our capacity in the Dominican Republic by adding a second storage tank with 50 TBTU of additional capacity and we recently completed construction of a pipeline that will transport natural gas from our LNG terminal to several power plants in the country.
We are replicating our success with LNG infrastructure in the Dominican Republic and Panama by developing a similar project, on a larger scale, in Vietnam. This project will have 480 TBTU of LNG storage capacity co-located with 2.2 GW of combined cycle plants. The project will have substantial excess LNG capacity to help meet demand for natural gas in Vietnam and the power plants will have 20-year contracts with the Government of Vietnam.
At our utilities, we are accelerating growth through grid modernization and infrastructure investments to replace outdated networks. In 2020, Indianapolis Power & Light's seven-year $1.2 billion TDSIC plan was approved by the Indiana Utility Regulatory Commission. We see similar growth opportunities at Dayton Power & Light in Ohio, including DP&L's pending Smart Grid Plan.
We are developing and deploying innovative solutions such as battery-based energy storage, digital customer interfaces and energy management. These solutions are scalable and capital light, allowing us to work with our customers to deliver results that meet their requirements.
As a result of executing on our strategy, we have reduced our coal-fired generation to 25% of our total generation volume as of year-end 2020 (based on the portfolio as of year-end, adjusted for any announced asset sales and retirements at that time). We remain on track to further reduce our coal generation to below 10% by year-end 2030.
In 2020, we achieved significant milestones on our strategic objectives, including:
•We completed construction of 2,318 MW of new projects, including:
◦1,299 MW Southland Repowering; and
◦1,019 MW of solar, wind and energy storage globally
•We signed 3,017 MW of renewables and energy storage under long-term PPAs, including:
◦1,180 MW of energy storage, solar and solar plus storage and hydro in the US and El Salvador;
◦1,171 MW of wind and solar at AES Gener in Chile and Colombia;
◦346 MW of wind at AES Brasil;
◦211 MW of wind and solar in Panama and the Dominican Republic; and
◦109 MW of wind in Mexico
•As of December 31, 2020, our backlog of 6,909 MW includes:
◦1,850 MW under construction and coming on-line through 2022; and
◦5,059 MW of renewables signed under long-term PPAs
•The Company has reduced its coal-fired generation to 25% of total generation volume (proforma for asset sales and retirements announced in 2020) and is on track to further reduce its coal-fired generation to less than 10% by year-end 2030
•Our joint venture with Siemens, Fluence, is the global leader in the fast-growing energy storage market, which is expected to increase by 15 to 20 GW annually
◦Fluence has been awarded or delivered 2.4 GW of projects, including 785 MW awarded in 2020
◦In December 2020, the Qatar Investment Authority ("QIA") agreed to invest $125 million in Fluence through a private placement transaction, valuing Fluence at more than $1 billion
|7 | 2020 Annual Report|
•Following our efforts to strengthen our balance sheet, our Parent Company credit rating was upgraded to investment grade (BBB-) by S&P
We currently own and/or operate a generation portfolio of 30,308 MW, including generation from our integrated utility, IPL. Our generation fleet is diversified by fuel type. See discussion below under Fuel Costs.
Performance drivers of our generation businesses include types of electricity sales agreements, plant reliability and flexibility, availability of generation capacity to meet contracted sales, fuel costs, seasonality, weather variations and economic activity, fixed-cost management, and competition.
Contract Sales — Most of our generation businesses sell electricity under medium- or long-term contracts ("contract sales") or under short-term agreements in competitive markets ("short-term sales"). Our medium-term contract sales have terms of two to five years, while our long-term contracts have terms of more than five years.
Contracts requiring fuel to generate energy, such as natural gas or coal, are structured to recover variable costs, including fuel and variable O&M costs, either through direct or indexation-based contractual pass-throughs or tolling arrangements. When the contract does not include a fuel pass-through, we typically hedge fuel costs or enter into fuel supply agreements for a similar contract period (see discussion below under Fuel Costs). These contracts also help us to fund a significant portion of the total capital cost of the project through long-term non-recourse project-level financing.
Certain contracts include capacity payments that cover projected fixed costs of the plant, including fixed O&M expenses, debt service, and a return on capital invested. In addition, most of our contracts require that the majority of the capacity payments be denominated in the currency matching our fixed costs.
Contracts that do not have significant fuel cost or do not contain a capacity payment are structured based on long-term spot prices with some negotiated pass-through costs, allowing us to recover expected fixed and variable costs as well as provide a return on investment.
These contracts are intended to reduce exposure to the volatility of fuel and electricity prices by linking the business's revenues and costs. We generally structure our business to eliminate or reduce foreign exchange risk by matching the currency of revenue and expenses, including fixed costs and debt. Our project debt may consist of both fixed and floating rate debt for which we typically hedge a significant portion of our exposure. Some of our contracted businesses also receive a regulated market-based capacity payment, which is discussed in more detail in the Short-Term Sales section below.
Thus, these contracts, or other related commercial arrangements, significantly mitigate our exposure to changes in power and, as applicable, fuel prices, currency fluctuations and changes in interest rates. In addition, these contracts generally provide for a recovery of our fixed operating expenses and a return on our investment, as long as we operate the plant to the reliability and efficiency standards required in the contract.
Short-Term Sales — Our other generation businesses sell power and ancillary services under short-term contracts with average terms of less than two years, including spot sales, directly in the short-term market or at regulated prices. The short-term markets are typically administered by a system operator to coordinate dispatch. Short-term markets generally operate on merit order dispatch, where the least expensive generation facilities, based upon variable cost or bid price, are dispatched first and the most expensive facilities are dispatched last. The short-term price is typically set at the marginal cost of energy or bid price (the cost of the last plant required to meet system demand). As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity. In addition, many of these wholesale markets include markets for ancillary services to support the reliable operation of the transmission system. Across our portfolio, we provide a wide array of ancillary services, including voltage support, frequency regulation and spinning reserves.
Many of the short-term markets in which we operate include regulated capacity markets. These capacity markets are intended to provide additional revenue based upon availability without reliance on the energy margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand).
|8 | 2020 Annual Report|
Our generating facilities selling in the short-term markets typically receive capacity payments based on their availability in the market.
Plant Reliability and Flexibility — Our contract and short-term sales provide incentives to our generation plants to optimally manage availability, operating efficiency and flexibility. Capacity payments under contract sales are frequently tied to meeting minimum standards. In short-term sales, our plants must be reliable and flexible to capture peak market prices and to maximize market-based revenues. In addition, our flexibility allows us to capture ancillary service revenue while meeting local market needs.
Fuel Costs — For our thermal generation plants, fuel is a significant component of our total cost of generation. For contract sales, we often enter into fuel supply agreements to match the contract period, or we may financially hedge our fuel costs. Some of our contracts include indexation for fuels. In those cases, we seek to match our fuel supply agreements to the indexation. For certain projects, we have tolling arrangements where the power offtaker is responsible for the supply and cost of fuel to our plants.
In short-term sales, we sell power at market prices that are generally reflective of the market cost of fuel at the time, and thus procure fuel supply on a short-term basis, generally designed to match up with our market sales profile. Since fuel price is often the primary determinant for power prices, the economics of projects with short-term sales are often subject to volatility of relative fuel prices. For further information regarding commodity price risk please see Item 7A.—Quantitative and Qualitative Disclosures about Market Risk in this Form 10-K.
37% of the capacity of our generation plants are fueled by renewables, including hydro, solar, wind, energy storage, biomass and landfill gas, which do not have significant fuel costs.
33% of the capacity of our generation plants are fueled by natural gas. Generally, we use gas from local suppliers in each market. A few exceptions to this are AES Gener in Chile, where we purchase imported gas from third parties, and our plants in the Dominican Republic and Panama, where we import LNG to utilize in the local market.
27% of the capacity of our generation fleet is coal-fired. In the U.S., most of our coal-fired plants are supplied from domestic coal. At our non-U.S. generation plants, and at our plants in Hawaii and Puerto Rico, we source coal internationally. Across our fleet, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.
3% of the capacity of our generation fleet utilizes pet coke, diesel or oil for fuel. We source oil and diesel locally at prices linked to international markets. We largely source pet coke from Mexico and the U.S.
Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal weather patterns and, therefore, operating margin is not generated evenly throughout the year. Additionally, weather variations, including temperature, solar and wind resources, and hydrological conditions, may also have an impact on generation output at our renewable generation facilities. In competitive markets for power, local economic activity can also have an impact on power demand and short-term prices for power.
Fixed-Cost Management — In our businesses with long-term contracts, the majority of the fixed O&M costs are recovered through the capacity payment. However, for all generation businesses, managing fixed costs and reducing them over time is a driver of business performance.
Competition — For our businesses with medium- or long-term contracts, there is limited competition during the term of the contract. For short-term sales, plant dispatch and the price of electricity are determined by market competition and local dispatch and reliability rules.
AES' six utility businesses distribute power to 2.5 million people in two countries. AES' two utilities in the U.S. also include generation capacity totaling 3,973 MW. Our utility businesses consist of IPL and DP&L in the U.S. and four utilities in El Salvador.
IPL, our fully integrated utility, and DP&L, our transmission and distribution regulated utility, operate as the sole distributors of electricity within their respective jurisdictions. IPL owns and operates all of the facilities necessary to generate, transmit and distribute electricity. DP&L owns and operates all of the facilities necessary to transmit and distribute electricity. At our distribution business in El Salvador, we face limited competition due to significant barriers to enter the market. According to El Salvador's regulation, large regulated customers have the option of becoming unregulated users and requesting service directly from generation or commercialization agents.
|9 | 2020 Annual Report|
In general, our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. Key performance drivers for utilities include the regulated rate of return and tariff, seasonality, weather variations, economic activity and reliability of service. Revenue from utilities is classified as regulated on the Consolidated Statements of Operations.
Regulated Rate of Return and Tariff — 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 and establishes service standards that we are required to meet.
Our utilities are generally permitted to earn a regulated rate of return on assets, determined by the regulator based on the utility's allowed regulatory asset base, capital structure and cost of capital. The asset base on which the utility is permitted a return is determined by the regulator, within the framework of applicable local laws, and is based on the amount of assets that are considered used and useful in serving customers. Both the allowed return and the asset base are important components of the utility's earning power. The allowed rate of return and operating expenses deemed reasonable by the regulator are recovered through the regulated tariff that the utility charges to its customers.
The tariff may be reviewed and reset by the regulator from time to time depending on local regulations, or the utility may seek a change in its tariffs. The tariff is generally based upon usage level and may include a pass-through of costs that are not controlled by the utility, such as the costs of fuel (in the case of integrated utilities) and/or the costs of purchased energy, to the customer. Components of the tariff that are directly passed through to the customer are usually adjusted through a summary regulatory process or an existing formula-based mechanism. In some regulatory regimes, customers with demand above an established level are unregulated and can choose to contract directly with the utility or with other retail energy suppliers and pay non-bypassable fees, which are fees to the distribution company for use of its distribution system.
The regulated tariff generally recognizes that our utility businesses should recover certain operating and fixed costs, as well as manage uncollectible amounts, quality of service and technical and non-technical losses. Utilities, therefore, need to manage costs to the levels reflected in the tariff, or risk non-recovery of costs or diminished returns.
Seasonality, Weather Variations, and Economic Activity — Our utility businesses are generally affected by seasonal weather patterns and, therefore, operating margin is not generated evenly throughout the year. Additionally, weather variations may also have an impact based on the number of customers, temperature variances from normal conditions, and customers' historic usage levels and patterns. Retail sales, after adjustments for weather variations, are also affected by changes in local economic activity, energy efficiency and distributed generation initiatives, as well as the number of retail customers.
Reliability of Service — Our utility businesses must meet certain reliability standards, such as duration and frequency of outages. Those standards may be explicit, with defined performance incentives or penalties, or implicit, where the utility must operate to meet customer and/or regulator expectations.
Development and Construction
We develop and construct new generation facilities. For our utility business, new plants may be built or existing plants retrofitted in response to customer needs or to comply with regulatory developments. The projects are developed subject to regulatory approval that permits recovery of our capital cost and a return on our investment. For our generation businesses, our priority for development is in key growth markets, where we can leverage our global scale and synergies with our existing businesses by adding renewable energy. We make the decision to invest in new projects by evaluating the strategic fit, project returns and financial profile against a fair risk-adjusted return for the investment and against alternative uses of capital, including corporate debt repayment.
In some cases, we enter into long-term contracts for output from new facilities prior to commencing construction. To limit required equity contributions from The AES Corporation, we also seek non-recourse project debt financing and other sources of capital, including partners, when it is commercially attractive. We typically contract with a third party to manage construction, although our construction management team supervises the construction work and tracks progress against the project's budget and the required safety, efficiency and productivity standards.
|10 | 2020 Annual Report|
The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the business internally. It is organized by geographic regions, which provides a socio-political-economic understanding of our business.
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) — which are led by our SBU Presidents. We have two lines of business: generation and utilities. Each of our SBUs participates in our first business line, generation, in which we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. Our US and Utilities SBU participates in our second business line, utilities, in which we own and/or operate utilities to generate or purchase, distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market.
We measure the operating performance of our SBUs using Adjusted PTC, a non-GAAP measure. The Adjusted PTC by SBU for the year ended December 31, 2020 is shown below. The percentages for Adjusted PTC are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before deductions for Corporate. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted PTC.
For financial reporting purposes, the Company's corporate activities and certain other investments are reported within "Corporate and Other" because they do not require separate disclosure. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 18—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure.
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US and Utilities SBU
Our US and Utilities SBU has 37 generation facilities, two utilities in the United States, and four utilities in El Salvador.
Generation — Operating installed capacity of our US and Utilities SBU totals 11,754 MW. IPALCO (IPL's parent), DP&L, and DPL Inc. (DP&L's parent) are all SEC registrants, and as such, follow the public filing requirements of the Securities Exchange Act of 1934. The following table lists our US and Utilities SBU generation facilities:
|Business||Location||Fuel||Gross MW||AES Equity Interest||Year Acquired or Began Operation||Contract Expiration Date||Customer(s)|
|El Salvador||Solar||100||50||%||2018-2019||2043-2044||CAESS, EEO, CLESA, DEUSEM|
|AES Nejapa||El Salvador||Landfill Gas||6||100||%||2011||2035||CAESS|
|El Salvador Subtotal||113|
AES Clean Energy (sPower OpCo A (1))
Southland Energy—Alamitos (2)
|US-CA||Gas||650||65||%||2020||2040||Southern California Edison|
Southland Energy—Huntington Beach(2)
|US-CA||Gas||649||65||%||2020||2040||Southern California Edison|
|AES Puerto Rico||US-PR||Coal||524||100||%||2002||2027||Puerto Rico Electric Power Authority|
AES Clean Energy (AES Distributed Energy) (3)
|US-Various||Solar||283||100||%||2015-2020||2029-2042||Utility, Municipality, Education, Non-Profit|
Buffalo Gap II (3)
|US-HI||Coal||206||100||%||1992||2022||Hawaiian Electric Co.|
|Warrior Run||US-MD||Coal||205||100||%||2000||2030||Potomac Edison|
|Prevailing Winds (AES Clean Energy/sPower)||US-SD||Wind||200||50||%||2020||2050||Prevailing Winds|
Buffalo Gap III (3)
|Highlander (AES Clean Energy/sPower)||US-VA||Solar||165||50||%||2020||2035||Apple, Akami, Etsy, Microsoft|
AES Clean Energy (sPower OpCo A (1))
AES Clean Energy (sPower OpCo B (1))
Buffalo Gap I (3)
Southland Energy—Alamitos Energy Center (2)
|US-CA||Energy Storage||100||65||%||2021||2041||Southern California Edison|
|East Line Solar (AES Clean Energy/sPower)||US-AZ||Solar||100||50||%||2020||2045||Salt River Project|
|Mountain View I & II||US-CA||Wind||64||100||%||2008||2021||Southern California Edison|
|Mountain View IV||US-CA||Wind||49||100||%||2012||2032||Southern California Edison|
Lawa'i (AES Clean Energy/AES Distributed Energy (3))
|US-HI||Solar||20||100||%||2018||2043||Kaua'i Island Utility Cooperative|
Kekaha (AES Clean Energy/AES Distributed Energy (3))
|US-HI||Solar||14||100||%||2019||2045||Kaua'i Island Utility Cooperative|
|Na Pua Makani||US-HI||Wind||28||100||%||2020||2040||HECO|
|Ilumina||US-PR||Solar||24||100||%||2012||2032||Puerto Rico Electric Power Authority|
|Laurel Mountain ES||US-WV||Energy Storage||16||100||%||2011|
Southland Energy—AES Gilbert (Salt River) (2)
|US-AZ||Energy Storage||10||65||%||2019||2039||Salt River Project Agricultural Improvement & Power District|
|Warrior Run ES||US-MD||Energy Storage||5||100||%||2016|
|United States Subtotal||7,668|
(1)Unconsolidated entity, accounted for as an equity affiliate.
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(2)AES is entitled to all earnings or losses until March 1, 2021, and any distributions related thereto.
(3)AES owns these assets together with third-party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as noncontrolling interest in the Company's Consolidated Balance Sheets.
(4)In November 2020, announced expected retirement in 2022.
Utilities — The following table lists our utilities and their generation facilities.
|Business||Location||Approximate Number of Customers Served as of 12/31/2020||GWh Sold in 2020||Fuel||Gross MW||AES Equity Interest||Year Acquired or Began Operation|
|El Salvador Subtotal||1,473,000||3,640|
|United States Subtotal||1,043,000||28,027||3,973|
(1)DPL's GWh sold in 2020 represent DP&L's (DPL's subsidiary) total transmission and distribution sales. DPL's wholesale revenues and DP&L's SSO utility revenues, which are sales to utility customers who use DP&L to source their electricity through a competitive bid process, were 4,481 GWh in 2020. DPL's other primary subsidiary, AES Ohio Generation, LLC, owned an interest in Conesville Unit 4. This plant was shutdown in May 2020 and sold in June 2020. DP&L also owns a 4.9% equity ownership in OVEC, an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,109 MW. DP&L’s share of this generation is approximately 103 MW.
(2)CDPQ owns direct and indirect interests in IPALCO which total approximately 30%. AES owns 85% of AES US Investments and AES US Investments owns 82.35% of IPALCO. IPL plants: Georgetown, Harding Street, Petersburg and Eagle Valley. 20 MW of IPL total is considered a transmission asset. In December 2019, IPL announced it would be retiring Petersburg Unit 1 in June 2021 and Petersburg Unit 2 in June 2023, a total of 630 MW. IPL issued an all-source Request for Proposal in December 2019 in order to competitively procure replacement capacity.
Under construction — The following table lists our plants under construction in the US and Utilities SBU:
|Business||Location||Fuel||Gross MW||AES Equity Interest||Expected Date of Commercial Operations|
|AES Clean Energy (AES Distributed Energy)||US-Various||Solar||77||100||%||1H 2021|
|Central Line (AES Clean Energy/sPower)||US-AZ||Solar||100||50||%||2H 2021|
|Clover Creek (AES Clean Energy/sPower)||US-UT||Solar||80||50||%||2H 2021|
|Cuscatlan Solar||El Salvador||Solar||10||100||%||1H 2021|
The majority of projects under construction have executed long-term PPAs or, as applicable, have been assigned tariffs through a regulatory process.
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The following map illustrates the locations of our US and Utilities facilities:
US and Utilities Businesses
Business Description — IPALCO is a holding company whose principal subsidiary is IPL. IPL, which also does business as AES Indiana, is an integrated utility that is engaged primarily in generating, transmitting, distributing, and selling electric energy to retail customers in the city of Indianapolis and neighboring areas within the state of Indiana and is subject to regulatory authority—see Regulatory Framework and Market Structure below. IPL has an exclusive right to provide electric service to the customers in its service area, covering about 528 square miles with an estimated population of approximately 965,000 people. IPL owns and operates four generating stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired, and IPL has plans to retire approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively (see Integrated Resource Plan below). The second largest station, Harding Street, uses natural gas and fuel oil to power combustion turbines. In addition, IPL operates a 20 MW battery-based energy storage unit at Harding Street, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. IPL took operational control and commenced commercial operations of this CCGT in April 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. In addition, IPL helps meet its customers' energy needs with long-term contracts for the purchase of 96 MW of solar-generated electricity and 300 MW of wind-generated electricity.
Key Financial Drivers — IPL's financial results are driven primarily by retail demand, weather, and maintenance costs. IPL's financial results are likely to be driven by many other factors as well, including, but not limited to:
•regulatory outcomes and impacts;
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•the passage of new legislation, implementation of regulations, or other changes in regulation; and
•timely recovery of capital expenditures.
Regulatory Framework and Market Structure — IPL is subject to comprehensive regulation by the IURC with respect to its services and facilities, retail rates and charges, the issuance of long-term securities, and certain other matters. The regulatory authority of the IURC over IPL's business is typical of regulation generally imposed by state public utility commissions. The IURC sets tariff rates for electric service provided by IPL. The IURC considers all allowable costs for ratemaking purposes, including a fair return on assets used and useful to providing service to customers.
IPL's tariff rates for electric service to retail customers consist of basic rates and approved charges. In addition, IPL's rates include various adjustment mechanisms, including, but not limited to: (i) a rider to reflect changes in fuel and purchased power costs to meet IPL's retail load requirements, referred to as the Fuel Adjustment Charge, (ii) a rider to reflect changes in ongoing RTO costs, and (iii) a rider for the timely recovery of demand side management energy efficiency program costs, and (iv) riders to collect changes in capacity sales and wholesale sales margins above and below established annual benchmarks, referred to as the Capacity Adjustment and Off-System Sales Margin Adjustment, respectively. These components function somewhat independently of one another, but the overall structure of IPL's rates is subject to review at the time of any review of IPL's basic rates and charges. Additionally, IPL's rider recoveries are reviewed through recurring filings.
On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement to increase IPL's annual revenues by $44 million, or 3% (the "2018 Base Rate Order"). This revenue increase primarily includes recovery through rates of costs associated with the CCGT at Eagle Valley, completed in the first half of 2018, and other construction projects. New base rates and charges became effective on December 5, 2018. The 2018 Base Rate Order also provides customers with approximately $50 million in benefits over a two-year period through a rate adjustment mechanism that began in March 2019.
IPL is one of many transmission system owner members in MISO, an RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. IPL offers electricity in the MISO day-ahead and real-time markets.
Development Strategy — IPL's construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental regulations, along with discretionary investments designed to replace aging equipment or improve overall performance.
Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that requests for recovery include a seven-year plan of eligible investments. Once a plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation, and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in the public utility’s next general rate case. The TDSIC mechanism is capped at an annual increase of two percent of total retail revenues.
On March 4, 2020, the IURC issued an order approving the projects in IPL's seven-year TDSIC Plan for eligible transmission, distribution, and storage system improvements totaling $1.2 billion from 2020 through 2027. On June 18, 2020, IPL filed its first annual TDSIC rate adjustment for a return on, and of, investments through March 31, 2020. On October 14, 2020, the IURC issued an order approving this TDSIC rate adjustment, which was reflected in rates effective November 2020.
Integrated Resource Plan — In December 2019, IPL filed its Integrated Resource Plan ("IRP"), which describes IPL's Preferred Resource Portfolio for meeting its generation capacity needs for serving its retail customers over the next several years. IPL's Preferred Resource Portfolio is IPL's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The IRP includes the retirement of 630 MW of coal-fired generation by 2023. Based on extensive modeling, IPL has determined that the cost of operating Petersburg Units 1 and 2 exceeds the value customers receive compared to alternative resources. Retirement of these units allows the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.
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IPL issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which is the first year IPL is expected to have a capacity shortfall. Modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. Proposals were received through February 28, 2020 and are currently being evaluated. On February 5, 2021, IPL announced an agreement to acquire a 195 MW solar project, subject to approval from the IURC.
Business Description — DPL is an energy holding company whose principal subsidiary is DP&L. DP&L, which also does business as AES Ohio, is a utility company that transmits and distributes electricity to retail customers in a 6,000 square mile area of West Central Ohio and is subject to regulatory authority—see Regulatory Framework and Market Structure below. DP&L has the exclusive right to provide transmission and distribution services to its customers, and procures retail standard service offer ("SSO") electric service on behalf of residential, commercial, industrial, and governmental customers through a competitive bid auction process. In previous years, AES Ohio Generation was also a primary subsidiary, but DPL has systematically exited this generation business. AES Ohio Generation completed the sale of its peaker assets in March 2018. In May 2018, AES Ohio Generation retired its Stuart and Killen facilities and completed the transfer of these facilities to a third party in December 2019. AES Ohio Generation's only remaining operating asset, Conesville Unit 4, was shut down in May 2020 and sold in June 2020.
Key Financial Drivers — Following the removal of the Decoupling Rider in December 2019, DPL's financial results are driven primarily by retail demand and weather. DPL's financial results are likely to be driven by other factors as well, including, but not limited to:
•regulatory outcomes and impacts;
•the passage of new legislation, implementation of regulations, or other changes in regulations; and
•timely recovery of transmission and distribution expenditures.
Regulatory Framework and Market Structure — DP&L is regulated by the PUCO for its distribution services and facilities, retail rates and charges, reliability of service, compliance with renewable energy portfolio requirements, energy efficiency program requirements, and certain other matters. The PUCO maintains jurisdiction over the delivery of electricity, SSO, and other retail electric services.
Electric customers within Ohio are permitted to purchase power under contract from a Competitive Retail Electric Service ("CRES") provider or from their local utility under SSO rates. The SSO generation supply is provided by third parties through a competitive bid process. Ohio utilities have the exclusive right to provide transmission and distribution services in their state-certified territories. While Ohio allows customers to choose retail generation providers, DP&L is required to provide retail generation service at SSO rates to any customer that has not signed a contract with a CRES provider or as a provider of last resort in the event of a CRES provider default. SSO rates are subject to rules and regulations of the PUCO and are established through a competitive bid process for the supply of power to SSO customers.
DP&L's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. DP&L is permitted to recover its costs of providing distribution service as well as earn a regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base, capital structure, and cost of capital. DP&L's retail rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred related to power purchased through the competitive bid process, participation in the PJM RTO, severe storm damage, and energy efficiency. DP&L's transmission rates are regulated by FERC.
DP&L is a member of PJM, an RTO that operates the transmission systems owned by utilities operating in all or parts of a multi-state region, including Ohio. PJM also administers the day-ahead and real-time energy markets, ancillary services market and forward capacity market for its members.
In September 2018, DP&L received an order from the PUCO establishing new base distribution rates, which became effective October 1, 2018. The order approved, without modification, a stipulation and recommendation previously filed by DP&L, along with various intervening parties, with the PUCO staff. The order established a revenue requirement of $248 million for DP&L's electric service base distribution rates, which reflected an increase to distribution revenues of $30 million per year. In addition, the order authorized DP&L to collect from customers costs related to qualified investments through a Distribution Investment Rider ("DIR"), changed the Decoupling Rider to reduce variability from the impact of weather and demand, partially resolved regulatory issues related to the TCJA, and authorized DP&L to defer certain vegetation management costs for future collection.
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On November 30, 2020, DP&L filed a new Distribution Rate Case Application proposing a revenue increase of $121 million per year and incorporates DIR investments that were planned and approved in the last rate case but not yet included in distribution rates, other distribution investments since September 2015, investments necessitated by the tornados that occurred on Memorial Day in 2019, and other proposed increases. The outcome of this filing is unknown at this time.
In March 2020, DP&L filed an application for a formula-based rate for its transmission service, which was approved and made effective May 3, 2020. In December 2020, a unanimous settlement was reached regarding these rates and filed with the FERC, which would be an approximately $7 million annualized increase from the rates in effect prior to May 3, 2020. The uncontested settlement is expected to receive FERC approval in early 2021.
ESP Proceedings — Ohio law requires utilities to provide their customers a default generation service, known as an SSO, which can be in the form of an electric security plan ("ESP") or a market rate offer ("MRO"), submitted for approval to the PUCO. The PUCO previously approved DP&L’s ESP for a six-year period beginning on November 1, 2017 (“ESP 3”). ESP 3 established a Distribution Modernization Rider (“DMR”) with an initial three-year term to collect $105 million in revenue per year through October 2020 primarily to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure.
In November 2019, the PUCO issued an order modifying the ESP 3 by removing the DMR. As a result, DP&L requested and the PUCO approved the request to revert to the ESP 1 rates, including authorizing the collection of a Rate Stability Charge ("RSC") of approximately $79 million per year, effective December 18, 2019. The order also disallowed the Regulatory Compliance Rider, Uncollectible Rider, DIR, and the Decoupling Rider. The PUCO order also required DP&L to conduct both an ESP v. MRO Test to validate that the ESP is more favorable in the aggregate than what would be experienced under an MRO, and a prospective SEET, both of which were filed with the PUCO on April 1, 2020. DP&L is also subject to an annual retrospective SEET. On October 23, 2020, DP&L entered into a Stipulation and Recommendation with the staff of the PUCO and certain other parties with respect to, among other matters, DP&L’s applications pending at the PUCO for (i) approval of DP&L’s plan to modernize its distribution grid (the “Smart Grid Plan”), (ii) findings that DP&L passed the SEET for 2018 and 2019, and (iii) findings that DP&L’s current electric security plan, ESP 1, satisfies the SEET and the more favorable in the aggregate (“MFA”) regulatory test. The settlement is subject to, and conditioned upon, approval by the PUCO. A hearing was conducted January 11 - 15, 2021 for consideration of this settlement. The settlement would provide, among other items, for the following:
•Approval of the Smart Grid Plan outlined in the Smart Grid Plan application filed by DP&L with the PUCO, as modified by the terms of the settlement, including, subject to offsetting operational benefits and certain other conditions, a return on and recovery of up to $249 million of Smart Grid Plan Phase 1 capital investments and recovery of operational and maintenance expenses through DP&L’s existing Infrastructure Investment Rider for a term of four years, under an aggregate cap of approximately $268 million on the amount of such investments and expenses that is recoverable, and an acknowledgement that DP&L may file a subsequent application with the PUCO within three years seeking approvals for Phase 2 of the Smart Grid Plan;
•A commitment by DP&L to invest in a Customer Information System and supporting technologies during Phase 1 of the Smart Grid Plan, with return on and of prudently incurred capital investments and operational and maintenance expenses, including deferred operational and maintenance expense amounts, in a future rate case;
•A determination that ESP 1 satisfies the prospective SEET and the MFA regulatory test;
•A recommendation by parties to the settlement that the PUCO also finds that DP&L satisfies the retrospective SEET for 2018 and 2019;
•A commitment to file an application with the PUCO no later than October 1, 2023 for a new ESP that does not seek to implement certain non-bypassable charges, including those related to provider of last resort risks, stability, or financial integrity;
•DP&L shareholder funding, in an aggregate amount of approximately $30 million over four years, for certain economic development discounts, incentives, and grants to certain commercial and industrial customers, including hospitals and manufacturers, assistance for low-income customers as well as the residents and businesses of the City of Dayton, and promotion of solar and resiliency development within DP&L’s service territory.
Certain parties which intervened in the ESP proceedings have filed petitions for rehearing of the recent PUCO ESP order, some of which seek to eliminate DP&L's RSC from its rates and others to re-implement ESP 3 without
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the DMR. The ultimate outcome of these petitions is unknown and could have a material adverse effect on DP&L’s results of operations, financial condition and cash flows. The parties signing the above-referenced settlement have agreed to withdraw their respective petitions if the settlement is approved by the PUCO without material modification.
Separate from the ESP process, on January 23, 2020, DP&L filed with the PUCO requesting approval to defer its decoupling costs consistent with the methodology approved in its Distribution Rate Case. If approved, deferral would be effective December 18, 2019 and going forward would reduce impacts of weather, energy efficiency programs, and economic changes in customer demand.
Development Strategy — Planned construction projects primarily relate to new investments in and upgrades to DP&L's transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments, and changing environmental standards, among other factors.
DPL is projecting to spend an estimated $767 million on capital projects from 2021 through 2023, which includes expected spending under DP&L's Smart Grid Plan included in the Stipulation and Recommendation entered into on October 23, 2020 (see Regulatory Framework and Market Structure above) as well as new transmission projects. The Smart Grid Plan was initially filed with the PUCO in December 2018 proposing to invest $576 million in capital projects over 10 years and includes leveraging technologies to modernize and improve the sustainability of the grid, and enhancing customer experience and security, as well as to allow DP&L to leverage and integrate distributed energy resources into its grid, including community solar, energy storage, microgrids, and electric vehicle charging infrastructure. DPL expects to finance this construction with a combination of cash on hand, short-term financing, long-term debt, equity capital contributions, and cash flows from operations.
Non-renewable U.S. Generation
Business Description — In the U.S., we own a diversified generation portfolio. The principal markets and locations where we are engaged in the generation and supply of electricity (energy and capacity) are the California Independent System Operator ("CAISO"), PJM, Hawaii, and Puerto Rico. AES Southland, operating in the CAISO, is our most significant generation business.
Many of our non-renewable U.S. generation plants provide baseload operations and are required to maintain a guaranteed level of availability. Any change in availability has a direct impact on financial performance. Some plants are eligible for availability bonuses if they meet certain requirements. Coal and natural gas are used as the primary fuels. Coal prices are set by market factors internationally, while natural gas prices are generally set domestically. Price variations for these fuels can change the composition of generation costs and energy prices in our generation businesses.
Many of these generation businesses have entered into long-term PPAs with utilities or other offtakers. Some businesses with PPAs have mechanisms to recover fuel costs from the offtaker, including an energy payment partially based on the market price of fuel. When market price fluctuations in fuel are borne by the offtaker, revenue may change as fuel prices fluctuate, but the variable margin or profitability should remain consistent. These businesses often have an opportunity to increase or decrease profitability from payments under their PPAs depending on such items as plant efficiency and availability, heat rate, ability to buy coal at lower costs through AES' global sourcing program, and fuel flexibility.
Warrior Run is one of our non-renewable generation businesses in the U.S. that currently operate as a QF, as defined under the PURPA. This business entered into a long-term contract with an electric utility that had a mandatory obligation to purchase power from QFs at the utility's avoided cost (i.e. the likely costs for both energy and capital investment that would have been incurred by the purchasing utility if that utility had to provide its own generating capacity or purchase it from another source). To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling application in certain proportions to the facility's total energy output and meet certain efficiency standards. To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet certain size criteria or be a cogeneration facility that simultaneously generates electricity and processes heat or steam.
Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under the EPAct of 1992, amending the Public Utility Holding Company Act (“PUHCA”). These businesses, subject to approval of FERC, have the right to sell power at market-based rates, either directly to the wholesale market or to a third-party offtaker such as a power marketer or utility/industrial customer. Under the FPA and FERC's regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to
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FERC that the seller lacks market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry, and that there is no opportunity for abusive transactions involving regulated affiliates of the seller.
The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by FERC, and regional regulation as defined by rules designed and implemented by the RTOs, non-profit corporations that operate the regional transmission grid and maintain organized markets for electricity. These rules, for the most part, govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. See Item 1A.—Risk Factors for additional discussion on U.S. regulatory matters.
Business Description — AES Southland is one of the largest generation operators in California by aggregate installed capacity, with an installed gross capacity of 3,611 MW at the end of 2020. The five coastal power plants comprising AES Southland are in areas that are critical for local reliability and play an important role in integrating the increasing amounts of renewable generation resources in California. AES Southland is composed of three once-through cooling ("OTC") power plants, two combined cycle gas-fired generation facilities and an interconnected battery-based energy storage facility.
AES Huntington Beach, LLC, AES Alamitos, LLC, and AES Redondo Beach ("Southland OTC units") are contracted through Resource Adequacy Purchase Agreements (“RAPAs”). Under the RAPAs, as approved by the California Public Utilities Commission, these generating stations provide resource adequacy capacity, and have no obligation to produce or sell any energy to the RAPA counterparty. However, the generating stations are required to bid energy into the California ISO markets. Compensation under these RAPAs is dependent on the availability of the AES Southland units in the California ISO market. Failure to achieve the minimum availability target would result in an assessed penalty.
In November 2014, AES Southland was awarded 20-year contracts by Southern California Edison ("SCE") to provide 1,284 MW of combined cycle gas-fired generation and 100 MW of interconnected battery-based energy storage ("Southland Energy units"). The agreements for the combined cycle gas-fired generation were amended in 2019 and capacity was increased to 1,299 MW. The contracts are RAPAs with annual energy put options. If AES Southland exercises the annual put option, all capacity, energy and ancillary services will be sold to SCE in exchange for a fixed monthly fee that covers fixed operating cost, debt service, and return on capital. In addition, SCE will reimburse variable costs and provide the natural gas.
In April 2017, the California Energy Commission unanimously approved the licenses for the Southland Energy combined cycle projects at AES Alamitos and AES Huntington Beach. In June 2017, AES closed the financing of $2 billion, funded with a combination of non-recourse debt and AES equity. Construction of the combined cycle capacity began in 2017.
At the end of 2019, five of the twelve Southland OTC generation units were retired to support the construction efforts of the Southland Energy combined cycle gas-fired generation projects in anticipation of COD, which was reached in early February 2020. On January 23, 2020, the Statewide Advisory Committee on Cooling Water Intake Structures adopted a recommendation to present to the California State Water Resources Board ("SWRCB") to extend OTC compliance dates for the remaining Southland OTC units at AES Huntington Beach and AES Alamitos until December 31, 2023 and AES Redondo Beach until December 31, 2021. On September 1, 2020, in response to a request by the state's energy, utility, and grid operators and regulators, the SWRCB approved amendments to its OTC. The SWRCB OTC Policy previously required the shutdown and permanent retirement of all remaining Southland OTC generating units by December 31, 2020. See United States Environmental and Land-Use Legislation and Regulations—Cooling Water Intake for further discussion of AES Southland’s plans regarding the OTC Policy.
The construction of the Alamitos Energy Center, an interconnected battery-based energy storage facility, began in June 2019 and commercial operation of the energy storage capacity was achieved on January 1, 2021.
Key Financial Drivers — AES Southland's availability is one of the most important drivers of operations, along with market demand and prices for gas and electricity.
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Business Description — AES Hawaii receives an energy payment from its offtaker under a PPA expiring in 2022, which is based on a fixed rate indexed to the Gross National Product Implicit Price Deflator. Since the energy payment is not directly linked to market prices for fuel, the risk arising from fluctuations in market prices for coal is borne by AES Hawaii. AES Hawaii has entered into fixed-price coal purchase commitments through 2021 and plans to seek additional fuel purchase commitments during 2021 to manage fuel price risk in 2022.
In July 2020, the Hawaii State Legislature passed Senate Bill 2629 which will prohibit AES Hawaii from generating electricity from coal after December 31, 2022. This will restrict the Company from contracting the asset beyond the expiration of its existing PPA, and as a result, AES plans to retire the AES Hawaii facility in 2022.
Key Financial Drivers — AES Hawaii's financial results are driven by fuel costs and outages. The Company has entered into long-term fuel contracts to mitigate the risks associated with fluctuating prices. In addition, major maintenance requiring units to be off-line is performed during periods when power demand is typically lower.
Business Description — AES Puerto Rico owns and operates a coal-fired cogeneration plant and a solar plant of 524 MW and 24 MW, respectively, representing approximately 8% of the installed capacity in Puerto Rico. Both plants are fully contracted through long-term PPAs with PREPA expiring in 2027 and 2032, respectively. AES Puerto Rico receives a capacity payment based on the plants' twelve month rolling average availability, receiving the full payment when the availability is 90% or higher. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPAs with PREPA.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to, improved operational performance and plant availability.
Regulatory Framework and Market Structure — Puerto Rico has a single electric grid managed by PREPA, a state-owned entity that provides virtually all of the electric power consumed in Puerto Rico and generates, transmits, and distributes electricity to 1.5 million customers. The Puerto Rico Energy Bureau is the main regulatory body. The bureau approves wholesale and retail rates, sets efficiency and interconnection standards, and oversees PREPA's compliance with Puerto Rico's renewable portfolio standard.
Puerto Rico's electricity is 97% produced by thermal plants (43% from natural gas, 36% from petroleum, and 18% from coal).
AES Clean Energy
Business Description — AES manages the U.S. renewables portfolio, which comprises AES Distributed Energy, sPower and other renewable assets, as part of its broader investments in the U.S. On January 4, 2021, the sPower and AES Distributed Energy development platforms were merged to form AES Clean Energy Development, which will serve as the development vehicle for all future renewable projects in the U.S. sPower remains an AES unconsolidated affiliate after this merger. Collectively, AES Distributed Energy, sPower, AES Clean Energy Development, and the other renewable assets in the U.S. are referred to as AES Clean Energy.
Prior to the merger, both AES and sPower were recognized leaders in renewable development in the U.S. Together, AES Clean Energy is one of the top renewables growth platforms and the expanded team aims to solve our customers' energy challenges. AES Clean Energy offers its customers an expanded portfolio of innovative solutions based on cutting-edge technologies that are designed to accelerate their energy futures. Generation capacity of the systems owned and/or operated under AES Clean Energy is 2,983 MW across the U.S. with another 299 MW under construction. This capacity includes 2,066 MW of solar, 1,085 MW of wind, and 131 MW of energy storage.
A majority of solar projects under AES Clean Energy have been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in variability to earnings attributable to AES compared to the earnings reported at the facilities.
Key Financial Drivers — The financial results of AES Clean Energy are primarily driven by the efficient construction and operation of renewable energy facilities across the U.S. under long-term PPAs, through which the energy price on the entire production of these facilities is guaranteed. The financial results of renewable assets are
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primarily driven by the amount of wind or solar resource at the facilities, availability of facilities, and growth in projects.
Laurel Mountain, Buffalo Gap II and Buffalo Gap III are exposed to the volatility of energy prices and their revenue may change materially as energy prices fluctuate in their respective markets of operations. Laurel Mountain also operates 16 MW of battery energy storage that is sold into the PJM market as regulation energy. For these projects, PJM and ERCOT power prices impact financial results.
Development Strategy — As states, communities, and organizations of all types make commitments and plan to reduce their carbon footprints, renewables are the fastest-growing source of electricity generation in the U.S. AES Clean Energy works with its customers to co-create and deliver the smarter, greener energy solutions that meet their needs, including 24/7 carbon-free energy. The merged renewables platform has brought together sPower's and AES' differentiated capabilities in solar, wind, and energy storage to accelerate customers' energy transitions.
AES Clean Energy has a renewable project backlog that includes 2,206 MW of projects for which long-term PPAs have been signed or, as applicable, tariffs have been assigned through a regulatory process. The budget for construction of the projects currently under construction and the contracted projects is over $3.9 billion. AES Clean Energy is actively developing new products and renewable sites to serve the current and future needs of its customers.
U.S. Environmental Regulation
For information on compliance with environmental regulations see Item 1.—United States Environmental and Land-Use Legislation and Regulations.
Business Description — AES El Salvador is the majority owner of four of the five distribution companies operating in El Salvador (CAESS, CLESA, EEO and DEUSEM). AES El Salvador's territory covers 77% of the country and accounted for 3,640 GWh of the wholesale market energy sales during 2020. AES El Salvador is also a 50% owner and operator of Bosforo, a 100 MW solar farm. The energy produced by this solar farm is fully contracted by AES' utilities in El Salvador.
In addition, AES El Salvador offers customers non-regulated services such as energy trading, electromechanical construction, O&M of electrical assets, EPC, pole rental, and tax collection for municipalities.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•improved operational performance;
•variability in energy demand driven by weather; and
•the impact of fuel oil prices on energy tariff prices, which affect cash flow due to a three-month delay in the pass-through of energy costs to the tariffs charged to customers.
Regulatory Framework and Market Structure — El Salvador's national electric market is composed of generation, distribution, transmission, and marketing businesses, a market and system operator, and regulatory agencies. The operation of the transmission system and the wholesale market is based on production costs with a marginal economic model that rewards efficiency and allows investors to have guaranteed profits, while end users receive affordable rates. The energy sector is governed by the General Electricity Law, which establishes two regulatory entities responsible for monitoring its compliance:
•The National Energy Council is the highest authority on energy policy and strategy, and the coordinating body for the different energy sectors. One of its main objectives is to promote investment in non-conventional renewable sources to diversify the energy matrix.
•The General Superintendence of Electricity and Telecommunications regulates the market and sets consumer prices, and, jointly with the distribution companies in El Salvador, developed the tariff calculation applicable from 2018 until 2022. The next tariff calculation is scheduled for 2022, and will be effective starting in 2023.
El Salvador has a national electric grid that interconnects directly with Guatemala and Honduras, allowing transactions with all Central American countries. The sector has approximately 1,799 MW of installed capacity, composed of thermal (40%), hydroelectric (31%), solar (11%), biomass (9%), and geothermal (9%) generation plants.
Development Strategy — In order to explore new business opportunities, AES El Salvador created AES
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Soluciones, an LED public lighting service provider and the main commercial and industrial solar photovoltaic EPC provider in the country. AES Next is also the O&M services provider for the Bosforo project.
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South America SBU
Our South America SBU has generation facilities in four countries — Chile, Colombia, Argentina and Brazil. AES Gener is a publicly traded company in Chile and owns all of our assets in Chile, AES Chivor in Colombia and TermoAndes in Argentina, as detailed below. AES has a 66.7% ownership interest in AES Gener and this business is consolidated in our financial statements. AES Brasil (the business formerly branded as AES Tietê) is a publicly traded company in Brazil. AES controls and consolidates AES Brasil through its 44% economic interest.
Operating installed capacity of our South America SBU totals 12,304 MW, of which 34%, 29%, 8%, and 29% are located in Argentina, Chile, Colombia and Brazil, respectively. The following table lists our South America SBU generation facilities:
|Business||Location||Fuel||Gross MW||AES Equity Interest||Year Acquired or Began Operation||Contract Expiration Date||Customer(s)|
Gener - Chile (1)
|Electrica Angamos||Chile||Coal||558||67||%||2011||2021||Minera Escondida, Minera Spence, Quebrada Blanca|
|Cochrane||Chile||Coal||550||40||%||2016||2030-2037||SQM, Sierra Gorda, Quebrada Blanca|
|Cochrane ES||Chile||Energy Storage||20||40||%||2016|
|Electrica Angamos ES||Chile||Energy Storage||20||67||%||2011|
|Norgener ES (Los Andes)||Chile||Energy Storage||12||67||%||2009|
|Alfalfal Virtual Reservoir||Chile||Energy Storage||10||67||%||2020|
|AES Gener Subtotal||5,196|
|San Nicolás||Argentina||Coal/Gas/Oil/Energy Storage||691||100||%||1993|
Guillermo Brown (4)
|Alto Sertão II||Brazil||Wind||386||44||%||2017||2033-2035||Various|
|Drogaria Araujo||Brazil||Solar||5||44||%||2019||2029||Drogaria Araujo|
|Brasil Community Solar||Brazil||Solar||1||44||%||2020|
|AES Brasil Subtotal||3,531|
(1)Gener - Chile plants: Alfalfal, Andes Solar, Andes Solar 2a, Laguna Verde, Laja, Los Cururos, Maitenes, Norgener 1, Norgener 2, Queltehues, Ventanas 2, Ventanas 3, Ventanas 4 and Volcán. In December 2020, AES Gener requested the retirement of Ventanas 1 and 2. Ventanas 1 initiated strategic reserve mode and Ventanas 2 is waiting for approval.
(2)Guacolda is comprised of five coal-fired units under Guacolda Energia S.A., an unconsolidated entity for which the results of operations are reflected in Net equity in earnings of affiliates. 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 34%.
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(3)TermoAndes is located in Argentina, but is connected to both the SEN in Chile and the SADI in Argentina.
(4)AES operates this facility through management or O&M agreements and to date owns no equity interest in the business.
(5)Tietê hydro plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mogi-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim and Sao Jose.
Under construction — The following table lists our plants under construction in the South America SBU:
|Business||Location||Fuel||Gross MW||AES Equity Interest||Expected Date of Commercial Operations|
|Tucano Phase 2||Brazil||Wind||167||44||%||2H 2022|
|Tucano Phase 1||Brazil||Wind||155||44||%||2H 2022|
|Farmácias São João||Brazil||Solar||3||44||%||1H 2021|
|AES Brasil Subtotal||330|
Alto Maipo (1)
|Los Olmos||Chile||Wind||110||67||%||1H 2021|
|Campo Lindo||Chile||Wind||73||67||%||1H 2021|
|Andes Solar 2b||Chile||Solar||180||67||%||2H 2021|
|San Fernando||Colombia||Solar||59||67||%||2H 2021|
(1) Alto Maipo is the largest project in construction in the Chilean market. When completed, it will include 75 km of tunnels, two power houses and 17 km of transmission lines.
The majority of projects under construction have executed mid- to long-term PPAs.
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo, a distribution business in Brazil. Prior to its sale, Eletropaulo was accounted for as an equity method investment and its results of operations and financial position were reported as discontinued operations in the consolidated financial statements for all periods presented.
In September 2020, the Company completed the sale of its entire interest in AES Uruguaiana, a gas-fired combined cycle power plant located in Brazil.
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The following map illustrates the location of our South America facilities:
South America Businesses
Business Description — In Chile, through AES Gener, we are engaged in the generation and supply of electricity (energy and capacity) in the SEN—see Regulatory Framework and Market Structure below. AES Gener is the second largest generation operator in Chile in terms of installed capacity with 3,450 MW, excluding energy storage, and has a market share of approximately 13% as of December 31, 2020.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers, and energy resources. AES Gener's generation plants are located near the principal electricity consumption centers, including Santiago, Valparaiso, and Antofagasta. AES Gener's diverse generation portfolio provides flexibility for the management of contractual obligations with regulated and unregulated customers, provides backup energy to the spot market and facilitates operations under a variety of market and hydrological conditions.
AES Gener's Green Blend and Extend strategy aims to reduce carbon intensity and incorporate renewable energy to extend our existing conventional PPAs. This strategy de-links our PPAs from legacy fossil resources, grows our renewable energy portfolio, and delivers a competitive, reliable energy solution. In line with the "green blend and extend" strategy, AES Gener has committed to not build additional coal-based power plants and to advance the development of new renewable projects, including the implementation of battery energy storage systems ("BESS") and other technological innovations that will provide greater flexibility and reliability to the system.
AES Gener currently has long-term contracts, with an average remaining term of approximately 9 years, with regulated distribution companies and unregulated customers, such as mining and industrial companies. In general,
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these long-term contracts include pass-through mechanisms for fuel costs along with price indexations to U.S. Consumer Price Index ("CPI").
In addition to energy payments, AES Gener also receives capacity payments to compensate for availability during periods of peak demand. The grid operator, Coordinador Electrico Nacional ("CEN"), annually determines the capacity requirements for each power plant. The capacity price is fixed semiannually by the National Energy Commission and indexed to the CPI and other relevant indices.
Key Financial Drivers — Hedge strategy at AES Gener limits volatility to the underlying financial drivers. In addition, financial results are likely to be driven by many factors, including, but not limited to:
•dry hydrology scenarios;
•changes in current regulatory rulings altering the ability to pass through or recover certain costs;
•fluctuations of the Chilean peso;
•tax policy changes;
•legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets; and
•market price risk when re-contracting.
Regulatory Framework and Market Structure — The Chilean electricity industry is divided into three business segments: generation, transmission, and distribution. Private companies operate in all three segments, and generators can enter into PPAs to sell energy to regulated and unregulated customers, as well as to other generators in the spot market.
Chile operates in a single power market, referred to as the SEN, which is managed by the grid operator CEN. The SEN has an installed capacity of 26,056 MW, and represents 99% of the installed generation capacity of the country.
CEN coordinates all generation and transmission companies in the SEN. CEN minimizes the operating costs of the electricity system, while maximizing service quality and reliability requirements. CEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost. In the south-central region of the SEN, thermoelectric generation is required to fulfill demand not satisfied by hydroelectric, solar, and wind output and is critical to provide reliable and dependable electricity supply under dry hydrological conditions in the highest demand area of the SEN. In the northern region of the SEN, which includes the Atacama Desert, thermoelectric capacity represents the majority of installed capacity. The fuels used for thermoelectric generation, mainly coal, diesel, and LNG, are indexed to international prices. In 2020, the installed generation capacity in the Chilean market was composed of 48% thermoelectric, 27% hydroelectric, 13% solar, 10% wind, and 2% other fuel sources.
Hydroelectric plants represent a significant portion of the system's installed capacity. Precipitation and snow melt impact hydrological conditions in Chile. Rain occurs principally from June to August and snow melt occurs from September to December. These factors affect dispatch of the system's hydroelectric and thermoelectric generation plants, thereby influencing spot market prices.
The Ministry of Energy has primary responsibility for the Chilean electricity system directly or through the National Energy Commission and the Superintendency of Electricity and Fuels.
All generators can sell energy through contracts with regulated distribution companies or directly to unregulated customers. Unregulated customers are customers whose connected capacity is higher than 5 MW. Customers with connected capacity between 0.5 MW and 5.0 MW can opt for regulated or unregulated contracts for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all electricity under contracts. Generators may also sell energy to other power generation companies on a short-term basis at negotiated prices outside the spot market. Electricity prices in Chile are denominated in USD, although payments are made in Chilean pesos.
The Chilean government’s decarbonization plan includes the complete retirement of the SEN coal fleet by the end of 2040 and carbon neutrality by 2050. During the year, AES Gener announced its commitment to shut down its Ventanas 1 coal-fired plant in 2020 and its Ventanas 2 coal-fired plant in June 2022 or earlier, pending resolution of current transmission constraints, and to disconnect both plants from the SEN in 2025. On December 26, 2020, the
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Ministry of Energy’s Supreme Decree Number 42 went into effect, allowing coal plants to enter into Strategic Reserve Status (“SRS”) and receive 60% of capacity payments for the 5-year period following its shutdown to remain connected as a backup in case of a system emergency. Following the issuance of this regulation and per the disconnection and termination agreement signed with the Chilean government in June 2019, the Ventanas 1 power plant was shut down on December 29, 2020 to enter into SRS.
Environmental Regulation — In March 2019, a new decontamination plan for the Ventanas region was approved. We are currently implementing the requirements defined by the plan which will impact our Ventanas and Guacolda businesses.
Chilean law requires all electricity generators to supply a certain portion of their total contractual obligations with non-conventional renewable energy ("NCREs"). Generation companies are able to meet this requirement by building NCRE generation capacity (wind, solar, biomass, geothermal, and small hydroelectric technology) or purchasing NCREs from qualified generators. Non-compliance with the NCRE requirements will result in fines. AES Gener currently fulfills the NCRE requirements by utilizing AES Gener's solar and biomass power plants and by purchasing NCREs from other generation companies. At present, AES Gener is in the process of negotiating additional NCRE supply contracts to meet future requirements.
Since 2017, emissions of particulate matter, SO2, NOX, and CO2 are monitored for plants with an installed capacity over 50 MW; these emissions are taxed. In the case of CO2, the tax is equivalent to $5 per ton emitted. Certain PPAs have clauses allowing the Company to pass the green tax costs to unregulated customers, while some distribution PPAs do not allow for the pass through of these costs.
Development Strategy — AES Gener is committed to reducing the coal intensity of the Chilean power grid and plans to increase the renewable energy capacity in its portfolio. As part of this commitment, and in addition to the 531 MW hydroelectric generation that Alto Maipo will deliver to the system, AES Gener purchased the 110 MW Los Cururos wind farm and its substation in northern Chile, and has finished construction on the 80 MW Andes 2a facility. Also under construction are the 110 MW Los Olmos wind farm, 66 MW Mesamávida wind farm, 73 MW Campo Lindo wind farm, and 180 MW Andes Solar 2b facility, which also includes 112 MW of BESS, to supply agreements with its main mining customers in execution of the new Green Blend and Extend strategy. In total, the pipeline currently has 4.4 GW under development at different stages and diversified geographically.
AES Gener executes its Green Blend and Extend strategy by integrating renewable energy sources into its portfolio, and by providing contracting options that contain a mix of both renewable and nonrenewable solutions.
Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, which owns a hydroelectric plant with an installed capacity of 1,000 MW and Tunjita, a 20 MW run-of-river hydroelectric plant, both located approximately 160 km east of Bogota, as well as Castilla, a 21 MW solar facility. AES Chivor’s installed capacity accounted for approximately 6% of system capacity at the end of 2020. AES Chivor is dependent on hydrological conditions, which influence generation and spot prices of non-contracted generation in Colombia.
AES Chivor's commercial strategy aims to execute contracts with commercial and industrial customers and bid in public tenders, mainly with distribution companies, in order to reduce margin volatility with proper portfolio risk management. The remaining energy generated by our portfolio is sold to the spot market, including ancillary services. Additionally, AES Chivor receives reliability payments for maintaining the plant's availability and generating firm energy during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
Key Financial Drivers — Hydrological conditions largely influence Chivor's power generation. Maintaining the appropriate contract level, while maximizing revenue through the sale of excess generation, is key to Chivor's results of operations. In addition to hydrology, financial results are driven by many factors, including, but not limited to:
•fluctuations of the Colombian peso; and
•spot market prices.
Regulatory Framework and Market Structure — Electricity supply in Colombia is concentrated in one main system, the SIN, which encompasses one-third of Colombia's territory, providing electricity to 97% of the country's population. The SIN's installed capacity, primarily hydroelectric (69%) and thermal (31%), totaled 17,473 MW as of
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December 31, 2020. The marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2020, 72% of total energy demand was supplied by hydroelectric plants.
The electricity sector in Colombia operates under a competitive market framework for the generation and sale of electricity, and a regulated framework for transmission and distribution of electricity. The distinct activities of the electricity sector are governed by Colombian laws and CREG, the Colombian regulating entity for energy and gas. Other government entities have a role in the electricity industry, including the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing utility companies; and the Mining and Energy Planning Unit, which is in charge of expansion of the generation and transmission network.
The generation sector is organized on a competitive basis with companies selling their generation in the wholesale market at the short-term price or under bilateral contracts with other participants, including distribution companies, generators and traders, and unregulated customers at freely negotiated prices. The National Dispatch Center dispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the lowest cost combination of available generating units.
Development Strategy — AES Colombia is committed to transform into a renewable growth platform by supporting its customers to diversify their energy supply and become more competitive. As part of this commitment, AES Colombia is developing a pipeline of 1.3 GW of solar and wind projects. Five projects (648 MW) of wind energy are located in La Guajira, one of the windiest spots on Earth, and two projects (255 MW) were awarded a 15-year PPA at the last renewable auction. One project (99 MW) of the Wind Cluster has Environmental License and the others are progressing smoothly in their development process. During 2020, AES Colombia was awarded the 61 MW San Fernando Solar project through a 15-year PPA with Ecopetrol and started construction in September. This solar project, along with the 21 MW Castilla project built in 2019 also with a PPA with Ecopetrol, has been fundamental in leading the renewable market in Colombia.
Business Description — AES operates plants in Argentina totaling 4,220 MW, representing 10% of the country's total installed capacity. AES owns a diversified generation portfolio in Argentina in terms of geography, technology, and fuel source. AES Argentina's plants are placed in strategic locations within the country in order to provide energy to the spot market and customers, making use of wind, hydro, and thermal plants.
AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2020, approximately 90% of the energy was sold in the wholesale electricity market and 10% was sold under contract sales made by TermoAndes, Vientos Neuquinos, and Vientos Bonaerenses power plants.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•exposure to fluctuations of the Argentine peso;
•changes in hydrology and wind resources;
•timely collection of FONINVEMEM installments and outstanding receivables (see Regulatory Framework and Market Structure below); and
•natural gas prices and availability for contracted generation at Termoandes.
Regulatory Framework and Market Structure — Argentina has one main power system, the SADI, which serves 96% of the country. As of December 31, 2020, the installed capacity of the SADI totaled 41,991 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (61%) and hydroelectric generation (27%), as well as wind (6%), nuclear (4%), and solar (2%).
Thermoelectric generation in the SADI is primarily natural gas. However, scarcity of natural gas during winter periods (June to August) due to transport constraints result in the use of alternative fuels, such as oil and coal. The SADI is also highly reliant on hydroelectric plants. Hydrological conditions impact reservoir water levels and largely influence the dispatch of the system's hydroelectric and thermoelectric generation plants and, therefore, influence market costs. Precipitation in Argentina occurs principally from June to August.
The Argentine regulatory framework divides the electricity sector into generation, transmission, and distribution. The wholesale electric market is comprised of generation companies, transmission companies, distribution companies, and large customers who are permitted to trade electricity. Generation companies can sell
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their output in the spot market or under PPAs. CAMMESA manages the electricity market and is responsible for dispatch coordination. The Electricity National Regulatory Agency is in charge of regulating public service activities and the Secretariat of Energy regulates system framework and grants concessions or authorizations for sector activities. In Argentina, there is a tolling scheme in which the regulator establishes prices for electricity and defines fuel reference prices. As a result, our businesses are particularly sensitive to changes in regulation.
The Argentine electric market is an "average cost" system. Generators are compensated for fixed costs and non-fuel variable costs, under prices denominated in Argentine pesos. CAMMESA is in charge of providing the natural gas and liquid fuels required by the generation companies, except for coal.
During 2020, the government has maintained prices to the end user, increasing subsidies and the system deficit. By December 2020, distribution companies recovered an average 55% of the total cost of the system.
AES Argentina contributed certain accounts receivable to fund the construction of new power plants under FONINVEMEM agreements. These receivables accrue interest and have been collected in monthly installments over 10 years after commercial operation date of the related plant took place. AES Argentina participated in the construction of three power plants under the FONINVEMEM structure, and in addition to the repayment of the accounts receivable contributed, AES Argentina will receive a pro rata ownership interest in each of these plants once the accounts receivables have been fully repaid. FONINVEMEM I and II installments were fully repaid in the first quarter of 2020 and the ownership interests in Termoeléctrica San Martín and Termoeléctrica Manuel Belgrano power plants are subject to agreement between the government and all generators that participated in the funds. FONINVEMEM III installments, related to Termoeléctrica Guillermo Brown which commenced operations in April 2016, are still being collected. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Long-Term Receivables and Note 7.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of receivables in Argentina.
In 2019 and 2020, the Argentine peso devalued against the USD by approximately 37% and 29%, respectively, and Argentina’s economy continued to be highly inflationary. Since September 2019, currency controls have been established to govern the devaluation of the Argentine peso and keep Argentine central bank reserves at acceptable levels for the next government of Argentina.
Development Strategy — Currently, 800 MW of renewable greenfield projects are in early and mid stages of development. These projects could be used to participate in future private PPAs or public auctions. In addition, "behind the meter” and off-grid solutions are being developed for the industrial sector (mining), including solar power plants plus BESS.
Business Description — AES Brasil (the business formerly branded as AES Tietê) has a portfolio of 12 hydroelectric power plants in the state of São Paulo with total installed capacity of 2,658 MW. These hydroelectric plants operate under a 30-year concession expiring in 2029.
Over the past three years, AES Brasil acquired and developed two solar power complexes in the state of São Paulo, which are fully contracted with 20-year PPAs and together account for 294 MW of installed capacity. AES Brasil represents approximately 12% of the total generation capacity in the state of São Paulo.
AES Brasil also owns Alto Sertão II, a wind complex located in the state of Bahia with an installed capacity of 386 MW and subject to 20-year PPAs expiring between 2033 and 2035, and in December 2020, also acquired the Ventus wind complex located in the State of Rio Grande do Norte with an installed capacity of 187 MW and subject to a 20-year PPA expiring in 2032.
In the second half of 2020, AES acquired an additional 19.8% ownership in AES Brasil. As of December 31, 2020, AES owns 44% of AES Brasil and is the controlling shareholder and manages and consolidates this business. As a result of the transaction, AES has also committed to transition the listing of AES Brasil's shares to the Novo Mercado, a listing segment of the Brazilian stock exchange with the highest standards of corporate governance. The transition to Novo Mercado is expected to occur in the first half of 2021.
In December 2020, AES Brasil entered into an agreement for the acquisition of the MS Wind and Santos Wind Complexes, located in the states of Rio Grande do Norte and Ceará, respectively. The complexes have been
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operational since 2013 with 159 MW of installed capacity, fully sold in the regulated market for 20 years.
AES Brasil aims to contract most of its physical guarantee requirements and sell the remaining portion in the spot market. The commercial strategy is reassessed periodically according to changes in market conditions, hydrology, and other factors. AES Brasil generally sells available energy through medium-term bilateral contracts.
Key Financial Drivers — The electricity market in Brazil is highly dependent on hydroelectric generation, therefore electricity pricing is driven by hydrology. Plant availability is also a significant financial driver as in times of high hydrology, AES is more exposed to the spot market. AES Brasil's financial results are driven by many factors, including, but not limited to:
•hydrology, impacting quantity of energy generated in the MRE (see Regulatory Framework and Market Structure below for further information);
•growth in demand for energy;
•market price risk when re-contracting;
•cost management; and
•ability to execute on its growth strategy.
Regulatory Framework and Market Structure — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy a generation plant can sell, called physical guarantee, representing the long-term average expected energy production of the plant. Under current rules, physical guarantee energy can be sold to distribution companies through long-term regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies.
Brazil has installed capacity of 176 GW, composed of hydroelectric (62%), thermoelectric (25%), renewable (12%), and nuclear (1%) sources. Operation is centralized and controlled by the national operator, ONS, and regulated by the Brazilian National Electric Energy Agency ("ANEEL"). The ONS dispatches generators based on their marginal cost of production and on the risk of system rationing. Key variables for the dispatch decision are forecasted hydrological conditions, reservoir levels, electricity demand, fuel prices, and thermal generation availability.
In case of unfavorable hydrology, the ONS will reduce hydroelectric dispatch to preserve reservoir levels and increase dispatch of thermal plants to meet demand. The consequences of unfavorable hydrology are (i) higher energy spot prices due to higher energy production costs by thermal plants and (ii) the need for hydro plants to purchase energy in the spot market to fulfill their contractual obligations.
A mechanism known as the MRE was created under ONS to share hydrological risk across MRE hydro generators by using a generation scaling factor ("GSF") to adjust generators' physical guarantee during periods of hydrological scarcity. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may need to purchase energy in the short-term market. When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they may sell the excess energy on the spot market.
In September 2020, Law 14.052/2020 published by ANEEL was approved by the President, establishing terms for compensation to MRE hydro generators for the incorrect application of the GSF mechanism from 2013 to 2018, which resulted in higher charges assessed to MRE hydro generators by the regulator. Under the law, potential compensation will be in the form of an offer for a concession extension for each hydro generator in exchange for full payment of billed GSF trade payables, the amount of which will be reduced in conjunction with the payment for a concession extension. See Key Trends and Uncertainties—Regulatory in Item 7.— Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K.
Development Strategy — AES Brasil's strategy is to grow by adding renewable capacity to its generation platform through acquisition or greenfield projects, to focus on client satisfaction and innovation to offer new products and energy solutions, and to be recognized for excellence in asset management.
In 2020, AES Brasil acquired the Tucano Project, a 582 MW greenfield wind power project in the state of Bahia, for which construction is scheduled to start in 2021 and when completed, will supply long-term PPAs. The first phase (155 MW) will be developed in 2021 through a joint venture with Unipar Carbocloro for a 20-year PPA starting in 2022. The second phase (167 MW) will be 100% developed by AES Brasil in 2021, for a 15-year PPA with Anglo American starting in 2022. AES Brasil is seeking other long-term PPAs to fulfill the remaining 260 MW.
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In March 2020, AES Brasil signed two purchase option agreements for a total installed capacity up to 1,100 MW of Cajuína greenfield wind power project in the state of Rio Grande do Norte, which are being exercised as the company secures long-term PPAs. In August 2020, AES Brasil signed a Shareholder Purchase Agreement ("SPA") for the first phase, Santa Tereza, which has installed capacity of 420 MW. Closing is expected to occur in the first quarter of 2021. A Memorandum of Understanding was signed with Ferbasa for 80 MW energy supply over a period of 20 years, beginning in 2024. The SPA for the second phase, São Ricardo, which has installed capacity of 437 MW, was signed in February 2021. AES Brasil is seeking other long-term PPAs to fulfill the remaining 777 MW in phases 1 and 2.
Under the current terms of the 2018 legal agreement in connection with AES Brasil's concession with the state government, AES Brasil is required to increase its capacity in the state of São Paulo by an additional 81 MW by October 2024.
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Our MCAC SBU has a portfolio of generation facilities, including renewable energy, in three countries, with a total capacity of 3,459 MW.
Generation — The following table lists our MCAC SBU generation facilities:
|Business||Location||Fuel||Gross MW||AES Equity Interest||Year Acquired or Began Operation||Contract Expiration Date||Customer(s)|
|DPP (Los Mina)||Dominican Republic||Gas||358||85||%||1996||2022||Andres, CDEEE, Non-Regulated Users|
|Dominican Republic||Gas||319||85||%||2003||2022||Ede Norte, Ede Este, Ede Sur, Non-Regulated Users|
|Dominican Republic||Coal||260||43||%||2000||2022||Ede Norte, Ede Este, Ede Sur, Non-Regulated Users|
|Andres ES||Dominican Republic||Energy Storage||10||85||%||2017|
|Los Mina DPP ES||Dominican Republic||Energy Storage||10||85||%||2017|
|Dominican Republic Subtotal||957|
|Merida III||Mexico||Gas/Diesel||505||75||%||2000||2025||Comision Federal de Electricidad|
Mesa La Paz (3)
|Mexico||Wind||306||50||%||2019||2045||Fuentes de Energia Peñoles|
|Termoelectrica del Golfo (TEG)||Mexico||Pet Coke||275||99||%||2007||2027||CEMEX|
|Termoelectrica del Penoles (TEP)||Mexico||Pet Coke||275||99||%||2007||2027||Peñoles|
|Panama||Gas||381||50||%||2018||2028||ENSA, Edemet, Edechi|
|Bayano||Panama||Hydro||260||49||%||1999||2030||ENSA, Edemet, Edechi, Other|
|Chiriqui-Esti||Panama||Hydro||120||49||%||2003||2030||ENSA, Edemet, Edechi, Other|
|Chiriqui-Los Valles||Panama||Hydro||54||49||%||1999||2030||ENSA, Edemet, Edechi, Other|
|Chiriqui-La Estrella||Panama||Hydro||48||49||%||1999||2030||ENSA, Edemet, Edechi, Other|
(1)Plant also includes an adjacent regasification facility, as well as a 70 TBTU LNG storage tank.
(2)Entered into an agreement to sell 43% interest in the Itabo facility in June 2020.
(3)Unconsolidated entity, accounted for as an equity affiliate.
(4)Plant also includes an adjacent regasification facility, as well as an 80 TBTU LNG storage tank.
Under construction — The following table lists our plants under construction in the MCAC SBU:
|Business||Location||Fuel||Gross MW||AES Equity Interest||Expected Date of Commercial Operations|
|Bayasol||Dominican Republic||Solar||50||85||%||1H 2021|
|Itabo Energy Storage||Dominican Republic||Energy Storage||7||43||%||2H 2021|
Dominican Republic Subtotal (1)
|Pese Solar||Panama||Solar||10||49||%||1H 2021|
|Mayorca Solar||Panama||Solar||10||49||%||1H 2021|
|5B Costa Norte||Panama||Solar||1||100||%||1H 2021|
(1)A second 50 TBTU LNG storage tank is under construction and expected to come on-line in the first half of 2023.
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The following map illustrates the location of our MCAC facilities:
Business Description — AES Dominicana consists of three operating subsidiaries: Itabo, Andres, and Los Mina. With a total of 957 MW of installed capacity, AES provides 19% of the country's capacity and supplies approximately 29% of the country's energy demand via these generation facilities. 873 MW is predominantly contracted until 2022 with government-owned distribution companies and large customers.
AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), a consortium of two leading Dominican industrial groups that manage a diversified business portfolio.
Itabo is 42.5% owned by AES. Itabo owns and operates two thermal power generation units with a total of 260 MW of installed capacity. On June 29, 2020, AES executed a sale and purchase agreement to sell its entire ownership interest in Itabo. In February 2021, the sale was approved by the Superintendence of Electricity and is expected to close in the first quarter of 2021.
Andres and Los Mina are owned 85% by AES. Andres owns and operates a combined cycle natural gas turbine and an energy storage facility with combined generation capacity of 329 MW, as well as the only LNG import terminal in the country, with 160,000 cubic meters of storage capacity. Los Mina owns and operates a combined cycle with two natural gas turbines and an energy storage facility with combined generation capacity of 368 MW.
AES Dominicana has a long-term LNG purchase contract through 2023 for 33.6 trillion btu/year with a price linked to NYMEX Henry Hub. The LNG contract terms allow delivery to various markets in Latin America. These plants capitalize on the competitively-priced LNG contract by selling power where the market is dominated by fuel oil-based generation. Andres has a long-term contract to sell regasified LNG to industrial users within the Dominican Republic using compression technology to transport it within the country, thereby capturing demand from industrial and commercial customers.
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Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•changes in spot prices due to fluctuations in commodity prices (since fuel is a pass-through cost under the PPAs, any variation in oil prices will impact spot sales for both Andres and Itabo);
•contracting levels and the extent of capacity awarded; and
•growth in domestic natural gas demand, supported by new infrastructure such as the Eastern Pipeline and second LNG tank.
Regulatory Framework and Market Structure — The Dominican Republic energy market is a decentralized industry consisting of generation, transmission, and distribution businesses. Generation companies can earn revenue through short- and long-term PPAs, ancillary services, and a competitive wholesale generation market. All generation, transmission, and distribution companies are subject to and regulated by the General Electricity Law.
Two main agencies are responsible for monitoring compliance with the General Electricity Law:
•The National Energy Commission drafts and coordinates the legal framework and regulatory legislation. They propose and adopt policies and procedures to implement best practices, support the proper functioning and development of the energy sector, and promote investment.
•The Superintendence of Electricity's main responsibilities include monitoring compliance with legal provisions, rules, and technical procedures governing generation, transmission, distribution, and commercialization of electricity. They monitor behavior in the electricity market in order to prevent monopolistic practices.
In addition to the two agencies responsible for monitoring compliance with the General Electricity Law, the Ministry of Industry and Commerce supervises commercial and industrial activities in the Dominican Republic as well as the fuels and natural gas commercialization to end users.
The Dominican Republic has one main interconnected system with 4,921 MW of installed capacity, composed of thermal (75%), hydroelectric (13%), wind (8%), and solar (4%).
Development Strategy — AES will continue to develop the commercialization of natural gas and incorporate partners directly in gas infrastructure projects. AES partnered with Energas in a joint venture which has been operating the 50 km Eastern Pipeline since February 2020. The joint venture is also developing a new LNG facility of 120,000 cubic meters, including additional storage, regasification, and truck loading capacity, for which construction is scheduled to start in 2021. This will allow AES to reach new customers who have converted, or are in the process of converting, to natural gas as a fuel source, and better operational flexibility.
Business Description — AES owns and operates five hydroelectric plants totaling 705 MW of generation capacity, a natural gas-fired power plant with 381 MW of generation capacity, and a wind farm of 55 MW, which collectively represent 30% of the total installed capacity in Panama. Furthermore, AES operates an LNG regasification facility, a 180,000 cubic meter storage tank, and a truck loading facility which reached commercial operations in December 2020.
The majority of our hydroelectric plants in Panama are based on run-of-the-river technology, with the exception of the 260 MW Bayano plant. Hydrological conditions have an important influence on profitability. Variations in hydrology can result in an excess or a shortfall in energy production relative to our contractual obligations. Hydro generation is generally in a shortfall position during the dry season from January through May, which is offset by thermal generation since its behavior is opposite and complementary to hydro generation.
Our hydro and thermal assets are mainly contracted through medium to long-term PPAs with distribution companies. A small volume of our hydro plants are contracted with unregulated users. Our hydro assets in Panama have PPAs with distribution companies expiring in December 2030 for a total contracted capacity of 383 MW. Our thermal asset in Panama has PPAs with distribution companies for a total contracted capacity of 350 MW expiring in August 2028.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•changes in hydrology, which impacts commodity prices and exposes the business to variability in the cost of replacement power;
•fluctuations in commodity prices, mainly oil and natural gas, which affect the cost of thermal generation and spot prices;
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•constraints imposed by the capacity of transmission lines connecting the west side of the country with the load, keeping surplus power trapped during the rainy season; and
•country demand as GDP growth is expected to remain strong over the short and medium term.
Regulatory Framework and Market Structure — The Panamanian power sector is composed of three distinct operating business units: generation, distribution, and transmission. Generators can enter into short-term and long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into alternative supply contracts with each other. Outside of PPAs, generators may buy and sell energy in the short-term market. Generators can only contract up to their firm capacity.
Three main agencies are responsible for monitoring compliance with the General Electricity Law:
•The National Secretary of Energy in Panama (SNE) has the responsibilities of planning, supervising, and controlling policies of the energy sector within Panama. The SNE proposes laws and regulations to the executive agencies that regulate the procurement of energy and hydrocarbons for the country.
•The regulator of public services, known as the ASEP, is an autonomous agency of the government. ASEP is responsible for the control and oversight of public services, including electricity, the transmission and distribution of natural gas utilities, and the companies that provide such services.
•The National Dispatch Center (CND) implements the economic dispatch of electricity in the wholesale market. The National Dispatch Center's objectives are to minimize the total cost of generation and maintain the reliability and security of the electric power system. Short-term power prices are determined on an hourly basis by the last dispatched generating unit. Physical generation of energy is determined by the National Dispatch Center regardless of contractual arrangements.
Panama's current total installed capacity is 3,854 MW, composed of hydroelectric (47%), thermal (41%), wind (7%), and solar (5%) generation.
Development Strategy — Given our LNG facility’s excess capacity in Panama, the company will develop natural gas supply solutions for third parties such as power generators and industrial and commercial customers. This strategy will support a growing demand for natural gas in the region and will contribute to AES' mission by reducing carbon dioxide emissions as a result of using LNG.
In addition to investing in LNG infrastructure, AES is investing in renewable projects within the region. This will increase complementary non-hydro renewable assets in the system and contribute to the reduction of hydrological risk in Panama.
Business Description — AES has 1,361 MW of installed capacity in Mexico. The TEG and TEP pet coke-fired plants, located in Tamuin, San Luis Potosi, supply power to their offtakers under long-term PPAs expiring in 2027 with a 90% availability guarantee. TEG and TEP secure their fuel under a long-term contract.
Merida is a CCGT located on Mexico's Yucatan Peninsula. Merida sells power to the CFE under a capacity and energy based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel fuel under a long-term contract with one of the CFE’s subsidiaries, the cost of which is then passed through to the CFE under the terms of the PPA.
Mesa La Paz, a 306 MW wind project developed under a joint venture with Grupo Bal, achieved commercial operations in December 2019. Starting in April 2020, Mesa La Paz sells power under a long-term PPA expiring in 2045.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•fully contracting the companies, providing additional benefits from improved operational performance, including performance incentives and/or excess energy sales; and
•changes in the methodology to calculate spot energy prices or Locational Marginal Prices, which impacts the excess energy sales to the CFE (see Regulatory Framework and Market Structure below) in (i) TEG and TEP under self-supply scheme, and (ii) Mesa La Paz under the New Market Rules.
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Regulatory Framework and Market Structure — Mexico´s main electrical system is called the National Interconnected System (SIN), which geographically covers an area from Puerto Peñasco, Sonora to Cozumel, Quintana Roo. Mexico also has three isolated electrical systems: (1) the Baja California Interconnected System, which is interconnected with the WECC; (2) the Baja California Sur Interconnected System; and (3) the Mulegé Interconnected System, a very small electrical system. All three are isolated from the SIN and from each other. The Mexican power industry comprises the activities of generation, transmission, distribution, and commercialization segments, considering transmission and distribution to be exclusive state services.
In addition to the Ministry of Energy, three main agencies are responsible for regulating the market agents and their activities, monitoring compliance with the Electric Industry Law and the Market Rules, and the surveillance of operational compliance and management of the wholesale electricity market:
•The Energy Regulatory Commission is responsible for the establishment of directives, orders, methodologies, and standards to regulate the electric and fuel markets, as well as granting permits.
•The National Center for Energy Control, as an ISO, is responsible for managing the wholesale electricity market, transmission and distribution infrastructure, planning network developments, guaranteeing open access to network infrastructure, executing competitive mechanisms to cover regulated demand, and setting transmission charges.
•The Electricity Federal Commission (CFE) owns the transmission and distribution grids and is also the country's basic supplier. CFE is the offtaker for IPP generators, and together with its own power units has more than 50% of the current generation market share.
Mexico has an installed capacity totaling 86 GW with a generation mix composed of thermal (65%), hydroelectric (15%), wind (8%), solar (7%), and other fuel sources (5%).
Development Strategy — AES has partnered with Grupo Bal in a joint venture to co-invest in power and related infrastructure projects in Mexico, focusing on renewable and natural gas generation.
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Generation — Our Eurasia SBU has generation facilities in five countries with total operating installed capacity of 2,791 MW. The following table lists our Eurasia SBU generation facilities:
|Business||Location||Fuel||Gross MW||AES Equity Interest||Year Acquired or Began Operation||Contract Expiration Date||Customer(s)|
|St. Nikola||Bulgaria||Wind||156||89||%||2010||2025||Electricity Security Fund|
|Delhi ES||India||Energy Storage||10||60||%||2019|
Amman East (1)
|Jordan||Gas||381||37||%||2009||2033||National Electric Power Company|
|Jordan||Heavy Fuel Oil||250||36||%||2014||2039||National Electric Power Company|
|AM Solar||Jordan||Solar||52||36||%||2019||2039||National Electric Power Company|
|Netherlands ES||Netherlands||Energy Storage||10||100||%||2015|
Mong Duong 2 (2)
(1)Entered into an agreement to sell 26% interest in these businesses in November 2020.
(2)Entered into an agreement to sell our entire interest in the Mong Duong 2 plant in December 2020.
In December 2020, the Company completed the sale of its entire 49% equity interest in the OPGC coal-fired generation facilities in India.
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The following map illustrates the location of our Eurasia facilities:
Business Description — Mong Duong 2 is a 1,242 MW gross coal-fired plant located in the Quang Ninh Province of Vietnam and was constructed under a BOT service concession agreement expiring in 2040. This is the first and largest coal-fired BOT plant using pulverized coal-fired boiler technology in Vietnam. The BOT company has a PPA with EVN and a Coal Supply Agreement with Vinacomin, both expiring in 2040.
On December 31, 2020, AES executed an agreement to sell its entire 51% interest in the Mong Duong 2 plant. The sale is expected to close in late 2021 or early 2022, subject to customary approvals, including from the Government of Vietnam and the minority partners in Mong Duong 2.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to, the operating performance and availability of the facility.
Regulatory Framework and Market Structure — The Ministry of Industry and Trade in Vietnam is primarily responsible for formulating a program to restructure the power industry, developing the electricity market, and promulgating electricity market regulations. The fuel supply is owned by the government through Vinacomin, a state-owned entity, and PetroVietnam.
The Vietnam power market is divided into three regions (North, Central, and South), with total installed capacity of approximately 54 GW. The fuel mix in Vietnam is composed primarily of hydropower at 37% and coal at 36%. EVN, the national utility, owns 53% of installed generation capacity.
The government is in the process of realigning EVN-owned companies into three different independent operations in order to create a competitive power market. The first stage of this realignment was the implementation of the Competitive Electricity Market, which has been in operation since 2012. The second stage was the introduction of the Electricity Wholesale Market, which has been in operation since the beginning of 2019. The third and final stage impacts the Electricity Retail Market, which will undergo similar reforms after 2022. BOT power
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plants will not directly participate in the power market; alternatively, a single buyer will bid the tariff on the power pool on their behalf.
Development Strategy — In Vietnam, we continue to advance the development of our Son My LNG terminal project, which has a design capacity of up to 9.6 million metric tonnes per annum, and the Son My 2 CCGT project, which has a capacity of about 2,250 MW. In October 2019, we received formal approval as a government-mandated investor in the Son My LNG terminal project in partnership with PetroVietnam Gas and in October 2020, we signed the term sheet agreement with PetroVietnam Gas for the joint venture agreement. In September 2019, we received formal approval as the government-mandated investor with 100% equity ownership in the Son My 2 CCGT project and executed a statutory memorandum of understanding with Vietnam’s Ministry of Industry and Trade in November 2019 to continue developing the Son My 2 CCGT project under Vietnam’s Build-Operate-Transfer legal framework. The Son My 2 CCGT project will utilize the Son My LNG terminal project and be its anchor customer.
Business Description — Our AES Maritza plant is a 690 MW lignite fuel thermal power plant. AES Maritza's entire power output is contracted with NEK, the state-owned public electricity supplier, independent energy producer, and trading company. Maritza is contracted under a 15-year PPA that expires in May 2026. AES Maritza has been collecting receivables from NEK in a timely manner since 2016. However, NEK's liquidity position remains subject to political conditions and regulatory changes in Bulgaria.
The DG Comp is reviewing NEK’s PPA with AES Maritza pursuant to the European Union’s state aid rules. AES Maritza believes that its PPA is legal and in compliance with all applicable laws. For additional details see Key Trends and Uncertainties in Item 7.— Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K.
AES also owns an 89% economic interest in the St. Nikola wind farm with 156 MW of installed capacity. The power output of St. Nikola is sold to customers operating on the liberalized electricity market and the plant receives additional revenue per the terms of an October 2018 Contract for Premium with the state-owned Electricity Security Fund.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•regulatory changes in the Bulgarian power market;
•results of the DG Comp review;
•availability and load factor of the operating units;
•the level of wind resources for St. Nikola;
•spot market price volatility beyond the level of compensation through the Contract for Premium for St. Nikola; and
•NEK's ability to meet the payment terms of the PPA contract with Maritza.
Regulatory Framework and Market Structure — The electricity sector in Bulgaria allows both regulated and competitive segments. In its capacity as the public provider of electricity, NEK acts as a single buyer and seller for all regulated transactions on the market. Electricity outside the regulated market trades on one of the platforms of the Independent Bulgarian Electricity Exchange day-ahead market, intra-day market, or bilateral contracts market. Bulgaria is working with the European Commission on the implementation of a model that allows for a gradual phase-out of regulated energy prices.
Bulgaria’s power sector is supported by a diverse generation mix, universal access to the grid, and numerous cross-border connections with neighboring countries. In addition, it plays an important role in the energy balance in the Balkan region.
Bulgaria has 13 GW of installed capacity enabling the country to meet and exceed domestic demand and export energy. Installed capacity is primarily thermal (45%), hydro (25%), and nuclear (16%).
Environmental Regulation — In 2017, new EU environmental standards were enacted that regulate emissions from the combustion of solid fuels for large combustion plants, known as the Best Available Techniques Reference Document for Large Combustion Plants, which applies to AES Maritza. AES Maritza was granted a derogation with respect to these standards and a formal decision for the preliminary execution of that derogation was made by the Bulgarian environmental authorities in February 2021. A third-party appeal with respect to the derogation has been
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made; however, while such appeal is considered, the preliminary execution of that derogation is in full force and effect.
In December 2019, the EU approved the European Green New Deal, a framework document that sets out how to make Europe climate-neutral by 2050. In response, in October 2020, Bulgaria submitted an updated version of the Integrated Energy and Climate Plan of the Republic of Bulgaria 2021-2030 ("IECP"), with national targets to contribute to the EU decarbonization targets, which does not include specific commitments to phase out coal plants before 2030. The IECP emphasizes the socio-economic importance of the indigenous coal industry in Bulgaria and the potential for indigenous coal to provide resources for electricity generation in the next 60 years while contributing to Bulgaria's energy and national security. There are currently no EU or Bulgarian regulations that limit the ability of AES Maritza to operate.
Business Description — In Jordan, AES has a 37% controlling interest in Amman East, a 381 MW oil/gas-fired plant fully contracted with the national utility under a 25-year PPA expiring in 2033, a 36% controlling interest in the IPP4 plant, a 250 MW oil/gas-fired peaker plant fully contracted with the national utility until 2039, and a 36% controlling interest in a 52 MW solar plant fully contracted with the national utility under a 20-year PPA expiring in 2039. We consolidate the results in our operations as we have a controlling interest in these businesses.
On November 10, 2020, AES executed a sale and purchase agreement to sell approximately 26% effective ownership interest in both the Amman East and IPP4 plants. The sale is expected to close in the first half of 2021 subject to customary approvals, including lender consents.
Regulatory Framework and Market Structure — The Jordan electricity transmission market is a single-buyer model with the state-owned National Electric Power Company ("NEPCO") responsible for transmission. NEPCO generally enters into long-term PPAs with IPPs to fulfill energy procurement requests from distribution utilities. The sector is prioritizing renewable energy development, with 2,400 MW of renewable energy installed capacity expected by the end of 2021, 2,129 MW of which is already connected to the grid.
Development Strategy — India is a high-growth market for renewables and battery energy storage. AES owns and operates a test 10 MW BESS in Delhi city, located inside a substation of Tata Power Delhi Distribution Limited ("TPDDL"). The BESS is integrated with the TPDDL distribution system and provides various frequency regulation services. Discussions of the commercial opportunities with TPDDL are ongoing. Leveraging the Delhi BESS experience, we are approaching similar use case opportunities with other customers in India.
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Fluence and Uplight are unconsolidated entities and their results are reported as Net equity in earnings of affiliates on our Consolidated Statements of Operations. 5B is a cost method investment and AES will record income only when it receives dividends from 5B.
Business Description — Fluence, AES' joint venture with Siemens, is a global energy storage technology and services company aligned with the AES strategy of becoming less carbon intensive. Fluence represents the combination of two global leaders in utility-scale, battery-based energy storage, bringing together the AES Advancion and Siemens Siestorage platforms, the capabilities and expertise of the two partners, and the global sales presence of Siemens.
In December 2020, Fluence entered into an agreement with the QIA whereby QIA will invest $125 million in Fluence. Following the completion of the transaction, which is expected in the second quarter of 2021, AES and Siemens are expected to each own approximately 44% of Fluence.
Key Financial Drivers — Fluence's financial results are driven by the growth in its product revenue and an efficient cost structure that is expected to benefit from increased scale. Fluence’s pipeline of potential projects is global, with approximately 50% being located outside the U.S.
Regulatory Framework and Market Structure — The grid-connected energy storage sector is expanding rapidly with over 5 GW of projects publicly announced in 2020. By incorporating energy storage across the electric power network, utilities and communities around the world will optimize their infrastructure investments, increase network flexibility and resiliency, and accelerate cost-effective integration of renewable electricity generation. Fluence is positioned to be a leading participant in this growth, accounting for approximately 15% of the storage market across their target markets in 2020.
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Business Description — The Company holds an equity interest in Uplight as part of its digitization and growth strategy. Uplight offers a comprehensive digital platform for utility customer engagement. Uplight provides software and services to approximately 80 of the world’s leading electric and gas utilities, principally in the U.S., with the mission of motivating and enabling energy users and providers to transition to a clean energy ecosystem. Uplight's solutions form a unified, end-to-end customer energy experience system that delivers innovative energy efficiency, demand response, and clean energy solutions quickly. Utility and energy company leaders rely on Uplight and its customer-focused digital energy experiences to improve customer satisfaction, reduce service costs, increase revenue, and reduce carbon emissions.
Key Financial Drivers — Uplight's financial results are driven by the rate of growth of new customers and the extension of additional services to existing customers. Revenue growth primarily drives its financial results, given the relative significance of fixed operating costs.
Development Strategy — AES' collaboration with Uplight is designed to create value for Uplight, AES and their respective customers. IPL and DP&L have implemented Uplight's consumer engagement solutions in support of energy efficiency and demand response programs. AES and Uplight are now working together to develop mobile-enabled engagement, e-mobility and advanced consumer and industrial offerings, with plans for future deployment of the Uplight platform in Latin America.
Business Description — The Company made a strategic investment in 5B, a solar technology innovator with the mission to accelerate the transformation of the world to a clean energy future. 5B's technology design enables solar projects to be installed up to three times faster, while allowing for up to two times more energy within the same footprint as traditional plants.
Key Financial Drivers — 5B is a cost method investment and AES will record income only when it receives dividends from 5B. 5B is in the beginning of its growth mode and is expanding its ecosystem for global reach.
Development Strategy — In addition to a large global market for third party projects, we believe there is an addressable market of nearly 5 GW across our development pipeline. AES expects to utilize this technology in conjunction with ongoing automation and digital initiatives to speed up delivery time and lower costs. 5B technology has been deployed at a 2 MW AES project in Panama and is expected to be deployed at a portion of the 180 MW Andes Solar 2b project to be constructed in Chile.
Environmental and Land-Use Regulations
The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion residuals), and certain air emissions, such as SO2, NOX, particulate matter, mercury, and other hazardous air pollutants. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries, and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors—Our operations are subject to significant government regulation and could be adversely affected by changes in the law or regulatory schemes; Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR; Our businesses are subject to stringent environmental laws, rules and regulations; and 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 in this Form 10-K. For a discussion of the laws and regulations of individual countries within each SBU where our subsidiaries operate, see discussion within Item 1.—Business of this Form 10-K under the applicable SBUs.
Many of the countries in which the Company does business have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from electric power generation or distribution assets. In addition, international projects funded by the International Finance Corporation, the private sector lending arm of the World Bank, or many other international lenders are subject to World Bank environmental standards or similar standards, which tend to be more stringent than local country standards. The Company often has used advanced generation technologies in order to minimize environmental impacts, such as combined fluidized bed boilers and advanced gas turbines, and environmental
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control devices such as flue gas desulphurization for SO2 emissions and selective catalytic reduction for NOx emissions.
Environmental laws and regulations affecting electric power generation and distribution facilities are complex, change frequently, and have become more stringent over time. The Company has incurred and will continue to incur capital costs and other expenditures to comply with these environmental laws and regulations. The Company may be required to make significant capital or other expenditures to comply with these regulations. There can be no assurance that the businesses operated by the subsidiaries of the Company will be able to recover any of these compliance costs from their counterparties or customers such that the Company's consolidated results of operations, financial condition, and cash flows would not be materially affected.
Various licenses, permits, and approvals are required for our operations. Failure to comply with permits or approvals, or with environmental laws, can result in fines, penalties, capital expenditures, interruptions, or changes to our operations. Certain subsidiaries of the Company are subject to litigation or regulatory action relating to environmental permits or approvals. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action.
United States Environmental and Land-Use Legislation and Regulations
In the United States, the CAA and various state laws and regulations regulate emissions of air pollutants, including SO2, NOX, particulate matter, GHGs, mercury, and other hazardous air pollutants. Certain applicable rules are discussed in further detail below.
CSAPR — CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. The CSAPR required significant reductions in SO2 and NOX emissions from power plants in many states in which subsidiaries of the Company operate. The Company is required to comply with the CSAPR in several states, including Ohio, Indiana, and Maryland. The CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. The Company complies with CSAPR through operation of existing controls and purchases of allowances on the open market, as needed.
On October 26, 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS ("CSAPR Update Rule"). The CSAPR Update Rule finds that NOX ozone season emissions in 22 states (including Indiana, Maryland, and Ohio) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS, and, accordingly, the EPA issued federal implementation plans that both updated existing CSAPR NOX ozone season emission budgets for electric generating units within these states and implemented these budgets through modifications to the CSAPR NOX ozone season allowance trading program. Implementation started in the 2017 ozone season (May-September 2017). Affected facilities began to receive fewer ozone season NOX allowances in 2017, resulting in the need to purchase additional allowances. Additionally, on September 13, 2019, the D.C. Circuit remanded a portion of the CSAPR Update Rule to the EPA. On October 30, 2020, the EPA issued a proposed rule addressing 21 states’ (including Maryland and Indiana) outstanding “good neighbor” obligations with respect of the 2008 ozone NAAQS. The proposed rule could result in affected facilities receiving fewer ozone season NOX allowances as soon as the 2021 ozone season. While the Company's additional CSAPR compliance costs to date have been immaterial, the future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time, but it could be material if certain facilities will need to purchase additional allowances based on reduced allocations.
New Source Review ("NSR") — The NSR requirements under the CAA impose certain requirements on major emission sources, such as electric generating stations, if changes are made to the sources that result in a significant increase in air emissions. Certain projects, including power plant modifications, are excluded from these NSR requirements, if they meet the routine maintenance, repair and replacement ("RMRR") exclusion of the CAA. There is ongoing uncertainty, and significant litigation, regarding which projects fall within the RMRR exclusion. Over the past several years, the EPA has filed suits against coal-fired power plant owners and issued NOVs to a number of power plant owners alleging NSR violations. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action, including an NOV issued by the EPA against IPL concerning NSR and prevention of significant deterioration issues under the CAA.
If NSR requirements are imposed on any of the power plants owned by the Company's subsidiaries, the results could have a material adverse impact on the Company's business, financial condition, and results of operations.
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Regional Haze Rule — The EPA's "Regional Haze Rule" is intended to reduce haze and protect visibility in designated federal areas, and sets guidelines for determining the best available retrofit technology ("BART") at affected plants and how to demonstrate "reasonable progress" toward eliminating man-made haze by 2064. The Regional Haze Rule required states to consider five factors when establishing BART for sources, including the availability of emission controls, the cost of the controls, and the effect of reducing emission on visibility in Class I areas (including wilderness areas, national parks, and similar areas). The statute would require compliance within five years after the EPA approves the relevant SIP or issues a federal implementation plan, although individual states may impose more stringent compliance schedules. In September 2017, the EPA published a final rule affirming the continued validity of the EPA's previous determination allowing states to rely on the CSAPR to satisfy BART requirements. All of the Company’s facilities that are subject to BART comply by meeting the requirements of CSAPR.
The second phase of the Regional Haze Rule began in 2019. States must submit regional haze plans for this second implementation period in 2021 to demonstrate reasonable progress towards reducing visibility impairment in Class I areas. States may need to require additional emissions controls for visibility impairing pollutants, including on BART sources, during the second implementation period. We currently cannot predict the impact of this second implementation period, if any, on any of our Company’s U.S. subsidiaries.
NAAQS — Under the CAA, the EPA sets NAAQS for six principal pollutants considered harmful to public health and the environment, including ozone, particulate matter, NOX, and SO2, which result from coal combustion. Areas meeting the NAAQS are designated "attainment areas" while those that do not meet the NAAQS are considered "nonattainment areas." Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.
Based on the current and potential future ambient air standards, certain of the states in which the Company's subsidiaries operate have determined or will be required to determine whether certain areas within such states meet the NAAQS. Some of these states may be required to modify their State Implementation Plans to detail how the states will attain or maintain their attainment status. As part of this process, it is possible that the applicable state environmental regulatory agency or the EPA may require reductions of emissions from our generating stations to reach attainment status for ozone, fine particulate matter, NOX, or SO2. The compliance costs of the Company's U.S. subsidiaries could be material.
Beginning January 1, 2017, IPL Petersburg has been required to meet reduced SO2 limits established in a final rule published by IDEM in 2015 in accordance with a new one-hour SO2 NAAQS of 75 parts per billion. Improvements to the existing flue gas desulfurization systems at IPL’s Petersburg station were required to meet the emission limits imposed by the rule. The IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million. On August 17, 2020, the EPA approved the reduced SO2 limits as part of a revised Indiana State Implementation Plan concluding that Indiana has appropriately demonstrated that the plan provides for attainment of the 2010 SO2 NAAQS.
Greenhouse Gas Emissions — In January 2011, the EPA began regulating GHG emissions from certain stationary sources, including a pre-construction permitting program for certain new construction or major modifications, known as the PSD. If future modifications to our U.S.-based businesses' sources become subject to PSD for other pollutants, it may trigger GHG BACT requirements and the cost of compliance with such requirements may be material.
On October 23, 2015, the EPA's rule establishing NSPS for new electric generating units became effective, establishing CO2 emissions standards for newly constructed coal-fueled electric generating plants, which reflects the partial capture and storage of CO2 emissions from the plants. The EPA also promulgated NSPS applicable to modified and reconstructed electric generating units, which will serve as a floor for future BACT determinations for such units. The NSPS could have an impact on the Company's plans to construct and/or modify or reconstruct electric generating units in some locations. On December 20, 2018, the EPA published proposed revisions to the final NSPS for new, modified, and reconstructed coal-fired electric utility steam generating units proposing that the best system of emissions reduction for these units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration, as was finalized in the 2015 final NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal. Challenges to the GHG NSPS
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are being held in abeyance at this time.
On August 31, 2018, the EPA published in the Federal Register proposed Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units, known as the Affordable Clean Energy (ACE) Rule. On July 8, 2019, the EPA published the final ACE Rule along with associated revisions to implementing regulations. The final ACE Rule established CO2 emission rules for existing power plants under CAA Section 111(d) and replaced the EPA's 2015 Clean Power Plan Rule (CPP). In accordance with the ACE Rule, the EPA determined that heat rate improvement measures are the best system of emissions reductions for existing coal-fired electric generating units. The final rule requires states, including Indiana and Maryland, develop a State Plan to establish CO2 emission limits for designated facilities, including IPL Petersburg's and AES Warrior Run's coal-fired electric generating units. States have three years to develop their plans under the rule. On February 19, 2020, Indiana published a First Notice for the Indiana ACE Rule indicating that IDEM intends to determine the best system of emissions reductions and CO2 standards for affected units. Impacts remain largely uncertain because Indiana's State Plan has not yet been developed. On January 19, 2021, the D.C. Circuit vacated and remanded to the EPA the ACE Rule, although the parties have an opportunity to request a rehearing at the D.C. Circuit or seek a review of the decision by the U.S. Supreme Court. The impact of this decision remains uncertain.
On November 4, 2020, the U.S. withdrawal from the Paris Agreement became effective. However, on January 20, 2021, President Biden signed and submitted an instrument for the U.S. to rejoin the Paris Agreement effective February 19, 2021. As such, there is some uncertainty with respect to the impact of GHG rules on IPL. The GHG BACT requirements will not apply at least until we construct a new major source or make a major modification of an existing major source, and the NSPS will not require us to comply with an emissions standard until we construct a new electric generating unit. We do not have any planned major modifications of an existing source or plans to construct a new major source at this time which are expected to be subject to these regulations. Furthermore, the EPA, states, and other utilities are still evaluating potential impacts of the GHG regulations in our industry. In light of these uncertainties, we cannot predict the impact of the EPA’s current and future GHG regulations on our consolidated results of operations, cash flows, and financial condition, but it could be material.
Due to the future uncertainty of these regulations and associated litigation, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the ACE Rule, should it be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the EPA that rescinds or substantively revises the NSPS, it could impact any Company plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impact on our business, financial condition, or results of operations.
Cooling Water Intake — The Company's facilities are subject to a variety of rules governing water use and discharge. In particular, the Company's U.S. facilities are subject to the CWA Section 316(b) rule issued by the EPA that seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the best technology available ("BTA") for cooling water intake structures. On August 15, 2014, the EPA published its final standards based on CWA Section 316(b) which require certain subject facilities to choose among seven BTA options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, are required to reduce entrainment of aquatic organisms. It is possible that this decision-making process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility to increase generation capacity are required to reduce both impingement and entrainment. It is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.
AES Southland's current plan is to comply with the SWRCB OTC Policy by shutting down and permanently retiring all existing generating units at AES Alamitos, AES Huntington Beach, and AES Redondo Beach that utilize OTC by the compliance dates included in the OTC Policy. New air-cooled combined cycle gas turbine generators and battery energy storage systems will be constructed at the AES Alamitos and AES Huntington Beach generating stations, and there is currently no plan to replace the OTC generating units at the AES Redondo Beach generating station. The execution of the implementation plan for compliance with the SWRCB's OTC Policy is entirely dependent on the Company's ability to execute on long-term PPAs to support project financing of the replacement generating units at AES Alamitos and AES Huntington Beach. The SWRCB reviews the implementation plan and latest information on OTC generating unit retirement dates and new generation availability to evaluate the impact on electrical system reliability and OTC compliance dates for specific units.
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The Company’s California subsidiaries have signed 20-year term PPAs with Southern California Edison for the new generating capacity, which have been approved by the California Public Utilities Commission. Construction of new generating capacity began in June 2017 at AES Huntington Beach and July 2017 at AES Alamitos. The new air-cooled combined cycle gas turbine generators were constructed at the AES Alamitos and AES Huntington Beach generating stations. Certain OTC units were required to be retired in 2019 to provide interconnection capacity and/or emissions credits prior to startup of the new generating units, and the remaining AES OTC generating units in California will be shutdown and permanently retired by the OTC Policy compliance dates for these units. On January 23, 2020, the Statewide Advisory Committee on Cooling Water Intake Structures adopted a recommendation to present to the SWRCB to extend the OTC compliance dates for AES Huntington Beach and AES Alamitos until December 31, 2023 and AES Redondo Beach until December 31, 2021. On September 1, 2020, in response to a request by the state’s energy, utility, and grid operators and regulators, the SWRCB approved amendments to its OTC Policy. The SWRCB OTC Policy previously required the shutdown and permanent retirement of all remaining OTC generating units at AES Alamitos, AES Huntington Beach, and AES Redondo Beach by December 31, 2020. The amendment extends the deadline for shutdown and retirement of AES Alamitos and AES Huntington Beach’s remaining OTC generating units to December 31, 2023 and extends the deadline for shutdown and retirement of AES Redondo Beach’s remaining OTC generating units to December 31, 2021 (the “AES Redondo Beach Extension”). In October 2020, the cities of Redondo Beach and Hermosa Beach filed a state court lawsuit challenging the AES Redondo Beach Extension. The outcome of the lawsuit is unclear. The respective facilities’ NPDES permits have been revised to allow the remaining OTC generating units at AES Alamitos, AES Huntington Beach, and AES Redondo Beach to continue operation beyond December 31, 2020 and in accordance with the amended OTC Policy.
Power plants are required to comply with the more stringent of state or federal requirements. At present, the California state requirements are more stringent and have earlier compliance dates than the federal EPA requirements, and are therefore applicable to the Company's California assets.
Challenges to the federal EPA's rule were filed and consolidated in the U.S. Court of Appeals for the Second Circuit, although implementation of the rule was not stayed while the challenges proceeded. On July 23, 2018, the U.S. Court of Appeals for the Second Circuit upheld the rule. The Second Circuit later denied a petition by environmental groups for rehearing. The Company anticipates that compliance with CWA Section 316(b) regulations and associated costs could have a material impact on our consolidated financial condition or results of operations.
Water Discharges — On June 29, 2015, the EPA and the U.S. Army Corps of Engineers ("the agencies") published a final rule defining federal jurisdiction over waters of the U.S. This rule, which initially became effective on August 28, 2015, could expand or otherwise change the number and types of waters or features subject to federal permitting. However, the agencies engaged in a two-step process to repeal the 2015 "Waters of the U.S." rule and replace it with a newly promulgated rule called the "Navigable Waters Protection" rule. The agencies completed the first step on October 22, 2019 by publishing the final rule repealing the 2015 “Waters of the U.S.” rule. In step two, the agencies issued a revised definition of waters of the U.S. on December 11, 2018 and released the prepublication version of the final "Navigable Waters Protection" rule on April 21, 2020. It is too early to determine whether the newly promulgated "Navigable Waters Protection" rule may have a material impact on our business, financial condition, or results of operations.
Certain of the Company's U.S.-based businesses are subject to NPDES permits that regulate specific industrial waste water and storm water discharges to the waters of the U.S. under the CWA. On August 28, 2012, the IDEM issued NPDES permits that set new water quality-based effluent discharge limits for the IPL Harding Street and Petersburg facilities with full compliance ultimately required by September 29, 2017. The deadline for Petersburg to commission a portion of the treatment system was subsequently extended to April 11, 2018.
On November 3, 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of the U.S. by steam-electric power plants through technology applications. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash and more stringent effluent limitations for flue gas desulfurization wastewater. The required compliance timelines for existing sources was to be established between November 1, 2018 and December 31, 2023. On September 18, 2017, the EPA published a final rule delaying certain compliance dates of the ELG rule for two years while it administratively reconsiders the rule. IPL Petersburg has installed a dry bottom ash handling system in response to the CCR rule and wastewater treatment systems in response to the NPDES permits in advance of the ELG compliance date. Other U.S. businesses already include dry handling of fly ash and bottom ash and do not generate flue gas desulfurization wastewater. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded portions of the
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EPA's 2015 ELG Rule related to legacy wastewaters and combustions residual leachate. On October 13, 2020, the EPA published final revisions to the 2015 ELG Rule related to flue gas desulfurization wastewater and bottom ash transport water, but did not address the portions of the ELG rule that were remanded by the U.S. Court of Appeals for the Fifth Circuit. Petitions have been filed for judicial review of the final revisions. It is too early to determine whether the outcome of the decision or current or future revisions to the ELG rule might have a material impact on our business, financial condition, and results of operations.
On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source, such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. On December 10, 2020, the EPA published a Notice of Availability of draft guidance memorandum addressing how the Supreme Court’s decision applies to NPDES permits. We are reviewing this decision and the EPA's draft guidance and it is too early to determine whether this decision may have a material impact on our business, financial condition, or results of operations.
Selenium Rule — In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant selenium in fresh water. NPDES permits may be updated to include selenium water quality-based effluent limits based on a site-specific evaluation process, which includes determining if there is a reasonable potential to exceed the revised final selenium water quality standards for the specific receiving water body utilizing actual and/or project discharge information for the generating facilities. As a result, it is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. IPL would seek recovery of these capital expenditures; however, there is no guarantee it would be successful in this regard.
Waste Management — On October 19, 2015, an EPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and currently operating landfills and surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. The primary enforcement mechanisms under this regulation would be actions commenced by the states and private lawsuits. On December 16, 2016, the Water Infrastructure Improvements for the Nation Act ("WIN Act") was signed into law. This 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. If this rule is finalized before Indiana or Puerto Rico establishes a state-level CCR permit program, AES CCR units in those locations could eventually be required to apply for a federal CCR permit from EPA. The EPA has indicated that it will implement a phased approach to amending the CCR Rule. On November 12, 2020, the EPA published its final Part B Rule, and indicated that it would address the issue of beneficial use of CCR for closure of ash ponds that are subject to forced closure in a separate and future rulemaking. This future rulemaking could impact IPL Petersburg plant’s ability to use CCR for closure of ash ponds. On August 28, 2020, the EPA published final amendments to the CCR Rule titled "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which amends certain regulatory provisions that govern CCR.
The CCR rule, current or proposed amendments to the CCR rule, the results of groundwater monitoring data, or the outcome of CCR-related litigation could have a material impact on our business, financial condition, and results of operations. IPL would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard.
On January 2, 2020, Puerto Rico Senate Bill 1221 was signed by the Puerto Rico Governor into law and became effective as Act 5-2020. Act 5-2020 prohibits the disposal and unencapsulated beneficial use of CCR, places restrictions on storage of CCR in Puerto Rico, and requires the Puerto Rico Department of Natural and Environmental Resources to develop implementation regulations. As such, it is not yet possible to determine whether this might have a material impact on our business, financial condition, and results of operations.
Comprehensive Environmental Response, Compensation and Liability Act of 1980 — This act, also known as "Superfund," may be the source of claims against certain of the Company's U.S. subsidiaries from time to time. There is ongoing litigation at a site known as the South Dayton Landfill where a group of companies already recognized as potentially responsible parties ("PRPs") have sued DP&L and other unrelated entities seeking a contribution toward the costs of assessment and remediation. DP&L is actively opposing such claims. In 2003, DP&L received notice that the EPA considers DP&L to be a PRP at the Tremont City landfill Superfund site. The EPA has taken no further action with respect to DP&L since 2003 regarding the Tremont City landfill. On October 16,
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2019, DP&L received a special notice that the EPA considers DP&L, along with other parties, to be a PRP for the clean-up of hazardous substances at a third-party landfill known as the Tremont City Barrel Site, located near Dayton, Ohio. The Company is unable to determine whether there will be any liability, or the size of any liability that may ultimately be assessed against DP&L at these three sites, but any such liability could be material to DP&L.
Biden Administration Actions Affecting Environmental Regulations — On January 20, 2021, President Biden issued an Executive Order ("EO") titled “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing agencies to, among other tasks, review regulations issued under the prior Administration to determine whether they should be suspended, revoked, or revised. As provided for by the EO, the EPA submitted a letter to the DOJ seeking to obtain abeyances or stays of proceedings in pending litigation that seeks review of regulations promulgated during the Trump Administration. The Biden Administration also issued a Memorandum titled “Regulatory Freeze Pending Review” directing agencies to refrain from proposing or issuing any rules until the Biden Administration has reviewed and approved those rules. These actions may have an impact on regulations that may affect our business, financial condition, or results of operations.
International Environmental Regulations
For a discussion of the material environmental regulations applicable to the Company's businesses located outside of the U.S., see Environmental Regulation under the discussion of the various countries in which the Company's subsidiaries operate in Item 1.—Business, under the applicable SBUs.
We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2020 total revenue. In our generation business, we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. Our utilities sell to end-user customers in the residential, commercial, industrial, and governmental sectors in a defined service area.
Human Capital Management
At AES, our people are instrumental to helping us meet the world’s energy needs. Supporting our people is a foundational value for AES. All of our actions are grounded in the shared values that shape AES’ culture: Safety First, Highest Standards, and All Together. The AES Corporation is led and managed by our Chief Executive Officer and the Executive Leadership Team with the guidance and oversight of our Board of Directors.
As of December 31, 2020, the Company and its subsidiaries had approximately 8,200 full time/permanent employees. The following chart lists our full time/permanent employees by SBU:
* On January 4, 2021, the merger of sPower as part of AES Clean Energy was completed and approximately 200 additional full time/permanent employees joined AES Clean Energy as part of the US and Utilities SBU.
As of December 31, 2020, approximately 45% of our U.S. employees were subject to collective bargaining agreements. Collective bargaining agreements between us and these labor unions expire at various dates ranging from 2021 to 2023. In addition, certain employees in non-U.S. locations were subject to collective bargaining
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agreements, representing approximately 65% of the non-U.S. workforce. Management believes that the Company's employee relations are favorable.
At AES, safety is one of our core values. Conducting safe operations at our facilities around the world, so that each person can return home safely, is the cornerstone of our daily activities and decisions. Safety efforts are led by our Chief Operating Officer and supported by safety committees that operate at the local site level. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety.
AES has established a Safety Management System (“SMS”) Global Safety Standard that applies to all AES employees, as well as contractors working in AES facilities and construction projects. The SMS requires continuous safety performance monitoring, risk assessment, and performance of periodic integrated environmental, health, and safety audits. The SMS provides a consistent framework for all AES operational businesses and construction projects to set expectations for risk identification and reduction, measure performance, and drive continuous improvements. The SMS standard is consistent with the OHSAS 18001/ISO 45001 standard, and during 2020 approximately 62% of our locations have elected to formally certify their SMS to the OHSAS 18001/ISO 45001 international standard. AES calculates lost time incident (“LTI”) rates for our employees and contractors based on OSHA standards, based on 200,000 labor hours, which equates to 100 workers who work 40 hours per week and 50 weeks per year. In 2020, there was a 37% decrease in LTI cases. In 2020, AES’ LTI Rate was 0.084 for AES People, 0.046 for operational contractors, and 0.069 for construction contractors. In 2020, the Company had one work-related fatality.
In response to the COVID-19 pandemic, we implemented significant changes that we determined were in the best interest of our employees, as well as the communities in which we operate. This includes having employees work from home to the extent they were able, while implementing additional safety measures for employees continuing critical on-site work.
We believe AES’ success depends on its ability to attract, develop, and retain key personnel. The skills, experience, and industry knowledge of key employees significantly benefit our operations and performance. We have a comprehensive approach to managing our talent and developing our leaders in order to ensure our people have the right skills for today and tomorrow, whether that requires us to build new business models or leverage leading technologies.
We emphasize employee development and training. To empower employees, we provide a range of development programs and opportunities, skills, and resources they need to be successful by focusing on experience and exposure, as well as formal programs including our ACE Academy for Talent Development and our Trainee Program.
At AES, we believe that our individual differences make us stronger. Our Diversity and Inclusion Program is led by our Diversity and Inclusion Officer. Governance and standards are guided by the Chief Human Resources Officer, with input from members of the Executive Leadership Team.
AES’ executive compensation philosophy emphasizes pay-for-performance. Our incentive plans are designed to reward strong performance, with greater compensation paid when performance exceeds expectations and less compensation paid when performance falls below expectations. We invest significant time and resources to ensure our compensation programs are competitive and reward the performance of our people. Every year, AES people who are not part of a collective bargaining agreement are eligible for an annual merit-based salary increase. In addition, individuals are eligible for a salary increase if they receive a significant promotion. For non-collectively bargained employees at certain levels in the organization, we offer annual incentives (bonus) and long-term compensation to reinforce the alignment between AES' employees and AES.
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The following individuals are our executive officers:
Bernerd Da Santos, 57 years old, has served as Executive Vice President and Chief Operating Officer since December 2017. Previously, Mr. Da Santos held several positions at AES, including Chief Operating Officer and Senior Vice President from 2014 to 2017, Chief Financial Officer, Global Finance Operations from 2012 to 2014, Chief Financial Officer of Global Utilities from 2011 to 2012, Chief Financial Officer of Latin America and Africa from 2009 to 2011, Chief Financial Officer of Latin America from 2007 to 2009, Managing Director of Finance for Latin America from 2005 to 2007, and VP and Controller of La Electricidad de Caracas ("EDC") (Venezuela). Prior to joining AES in 2000, Mr. Da Santos held a number of financial leadership positions at EDC. Mr. Da Santos is a member of the boards of AES Gener, Companhia Brasiliana de Energia, AES Tietê Energia, Compañia de Alumbrado Electrico de San Salvador, Empresa Electrica de Oriente, Compañia de Alumbrado Electrico de Santa Ana, Indianapolis Power & Light, IPALCO, AES Distributed Energy, and AES Mong Duong Power Company Limited. Mr. Da Santos holds a bachelor's degree with Cum Laude distinction in Business Administration and Public Administration from Universidad José Maria Vargas, a bachelor's degree with Cum Laude distinction in Business Management and Finance, and an MBA with Cum Laude distinction from Universidad José Maria Vargas.
Paul L. Freedman, 50 years old, has served as Executive Vice President, General Counsel and Corporate Secretary since February 2021. Prior to assuming his current position, Mr. Freedman was Senior Vice President and General Counsel from February 2018, Corporate Secretary from October 2018, Chief of Staff to the Chief Executive Officer from April 2016 to February 2018, Assistant General Counsel from 2014 to 2016, General Counsel, North America Generation, from 2011 to 2014, Senior Corporate Counsel from 2010 to 2011, and Counsel 2007 to 2010. Mr. Freedman is a member of the Boards of IPALCO, AES U.S. Investments, DP&L, the Business Council for International Understanding, and the Coalition for Integrity. Prior to joining AES, Mr. Freedman was Chief Counsel for credit programs at the U.S. Agency for International Development and he previously worked as an associate at the law firms of White & Case and Freshfields. Mr. Freedman received a B.A. from Columbia University and a J.D. from the Georgetown University Law Center.
Andrés R. Gluski, 63 years old, has been President, Chief Executive Officer and a member of our Board of Directors since September 2011 and is a member of the Innovation and Technology Committee. Prior to assuming his current position, Mr. Gluski served as Executive Vice President and Chief Operating Officer of the Company since March 2007. Prior to becoming the Chief Operating Officer of AES, Mr. Gluski was Executive Vice President and the Regional President of Latin America from 2006 to 2007. Mr. Gluski was Senior Vice President for the Caribbean and Central America from 2003 to 2006, Chief Executive Officer of EDC from 2002 to 2003 and Chief Executive Officer of AES Gener (Chile) in 2001. Prior to joining AES in 2000, Mr. Gluski was Executive Vice President and Chief Financial Officer of EDC, Executive Vice President of Banco de Venezuela (Grupo Santander), Vice President for Santander Investment, and Executive Vice President and Chief Financial Officer of CANTV (subsidiary of GTE). Mr. Gluski has also worked with the International Monetary Fund in the Treasury and Latin American Departments and served as Director General of the Ministry of Finance of Venezuela. From 2013 to 2016, Mr. Gluski served on President Obama's Export Council. Mr. Gluski is a member of the Board of Waste Management and Fluence. Mr. Gluski is also Chairman of the Americas Society/Council of the Americas. Mr. Gluski is a magna cum laude graduate of Wake Forest University and holds an M.A. and a Ph.D. in Economics from the University of Virginia.
Lisa Krueger, 57 years old, has served as Executive Vice President and President, US and Utilities SBU since February 2021. Prior to assuming her current position, Ms. Krueger was Senior Vice President and President of the US and Utilities SBU from September 2018. Prior to joining AES, Ms. Krueger served as an energy consultant from July 2017 to August 2018, Chief Commercial Officer of Cogentrix Energy Power Management, LLC, the portfolio management company of Carlyle Power Partners, from January 2017 to June 2017, and President and Chief Executive Officer of Essential Power, LLC from March 2014 to June 2017. Ms. Krueger also served as Vice President, Sustainable Development of First Solar, one of the world’s largest photovoltaic manufacturers and system integrators, where she led the development and implementation of various domestic and internal strategic plans focused on market and business development and served as the President of First Solar Electric. Prior to First Solar, Ms. Krueger held a variety of executive level positions with Dynegy, Inc., including Vice President, Enterprise Risk Control, Vice President, Northeast Commercial Operations, Vice President, Origination and Retail Operations, and Vice President, Environmental, Health & Safety. Ms. Krueger is the Executive Chair of the Boards of IPALCO, Indianapolis Power & Light and Dayton Power & Light and Chair of the Board of AES Southland Energy, AES Clean Energy and AES U.S. Investments. She also held a variety of leadership roles at Illinois Power, including positions
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in transmission planning and system operations, generation planning and system operations, and environmental, health & safety. Ms. Krueger has a Bachelor of Science degree in Chemical Engineering from the Missouri University of Science and Technology and an MBA from the Jones Graduate School of Business at Rice University.
Tish Mendoza, 45 years old, has served as Executive Vice President and Chief Human Resources Officer since February 2021. Prior to assuming her current position, Ms. Mendoza was Senior Vice President, Global Human Resources and Internal Communications and Chief Human Resources Officer from 2015, Vice President of Human Resources, Global Utilities from 2011 to 2012 and Vice President of Global Compensation, Benefits and HRIS, including Executive Compensation, from 2008 to 2011, and acted in the same capacity as the Director of the function from 2006 to 2008. Ms. Mendoza is a member of the boards of AES Chivor S.A., DP&L, AES Distributed Energy, and Uplight and sits on AES' compensation and benefits committees. Prior to joining AES, Ms. Mendoza was Vice President of Human Resources for a product company in the Treasury Services division of JP Morgan Chase and Vice President of Human Resources and Compensation and Benefits at Vastera, Inc, a former technology and managed services company. Ms. Mendoza earned certificates in Leadership and Human Resource Management, and a bachelor's degree in Business Administration and Human Resources.
Gustavo Pimenta, 42 years old, has served as Executive Vice President and Chief Financial Officer since January 2019. Prior to assuming his current position, Mr. Pimenta served as Deputy Chief Financial Officer from February 2018 to December 2018, Chief Financial Officer for the MCAC SBU from December 2014 to February 2018 and as Chief Financial Officer of AES Brazil from 2013 to December 2014. Prior to joining AES in 2009, Mr. Pimenta held various positions at Citigroup, including Vice President of Strategy and M&A in London and New York City. Mr. Pimenta is a member of the boards of J.M. Huber Corporation, IPALCO, AES Gener, AES Clean Energy, and AES U.S. Investments. Mr. Pimenta received a Bachelor’s degree in Economics from Universidade Federal de Minas Gerais and a Master’s degree in Economics and Finance from Fundação Getulio Vargas. He also participated in development programs in Finance, Strategy and Risk Management at New York University, University of Virginia’s Darden School of Business and Georgetown University.
How to Contact AES and Sources of Other Information
Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is (703) 522-1315. Our website address is http://www.aes.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 (the "Exchange Act") are posted on our website. After the reports are filed with, or furnished to the SEC, they are available from us free of charge. Material contained on our website is not part of and is not incorporated by reference in this Form 10-K. The SEC maintains an internet website that contains the reports, proxy and information statements and other information that we file electronically with the SEC at www.sec.gov.
Our CEO and our CFO have provided certifications to the SEC as required by Section 302 of the Sarbanes-Oxley Act of 2002. These certifications are included as exhibits to this Annual Report on Form 10-K.
Our CEO provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on May 4, 2020.
Our Code of Business Conduct ("Code of Conduct") and Corporate Governance Guidelines have been adopted by our Board of Directors. The Code of Conduct is intended to govern, as a requirement of employment, the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. Our Ethics and Compliance Department provides training, information, and certification programs for AES employees related to the Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering and associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to, or waivers from, the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.
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
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operations. 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 include risks associated with our operations, governmental regulation and laws, 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 in this Form 10-K and the Consolidated Financial Statements and related notes included elsewhere in this Form 10-K. If any of the following events actually occur, our business, financial results and financial condition could be materially adversely affected.
Risks Associated with our 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:
•changes in the availability of our generation facilities or distribution systems due to increases in scheduled and unscheduled plant outages, equipment failure, failure of transmission systems, labor disputes, disruptions in fuel supply, poor hydrologic and wind conditions, inability to comply with regulatory or permit requirements, or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, dam failures, tsunamis, explosions, terrorist acts, cyber attacks or other similar occurrences; and
•changes in our operating cost structure, including, but not limited to, increases in costs relating to gas, coal, oil and other fuel; fuel transportation; purchased electricity; operations, maintenance and repair; environmental compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental emission equipment; transmission access; and insurance.
Our businesses require reliable transportation sources (including related infrastructure such as roads, ports and rail), power sources and water sources to access and conduct operations. The availability and cost of this infrastructure affects capital and operating costs and levels of production and sales. Limitations, or interruptions in 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.
In addition, a portion of our generation facilities were constructed many years ago and may require significant capital expenditures for maintenance. The equipment at our plants requires 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. 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 operational procedures, preventative maintenance plans and specific programs supported by quality control systems, which may not prevent 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.
Furthermore, we and our affiliates are parties to material litigation and regulatory proceedings. See Item 3.— Legal Proceedings below. There can be no assurance that the outcomes of such matters will not have a material adverse effect on our consolidated financial position.
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We do a significant amount of business outside the U.S., including in developing countries.
A significant amount of our revenue is generated in developing countries and we intend to expand our business in certain developing countries in which AES has an existing presence. International operations, particularly in developing countries, entail significant risks and uncertainties, including:
•economic, social and political instability in any particular country or region;
•adverse changes in currency exchange rates;
•government restrictions on converting currencies or repatriating funds;
•unexpected changes in foreign laws and regulations or in trade, monetary, fiscal or environmental policies;
•high inflation and monetary fluctuations;
•restrictions on imports of solar panels, wind turbines, coal, oil, gas or other raw materials;
•threatened or consummated expropriation or nationalization of our assets by foreign governments;
•unexpected delays in permitting and governmental approvals;
•unexpected changes or instability affecting our strategic partners in developing countries;
•failure to comply with the U.S. Foreign Corrupt Practices Act, or other applicable anti-bribery regulations;
•unwillingness of governments, agencies, similar organizations or other counterparties to honor contracts;
•unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to AES and less beneficial to government or private party counterparties, against those counterparties;
•inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
•adverse changes in government tax policy and tax consequences of operating in multiple jurisdictions;
•difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and
•inability to attract and retain qualified personnel.
Developing projects in less developed economies also entails greater financing risks and such financing may only be available from multilateral or bilateral international financial institutions or agencies that require governmental guarantees for certain project and sovereign-related risks. There can be no assurance that project financing will be available.
Further, our operations may experience volatility in revenues and operating margin caused by regulatory and economic difficulties, political instability and currency devaluations, which may increase the uncertainty of cash flows from these businesses.
Any of these factors could have a material, adverse effect on our business, results of operations and financial condition.
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:
•plant availability in the markets generally;
•availability and effectiveness of transmission facilities owned and operated by third parties;
•competition and new entrants;
•seasonality, hydrology and other weather conditions;
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•transmission, transportation constraints, inefficiencies and/or availability;
•renewables source contribution to the supply stack;
•increased adoption of distributed generation;
•energy efficiency and demand side resources;
•available supplies of coal, natural gas, and crude oil and refined products;
•generating unit performance;
•natural disasters, terrorism, wars, embargoes, pandemics and other catastrophic events;
•energy, market and environmental regulation, legislation and policies;
•general economic conditions that impact demand and energy consumption; and
•bidding behavior and market bidding rules.
Wholesale power prices are declining in many markets which could impact our operations and opportunities for future growth.
The wholesale prices offered for electricity have declined significantly in recent years in many markets in which we operate 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 decreased 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 those 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. This trend 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 and have an adverse impact on our opportunities for new investments.
The COVID-19 pandemic, or the future outbreak of any other highly infectious or contagious diseases, could impact our business and operations.
The COVID-19 pandemic has severely impacted global economic activity, including electricity and energy consumption. COVID-19 or another pandemic could have material and adverse effects on our results of operations, financial condition and cash flows due to, among other factors:
•further decline in customer demand as a result of general decline in business activity;
•further destabilization of the markets and decline in business activity negatively impacting customers’ ability to pay for our services when due or at all, including downstream impacts, whereby the utilities’ customers are unable to pay monthly bills or receiving a moratorium from payment obligations, resulting in inability on the part of utilities to make payments for power supplied by our generation companies;
•decline in business activity causing our commercial and industrial customers to experience declining revenues and liquidity difficulties that impede their ability to pay for power that we supply;
•government moratoriums or other regulatory or legislative actions that limit changes in pricing, delay or suspend customers’ payment obligations or permit extended payment terms applicable to customers of our utilities or to our offtakers under power purchase agreements, in particular, to the extent that such measures are not mitigated by associated government subsidies or other support to address any shortfall or deficiencies in payments;
•claims by our PPA counterparties for delay or relief from payment obligations or other adjustments, including claims based on force majeure or other legal grounds;
•further decline in spot electricity prices;
•the destabilization of the markets and decline in business activity negatively impacting our customer growth in our service territories at our utilities;
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•negative impacts on the health of our essential personnel and on our operations as a result of implementing stay-at-home, quarantine, curfew and other social distancing measures;
•delays or inability to access, transport and deliver fuel to our generation facilities due to restrictions on business operations or other factors affecting us and our third-party suppliers;
•delays or inability to access equipment or the availability of personnel to perform planned and unplanned maintenance, which can, in turn, lead to disruption in operations;
•a deterioration in our ability to ensure business continuity, including increased cybersecurity attacks related to the work-from-home environment;
•further delays to our construction projects, including at our renewables projects, and the timing of the completion of renewables projects;
•delay or inability to receive the necessary permits for our development projects due to delays or shutdowns of government operations;
•delays in achieving our financial goals, strategy and digital transformation;
•deterioration of the credit profile of The AES Corporation and/or its subsidiaries and difficulty accessing the capital and credit markets on favorable terms, or at all, and a severe disruption and instability in the global financial markets, or deterioration in credit and financing conditions, which could affect our access to capital necessary to fund business operations or address maturing liabilities on a timely basis;
•delays or inability to complete asset sales on anticipated terms or to redeploy capital as set forth in our capital allocation plans;
•increased volatility in foreign exchange and commodity markets;
•deterioration of economic conditions, demand and other related factors resulting in impairments to goodwill or long-lived assets; and
•delay or inability in obtaining regulatory actions and outcomes that could be material to our business, including for recovery of COVID-19 related losses and the review and approval of our rates at our U.S. regulated utilities.
The impact of the COVID-19 pandemic also depends on factors, including the effectiveness and timing of vaccine development and distribution efforts, the development of more virulent COVID-19 variants as well as third-party actions taken to contain its spread and mitigate its public health effects. The COVID-19 pandemic presents material uncertainty that could adversely affect our generation facilities, transmission and distribution systems, development projects, energy storage sales by Fluence, and results of operations, financial condition and cash flows. The COVID-19 pandemic may also heighten many of the other risks described in this section.
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 our key electricity markets. 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 have also had a negative impact on China's economic growth. 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.
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 it will be sufficient or effective in light of all circumstances, 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. We cannot provide assurance that insurance coverage will continue to be
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available in the amounts or on terms similar to our current policies. 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 adequately 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.
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 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 not maintained, investment-grade credit ratings. Our generation businesses cannot always obtain government guarantees and if they do, the government may not have an investment grade credit rating. We have also located 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 will be effective.
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 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 us 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 areas impacted by the COVID-19 pandemic, which may cause delays and/or disruptions to our development projects or operations.
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The financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers. 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, and may have to sell power at market prices. A counterparty's breach by of a PPA or other agreement could also result in the breach of other agreements, including the affected businesses debt agreements. Any failure of a supplier or customer to fulfill its contractual obligations could have a material adverse effect on our financial results.
We may incur significant expenditures to adapt to our businesses to technological 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:
•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;
•advances in distributed and local power generation and energy storage that reduce demand for large-scale renewable electricity generation or impact our customers’ performance of long-term agreements; and
•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.
Cyber-attacks and data security breaches could harm our business.
Our business relies 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 a breach may:
•impact our operations, revenue, strategic objectives, customer and vendor relationships;
•expose us to legal claims and/or regulatory investigations and proceedings;
•require extensive repair and restoration costs for additional security measures to avert future attacks; and
•impair our reputation and limit our competitiveness for future opportunities.
•impact our financial and accounting systems and, subsequently, 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
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cover any losses we may experience. Further, we do not control certain of joint ventures or our equity method investments and cannot guarantee that their efforts will be effective.
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 at anticipated levels and the price of such spot power may increase substantially in times of low hydrology.
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 may also 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.
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Our development projects are subject to substantial uncertainties.
We are in various stages of developing and constructing power plants. Certain 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 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. In certain cases, our subsidiaries may enter into obligations in the development process even though they have not yet secured financing, PPAs, 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 without having financing, a PPA or critical permits in place (or enter into a PPA, procurement agreement or other agreement without agreed financing). If the project does not proceed, our subsidiaries may retain certain liabilities. Furthermore, we may undertake significant development costs and subsequently 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 reach commercial operation. If development efforts are not successful, we may abandon certain projects, resulting in, writing off the costs incurred, expensing related capitalized development costs incurred and incurring additional losses associated with any related contingent liabilities.
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 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 we would make and could impact the profitability and value of these joint ventures. In addition, if a joint venture partner becomes insolvent or bankrupt or is otherwise unable to meet its obligations to or share of liabilities for the joint venture, we may be responsible for meeting certain obligations of the joint ventures 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 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.
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. In particular, in the U.S., AES’ 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, including 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, there could be a material adverse impact on AES’ U.S. renewable growth opportunities, including fewer future PPAs or lower prices in future
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PPAs, decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing.
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 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 projects face considerable risk, including that favorable regulatory regimes expire or are adversely modified. At the development or acquisition stage, 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 or obtain third-party financing for these projects.
Fluctuations in currency exchange rates may impact our financial results and position.
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 U.S. 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 foreign subsidiaries report could cause significant fluctuations in our results. In addition, while our foreign operations expenses 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.
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.
Our utilities businesses may experience slower growth in customers or in customer usage.
Customer growth and customer usage in our utilities businesses are affected by external factors, including mandated energy efficiency measures, demand side management requirements, and economic and demographic
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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 not realize the anticipated benefits from significant investments and expenditures and have a material adverse effect on our 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. 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 a material increase in pension expense and future funding requirements. 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, which may necessitate additional cash contributions to the pension plans that could adversely affect our and our subsidiaries' liquidity. See Item 7.—Management's Discussion and Analysis—Critical Accounting Policies and Estimates—Pension and Other Postretirement Plans and Note 15—Benefit Plans included in Item 8.—Financial Statements and Supplementary Data.
Impairment of goodwill or long-lived assets would negatively impact our consolidated results of operations and net worth.
As of December 31, 2020, the Company had approximately $1.1 billion of goodwill, which represented approximately 3% of our total assets. 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, such as: deterioration in general economic conditions or our operating or regulatory environment; increased competitive environment; lower forecasted revenue; increase in fuel costs, particularly costs that we are unable to pass through 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, Gener's $868 million goodwill balance was considered to be "at risk" for impairment in 2020, largely due to the Chilean Government's announcement to phase out coal generation by 2040, and a decline in long-term energy prices. As a result of the long-lived asset impairments at Gener during the third quarter of 2020, the Company determined there was a triggering event requiring a reassessment of goodwill impairment at September 1, 2020. The Company determined the fair value of its Gener reporting unit exceeded its carrying value by 13%, and is not currently considered "at risk". We continue to monitor the Gener reporting unit for potential interim goodwill impairment triggering events. See Item 7.—Management's Discussion and Analysis—Key Trends and Uncertainties—Impairments. These types of events and the resulting analyses could result in goodwill impairment. Additionally, goodwill may be impaired if our acquisitions do not perform as expected. Long-lived assets are initially recorded at fair value, are amortized or depreciated over their estimated useful lives, and are evaluated for impairment only when impairment indicators, similar to those described above for goodwill, are present. Any impairment of goodwill or long-lived assets 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 and we may continue to make acquisitions. Although acquired businesses may have significant operating histories, we will have a limited or no history of owning and operating many of these businesses and possibly limited or no experience operating in the country or region where these businesses are located. Some of these businesses may have been government owned and some may be operated as part of a larger integrated utility prior to their acquisition. If we were to acquire any of these types of businesses, there can be no assurance that we will be successful in transitioning them to private ownership or that we will not incur unforeseen obligations or liabilities. Further, we may incur integration or
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other one-time costs that are greater than expected. Such businesses may not generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them; and the rate of return from such businesses may not justify our investment of capital to acquire them.
Risks associated with Governmental Regulation and Laws
Our operations are subject to significant government regulation and 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 obtaining expected or contracted increases in electricity tariff or contract rates or tariff adjustments for increased expenses, could adversely impact our results of operations. 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:
•changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs to be included in the rates we charge our customers, including but not limited to costs incurred to upgrade our power plants to comply with more stringent environmental regulations;
•changes in the determination of an appropriate rate of return on invested capital or that a utility's operating income or the rates it charges customers are too high, resulting in a rate reduction or consumer rebates;
•changes in the definition or determination of controllable or non-controllable costs;
•changes in tax law;
•changes in law or regulation that limit or otherwise affect the ability of our counterparties (including sovereign or private parties) to fulfill their obligations (including payment obligations) to us;
•changes in environmental law that impose additional costs or limit the dispatch of our generating facilities;
•changes in the definition of events that qualify as changes in economic equilibrium;
•changes in the timing of tariff increases;
•other changes in the regulatory determinations under the relevant concessions;
•other changes related to licensing or permitting which affect our ability to conduct business; or
•other changes that impact the short- or long-term price-setting mechanism in the our markets.
Furthermore, 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 efforts to comply with European Market Infrastructure Regulation, which includes regulations related to the trading, reporting and clearing of derivatives and similar regulations may be passed in other jurisdictions where we conduct business. Any of the above events may result in lower operating margins and financial results for the affected businesses.
Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR.
CCR generated at our current and former coal-fired generation plant sites, is currently handled and/or has been handled by: 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 EPA's final CCR rule provides that enforcement actions can be commenced by the 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.
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Some of our U.S. businesses are subject to the provisions of various laws and regulations administered by FERC, NERC and by state utility commissions that can have a material effect on our operations.
The AES Corporation is a registered electric holding company under the 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..
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 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.
FERC strongly encourages 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 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 U.S. utility businesses 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.
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.
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For example, in recent years, the EPA has issued 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 Item 1.—Business—Environmental and Land-Use Regulations.
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.
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 2020, the Company's subsidiaries operated businesses that had total CO2 emissions of approximately 47 million metric tonnes, approximately 16 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 are approximately 4 million metric tonnes (ownership adjusted). This 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. While actual emissions may vary substantially; 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.
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 electric utility steam generating units larger than 25 MW and in 2018 proposed revisions to the rule. In 2019, the EPA promulgated the Affordable Clean Energy (ACE) Rule which establishes heat rate improvement measures as the best system of emissions reductions for existing coal-fired electric generating units. On January 19, 2021, the D.C. Circuit vacated and remanded to EPA the ACE Rule although the parties have the opportunity to request a rehearing at the D.C. Circuit or seek a review of the decision by the U.S. Supreme Court. The impact of this decision and potential new or revised rules from the current Administration remains uncertain. 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, see Item 1.—Business—Environmental and Land-Use Regulations—U.S. Environmental and Land-Use Legislation and Regulations—Greenhouse Gas Emissions above. The Parties to the United Nations Framework Convention on Climate Change's 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 decarbonize the global economy and to further limit GHG emissions. The impact of GHG regulation on our operations will depend on a number of factors, including the degree and timing of GHG emissions
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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.
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, Hawaii, and the Puerto Rico Energy Public Policy Act, may adversely affect our operations. See Item 7.—Management's Discussion and Analysis—Key Trends and Uncertainties—Decarbonization Initiatives. Responding to these decarbonization initiatives, including developments in our strategy in line with these 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 that were dismissed against the Company because of its subsidiaries' GHG emissions. 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 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. Any actual or perceived failure to comply with the EU General Data Protection Regulation, the California Privacy Rights Act, the California Consumer Privacy Act, 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 have a material adverse impact on our results of operations and prospects.
Tax legislation initiatives or challenges to our tax positions could adversely affect us
We operate in the U.S. and various non-U.S. jurisdictions and 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, our effective tax rate or tax payments. The TCJA introduced significant changes to current U.S. federal tax law. These changes are complex, and the reaction to the federal tax changes by the individual states is still evolving. Our interpretations and assumptions around U.S. tax reform may evolve in future periods, which may materially affect our effective tax rate or tax payments. Additionally, President Biden proposed in his campaign platform changes to the corporate and U.S. individual tax system, including a possible increase in the corporate tax rate and the rate of
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tax non-U.S. earnings are subject to, that may introduce additional complexity or materially affect our effective tax rate or tax payments. See Item 7.—Management's Discussion and Analysis—Key Trends and Uncertainties.
Additionally, longstanding international tax norms that determine how and where cross-border international trade is subjected to tax are evolving. The OECD, in coordination with the G8 and G20, through its initial 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. In 2019, the OECD announced an expansion of these efforts in the form of a two-pillar approach that would create new nexus rules without reference to physical presence (Pillar One) and introduce a global minimum tax (Pillar Two). Blueprints for Pillar One and Pillar Two were released in the fourth quarter of 2020, with a stated goal of bringing the project to a conclusion by mid-2021. 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 difficult to assess whether the overall effect of such potential tax changes would be cumulatively positive or negative for our earnings and cash flow. Such changes could have a material adverse impact our results of operations.
Risks Related to our Indebtedness and Financial Condition
We have a significant amount of debt.
As of December 31, 2020, we had approximately $20 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings under The AES Corporation's revolving credit facility are unsecured. Most of the debt of The AES Corporation's subsidiaries, however, is secured by substantially all of the assets of those subsidiaries. A substantial portion of cash flow from operations must be used to make payments on our 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 level of indebtedness and related security could have other consequences, including:
•making it more difficult to satisfy debt service and other obligations;
•increasing our vulnerability to general adverse industry and economic conditions, including adverse changes in foreign exchange rates, interest rates and commodity prices;
•reducing available cash flow to fund other corporate purposes and grow our business;
•limiting our flexibility in planning for, or reacting to, changes in our business and the industry;
•placing us at a competitive disadvantage to our competitors that are not as highly leveraged; and
•limiting, along with financial and other restrictive covenants relating to such indebtedness, our ability to borrow additional funds, 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 may be greater than expected and our cash flows may not be sufficient to repay all of the outstanding debt as it becomes due. In that event, we may not be able to borrow money, sell assets, raise equity or otherwise raise funds on acceptable terms 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 that time. Any refinancing of our debt could result in higher interest rates or more onerous covenants that restrict our business operations. See Note 11—Debt included in Item 8.—Financial Statements and Supplementary Data for a schedule of our debt maturities.
The AES Corporation's ability to make payments on its outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries.
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. Business performance and local accounting and tax rules may also limit dividend distributions. Subsidiaries in foreign countries may also be prevented from distributing funds as a result of foreign governments restricting the repatriation of funds or the conversion of currencies. Our subsidiaries
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are separate and distinct legal entities and, unless they have expressly guaranteed 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 us.
We attempt to finance our domestic and foreign projects through non-recourse debt or "non-recourse financing" that requires 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. As of December 31, 2020, we had approximately $20 billion of outstanding indebtedness on a consolidated basis, of which approximately $3.4 billion was recourse debt of the Parent Company and approximately $16.4 billion was non-recourse debt. In some non-recourse financings, the Parent Company has explicitly agreed, in the form of guarantees, indemnities, letters of credit, letter of credit reimbursement agreements and agreements to pay, to undertake certain limited obligations and contingent liabilities, most of which will only be effective or will be terminated upon the occurrence of future events.
Certain of our subsidiaries are 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 $276 million as of December 31, 2020. While the lenders under our non-recourse financings generally do not have direct recourse to the Parent Company, such defaults under non-recourse financings can:
•reduce the Parent Company's receipt of subsidiary dividends, fees, interest payments, loans and other sources of cash because a subsidiary will typically be prohibited from distributing cash to the Parent Company during the pendency of any default;
•trigger The AES Corporation's obligation to make payments under any financial guarantee, letter of credit or other credit support provided to or on behalf of such subsidiary;
•trigger defaults in the Parent Company's outstanding debt. For example, The AES Corporation's revolving credit facility and outstanding senior notes include events of default for certain bankruptcy related events involving material subsidiaries and relating to accelerations of outstanding material debt of material subsidiaries or any subsidiaries that in the aggregate constitute a material subsidiary; or
•result in foreclosure on the assets that are pledged under the non-recourse financings, resulting in write-downs of assets and eliminating any and all potential future benefits derived from those assets.
None of the projects that are in default are owned by subsidiaries that, individually or in the aggregate, meet the applicable standard of materiality in The AES Corporation's revolving credit facility or other debt agreements 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 changes to our financial position and results of operations, 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 Parent Company indebtedness.
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, dividends on our common stock, acquisitions, construction and other project commitments, other equity commitments (including business development investments); equity repurchases; taxes and Parent Company overhead costs. Our principal sources of liquidity are: dividends and other distributions from our subsidiaries, proceeds from financings at the Parent Company, and proceeds from asset sales. See Item 7.—Management's Discussion and Analysis —Capital Resources and Liquidity. We believe that these sources will be adequate to meet our obligations for the foreseeable future, based on a number of material assumptions about 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; however, 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 our debt obligations at maturity and we may have to refinance such obligations. There can be no assurance that we will be successful in obtaining such refinancing on acceptable terms.
Our ability to grow our business depends on our ability to raise capital on favorable terms.
We rely on the capital markets as a source of liquidity for capital requirements not satisfied by operating cash
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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 availability of tax equity partners; the financial condition, performance and prospects of AES as well as our competitors; and changes in tax and securities laws. Should access to capital not be available to us, we may have to sell assets or cease further investments, including the expansion or improvement of existing facilities, any of which would affect our future growth.
A downgrade in the credit ratings of The AES Corporation or its subsidiaries could adversely affect our access to the capital markets, interest expense, liquidity or 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. Furthermore, counterparties may no longer be willing to accept general unsecured commitments by The AES Corporation to provide credit support. Accordingly, we 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, which reduces our available credit. There can be no assurance that counterparties will accept such guarantees or other assurances.
The market price of our common stock may be volatile.
The market price and trading volumes of our common stock could fluctuate substantially due to factors including general economic conditions, conditions in our industry and our markets, environmental and economic developments, and general credit and capital markets conditions, as well as developments specific to us, including risks described in this section, failing to meet our publicly announced guidance or key trends and other matters described in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
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.
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, 2020.
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
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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 and remediation costs are estimated to be approximately R$10 million to R$41 million ($2 million to $8 million), and there could be additional 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 February 2017, the EPA issued a NOV for DPL Stuart Station, alleging violations of opacity in 2016. On May 31, 2018, Stuart Station was retired, and on December 20, 2019, it was 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. On August 31, 2020, IPL reached a settlement with the EPA, the DOJ and IDEM, resolving these purported violations of the CAA at Petersburg Station. The settlement agreement, in the form of a proposed judicial consent decree, includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than IPL's current Title V air permit; payment of civil penalties totaling $1.5 million; a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.3 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023. If IPL does not meet the retirement obligation, it must install a Selective Non-Catalytic Reduction System on Unit 4. The proposed Consent Decree is subject to final review and approval by the U.S. District Court for the Southern District of Indiana, following a 30-day public comment period, which began upon publication in the Federal Register. On January 14, 2021, the United States and Indiana, on behalf of EPA and IDEM, respectively, filed a motion asking the court to enter the proposed Consent Decree, along with the United States’ response to the adverse public comments on the proposed settlements.
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. Potential outcomes of the CCC determination could include an order requiring AES Redondo Beach to perform a restoration and/or pay fines or penalties. AES Redondo Beach believes that it has meritorious arguments concerning the underlying CCC determination, but there can be no assurances that it will be successful. On March 27, 2020, AES Redondo Beach, LLC sold the site to an unaffiliated third-party purchaser that assumed the obligations contained within these proceedings. On May 26, 2020, CCC staff sent AES a Notice of Violation (NOV) directing AES to submit a Coastal Development Permit (“CDP”) application for the removal of the water pumps within the alleged wetlands. AES has submitted the CDP to the permitting authority, the City of Redondo Beach (“the City”), with respect to AES’s plans to disable or remove the pumps. The NOV also directed AES to submit technical analysis regarding additional water pumps located within onsite electrical vaults and a CDP application for their continued operation. AES has responded to the CCC, providing the requested analysis and seeking further discussion with the agency regarding the CDP. On October 14, 2020, the City deemed the CDP application to be complete and indicated a public hearing will be required, at which
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time AES must present additional information and analysis on the pumps within the alleged wetlands and the onsite electrical vaults.
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. A number of lawsuits have been filed in relation to the April 2018 Approval, some of which are still pending. To date, none of the lawsuits have negatively impacted the April 2018 Approval or the construction of the project. 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, and closing arguments were heard June 9-10, 2020. The parties are now awaiting the Tribunal’s decision in the First Arbitration. 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 jurisdictional objections raised by AES Gener and the Company to CNM’s piercing claims. The hearing on the jurisdictional objections, which was previously scheduled for October 2020, has been postponed to a date to be determined. 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 an opportunity to present reports and other evidence to challenge the grounds of the ruling. AES Gener has completed its presentation of evidence and awaits the Maritime Prosecution Office’s decision of the case. 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 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.
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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. In August 2020, at the request of the relevant AES companies, the case was transferred to a different civil court. 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 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. In August 2020, the Compliance Program for Guacolda Complex was approved by the SMA. Upon successful execution of the Compliance Program, the process is expected to conclude without sanctions and to not generate further actions. If the Ventanas Complex submission is approved by the SMA and satisfactorily fulfilled by AES Gener, the process is also expected to conclude without sanctions and to not generate further action.
In March 2020, Mexico’s Comisión Federal de Electricidad (“CFE”) served an arbitration demand upon AES Mérida III. CFE makes allegations that AES Mérida III is in breach of its obligations under a power and capacity purchase agreement ("Contract") between the two parties, which allegations relate to CFE’s own failure to provide fuel within the specifications of the Contract. CFE seeks to recover approximately $190 million in payments made to AES Merida under the Contract as well as approximately $431 million in alleged damages for having to acquire power from alternative sources in the Yucatan Peninsula. AES Mérida has filed an answer denying liability to CFE and asserting a counterclaim for damages due to CFE’s breach of its obligations. The parties submitted their respective initial briefs and supporting evidence in December 2020. After additional briefing, the evidentiary hearing will take place in November 2021. AES Mérida believes that it has meritorious defenses and claims and will assert them vigorously in the arbitration; however, there can be no assurances that it will be successful in its efforts.
ITEM 4. MINE SAFETY DISCLOSURES
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Recent Sales of Unregistered Securities
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 repurchases from the commencement of the Stock Repurchase Program in July 2010 through December 31, 2020 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, 2020, $264 million remained available for repurchase under the Stock Repurchase Program. No repurchases were made by The AES Corporation of its common stock in 2020, 2019, and 2018.
Our common stock is traded on the New York Stock Exchange under the symbol "AES."
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.
|Commencing the fourth quarter of||2020||2019||2018|
The fourth quarter 2020 cash dividend is to be paid in the first quarter of 2021. 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 revolving 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.
As of February 22, 2021, there were approximately 3,771 record holders of our common stock.
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THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE
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, 2015 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
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 of Financial Condition and Results of Operations and the Consolidated Financial Statements and the notes thereto included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K. The selected financial data for each of the years in the five year period ended December 31, 2020 have been derived from our audited Consolidated Financial Statements. Prior period amounts have been restated to reflect discontinued operations in all periods presented. Our historical results are not necessarily indicative of our future results.
Acquisitions, disposals, reclassifications, and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the Consolidated Financial Statements included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further explanation of the effect of such activities. Please also refer to Item 1A.—Risk Factors of this Form 10-K and Note 28—Risks and Uncertainties to the Consolidated Financial Statements included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for certain risks and uncertainties that may cause the data reflected herein not to be indicative of our future financial condition or results of operations.
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Selected Financial Data
|Statement of Operations Data for the Years Ended December 31:||(in millions, except per share amounts)|
Income (loss) from continuing operations (1)
|Income (loss) from continuing operations attributable to The AES Corporation, net of tax||43||302||985||(507)||(20)|
Income (loss) from discontinued operations attributable to The AES Corporation, net of tax (2)
|Net income (loss) attributable to The AES Corporation||$||46||$||303||$||1,203||$||(1,161)||$||(1,130)|
|Per Common Share Data|
|Basic earnings (loss) per share:|
|Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax||$||0.06||$||0.46||$||1.49||$||(0.77)||$||(0.04)|
|Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax||0.01||—||0.33||(0.99)||(1.68)|
|Net income (loss) attributable to The AES Corporation common stockholders||$||0.07||$||0.46||$||1.82||$||(1.76)||$||(1.72)|
|Diluted earnings (loss) per share:|
|Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax||$||0.06||$||0.45||$||1.48||$||(0.77)||$||(0.04)|
|Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax||0.01||—||0.33||(0.99)||(1.68)|
|Net income (loss) attributable to The AES Corporation common stockholders||$||0.07||$||0.45||$||1.81||$||(1.76)||$||(1.72)|
|Dividends Declared Per Common Share||$||0.58||$||0.55||$||0.53||$||0.49||$||0.45|
|Cash Flow Data for the Years Ended December 31:|
|Net cash provided by operating activities||$||2,755||$||2,466||$||2,343||$||2,504||$||2,897|
|Net cash used in investing activities||(2,295)||(2,721)||(505)||(2,599)||(2,136)|
|Net cash provided by (used in) financing activities||(78)||(86)||(1,643)||43||(747)|
|Total increase (decrease) in cash, cash equivalents and restricted cash||255||(431)||215||(172)||9|
|Cash, cash equivalents and restricted cash, ending||1,827||1,572||2,003||1,788||1,960|
|Balance Sheet Data at December 31:|
|Non-recourse debt (noncurrent)||15,005||14,914||13,986||13,176||13,731|
|Non-recourse debt (noncurrent)—Discontinued operations||—||—||—||—||758|
|Recourse debt (noncurrent)||3,446||3,391||3,650||4,625||4,671|
|Redeemable stock of subsidiaries||872||888||879||837||782|
|The AES Corporation stockholders' equity||2,634||2,996||3,208||2,465||2,794|
(1)Includes pre-tax gains on sales of business interests of $28 million, $984 million, and $29 million for the years ended December 31, 2019, 2018, and 2016, respectively, and pre-tax losses of $95 million and $52 million for the years ended December 31, 2020 and 2017, respectively; pre-tax impairment expense of $864 million, $185 million, $208 million, $537 million, and $1.1 billion for the years ended December 31, 2020, 2019, 2018, 2017, and 2016, respectively; other-than-temporary impairment of equity method investments of $202 million, $92 million. and $147 million for the years ended December 31, 2020, 2019, and 2018, respectively; income tax expense of $194 million and $675 million related to the one-time transition tax on foreign earnings, and income tax benefit of $77 million and expense of $39 million related to the remeasurement of deferred tax assets and liabilities to the lower corporate tax rate for the years ended December 31, 2018 and 2017, respectively; and net equity in losses of affiliates, primarily at Guacolda, of $123 million and $172 million, for the years ended December 31, 2020 and 2019, respectively. See Note 25—Held-for-Sale and Dispositions, Note 22—Asset Impairment Expense, Note 8—Investments in and Advances to Affiliates and Note 23—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
(2)Includes gain on sale of $199 million and loss on deconsolidation of $611 million related to Eletropaulo for the years ended December 31, 2018 and 2017, respectively, and impairment expense of $382 million and loss on sale of $737 million related to Sul for the year ended December 31, 2016. See Note 24—Discontinued Operations included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In 2020, AES delivered on or exceeded all strategic and financial objectives. We completed construction of 2.3 GW of new projects and signed long-term PPAs for 3 GW of renewable capacity. Fluence, our joint venture with Siemens, maintained its leading global market share with 1 GW of projects delivered or awarded in 2020. Finally, following our efforts to reduce recourse debt, our Parent Company's credit rating was upgraded to investment grade by S&P. 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 $0.39, from $0.45 to $0.06. This decrease reflects higher impairments and losses on sales in the current period, lower contributions from DP&L primarily driven by lower regulated rates as a result of the changes in the ESP, lower demand at IPL and DP&L due to milder weather, lower contributions from Colombia due to drier hydrology and lower generation due to a life extension project at Chivor, and prior year net insurance recoveries; partially offset by lower income tax expense, and higher contributions from Chile due to net gains from early contract terminations at Angamos and a positive impact due to incremental capitalized interest, from Brazil due to a favorable revision to the GSF liability, from Panama due to higher availability and improved hydrology, and in the U.S. due to commencement of operations of the Southland Energy CCGTs and a gain on sale of land.
Adjusted EPS, a non-GAAP measure, increased $0.08, from $1.36 to $1.44, mainly due to higher availability and improved hydrology in Panama, commencement of operations of the Southland Energy CCGTs and a gain on sale of land in the U.S., a favorable revision to the GSF liability in Brazil, a lower adjusted tax rate, and a positive impact in Chile due to incremental capitalized interest; partially offset by lower contributions from our utilities in the U.S. primarily driven by lower regulated rates as a result of the changes in DP&L's ESP and lower demand due to milder weather, lower contributions from Colombia due to drier hydrology and lower generation due to a life extension project at Chivor, and prior year net insurance recoveries.
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Review of Consolidated Results of Operations
|Years Ended December 31,||2020||2019||2018||% Change 2020 vs. 2019||% Change 2019 vs. 2018|
|(in millions, except per share amounts)|
|US and Utilities SBU||$||3,918||$||4,058||$||4,230||-3||%||-4||%|
|South America SBU||3,159||3,208||3,533||-2||%||-9||%|
|Corporate and Other||231||46||41||NM||12||%|
|US and Utilities SBU||638||754||733||-15||%||3||%|
|South America SBU||1,243||873||1,017||42||%||-14||%|
|Corporate and Other||120||39||58||NM||-33||%|
|Total Operating Margin||2,693||2,349||2,573||15||%||-9||%|
|General and administrative expenses||(165)||(196)||(192)||-16||%||2||%|
|Loss on extinguishment of debt||(186)||(169)||(188)||10||%||-10||%|
|Gain (loss) on disposal and sale of business interests||(95)||28||984||NM||-97||%|
|Asset impairment expense||(864)||(185)||(208)||NM||-11||%|
|Foreign currency transaction gains (losses)||55||(67)||(72)||NM||-7||%|
|Other non-operating expense||(202)||(92)||(147)||NM||-37||%|
|Income tax expense||(216)||(352)||(708)||-39||%||-50||%|
|Net equity in earnings (losses) of affiliates||(123)||(172)||39||-28||%||NM|
|INCOME FROM CONTINUING OPERATIONS||149||477||1,349||-69||%||-65||%|
|Loss from operations of discontinued businesses, net of income tax expense of $0, $0, and $2, respectively||—||—||(9)||—||%||-100||%|
|Gain from disposal of discontinued businesses, net of income tax expense of $0, $0, and $44, respectively||3||1||225||NM||-100||%|
|Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries||(106)||(175)||(364)||-39||%||-52||%|
|Less: Loss from discontinued operations attributable to noncontrolling interests||—||—||2||—||%||-100||%|
|NET INCOME ATTRIBUTABLE TO THE AES CORPORATION||$||46||$||303||$||1,203||-85||%||-75||%|
|AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:|
|Income from continuing operations, net of tax||$||43||$||302||$||985||-86||%||-69||%|
|Income from discontinued operations, net of tax||3||1||218||NM||-100||%|
|NET INCOME ATTRIBUTABLE TO THE AES CORPORATION||$||46||$||303||$||1,203||-85||%||-75||%|
|Net cash provided by operating activities||$||2,755||$||2,466||$||2,343||12||%||5||%|
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.
|80 | 2020 Annual Report|
Consolidated Revenue and Operating Margin
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Consolidated Revenue — Revenue decreased $529 million, or 5%, in 2020 compared to 2019. Excluding the unfavorable FX impact of $182 million, primarily in South America, this decrease was driven by:
•$229 million in Eurasia driven by the sale of the Northern Ireland businesses in June 2019 and lower generation in Vietnam;
•$140 million in US and Utilities mainly driven by a decrease in energy pass-through rates and lower demand due to the COVID-19 pandemic in El Salvador, lower regulated rates as a result of the changes in DP&L's ESP, lower retail sales demand at IPL and DPL primarily due to milder weather and COVID-19 pandemic impacts, and decreased capacity sales, at Southland due to unit retirements, and at DPL due to the sale and closure of generation facilities. These decreases were partially offset by increased capacity sales at Southland Energy due to the commencement of the PPAs; and
•$88 million in MCAC mainly driven by lower generation and volume pass-through fuel revenue in Mexico, the disconnection of the Estrella del Mar I power barge from the grid in Panama, and lower market prices, spot sales and demand in both the Dominican Republic and at the Colon combined cycle facility in Panama. These decreases were partially offset by higher LNG sales in the Dominican Republic, driven by the Eastern Pipeline COD in 2020.
These unfavorable impacts were partially offset by an increase of $115 million in South America driven by revenue recognized at Angamos for the early termination of contracts with Minera Escondida and Minera Spence and recovery of previously expensed payments from customers in Chile, partially offset by drier hydrology and lower generation in Colombia due to a life extension project being performed at the Chivor hydro plant, lower pass-through coal prices, spot prices, and lower generation in Chile, and lower energy and capacity prices (Resolution 31/2020) in Argentina.
|81 | 2020 Annual Report|
Consolidated Operating Margin — Operating margin increased $344 million, or 15%, in 2020 compared to 2019. Excluding the unfavorable impact of FX of $50 million, primarily in South America, this increase was driven by:
•$423 million in South America primarily due to the drivers discussed above, as well as a $184 million favorable revision to the GSF liability at Tietê related to the passage of a regulation providing concession extensions to hydro plants as compensation for prior period non-hydrological risk charges incorrectly assessed by the regulator; and
•$72 million in MCAC mostly due to higher availability at Changuinola due to the tunnel lining upgrade in 2019, improved hydrology in Panama, and higher LNG sales in the Dominican Republic, partially offset by prior year insurance recoveries associated with the lightning incident at the Andres facility in 2018, current year outage due to Andres steam turbine failure, and the disconnection of the Estrella del Mar I power barge from the grid in Panama.
These favorable impacts were partially offset by a decrease of $116 million in US and Utilities mostly due to lower regulated rates as a result of the changes in DP&L's ESP, lower retail sales demand at DPL and IPL primarily due to milder weather and COVID-19 pandemic impacts, lower capacity sales due to the retirement of units at Southland, a favorable revision to the ARO at DPL, and cost recoveries from DPL's joint owners of Stuart and Killen in 2019, partially offset by increased capacity sales at Southland Energy due to the commencement of the PPAs, and lower depreciation expense at Southland due to the extension of the water board permits.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
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;
|82 | 2020 Annual Report|
•$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.
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 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.
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 decreased $31 million, or 16%, to $165 million for 2020 compared to $196 million for 2019, primarily due to a higher reallocation of information technology costs to the SBUs and lower professional fees, partially offset by higher 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.
|83 | 2020 Annual Report|
Interest expense decreased $12 million, or 1%, to $1,038 million for 2020, compared to $1,050 million for 2019 primarily due to incremental capitalized interest in Chile and lower interest rates due to refinancing at the Parent Company, partially offset by lower capitalized interest due to the commencement of operations at the Alamitos and Huntington Beach facilities in February 2020.
Interest expense decreased $6 million, or 1%, to $1,050 million for 2019, compared to $1,056 million for 2018 primarily due to the debt refinancing at the Parent Company and DPL, and favorable foreign currency translation at AES Brasil, partially offset by lower capitalized interest due to the commencement of operations at Colon 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 income decreased $50 million, or 16%, to $268 million for 2020, compared to $318 million for 2019 primarily to the decrease of the LIBOR rate on receivables in Argentina, a lower loan receivable balance at Mong Duong, and a lower average interest rate at AES Brasil.
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.
Loss on extinguishment of debt
Loss on extinguishment of debt increased $17 million, or 10%, to $186 million for 2020, compared to $169 million for 2019. This increase was primarily due to losses of $145 million and $34 million at the Parent Company and DPL, respectively, resulting from the redemption of senior notes and a $16 million loss resulting from the Panama refinancing in 2020. These increases were partially offset by 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 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 the 2019 losses discussed above.
See Note 11—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Other income decreased $70 million, or 48%, to $75 million for 2020, compared to $145 million for 2019 primarily due to the prior year gains on insurance recoveries associated with property damage at the Andres facility and upgrading the tunnel lining at Changuinola, partially offset by the current year gain on sale of Redondo Beach land at Southland.
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 expense decreased $27 million, or 34%, to $53 million for 2020, compared to $80 million for 2019 primarily due to prior year losses recognized at commencement of sales-type leases at Distributed Energy, the prior year loss on disposal of assets at Changuinola associated with upgrading the tunnel lining, and lower defined benefit plan costs at IPL in 2020, partially offset by a loss on sale of Stabilization Fund receivables in Chile and compliance with an arbitration decision in 2020.
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
|84 | 2020 Annual Report|
the loss on disposal of assets resulting from damage associated with a lightning incident at the Andres facility in the Dominican Republic in 2018.
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
Loss on disposal and sale of business interests was $95 million for 2020, primarily due to the loss on sale of Uruguaiana and the loss on the settlement of the arbitration related to the sale of Kazakhstan HPPs, partially offset by the gain on sale of OPGC; as compared to a gain of $28 million for 2019 primarily due to the gain on sale of a portion of our interest in sPower's operating assets, the gain on the merger of Simple Energy to form Uplight, and the gain on transfer of Stuart and Killen, partially offset by the loss on sale of Kilroot and Ballylumford.
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.
See Note 25—Held-For-Sale and Dispositions and 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.
Asset impairment expense
Asset impairment expense increased $679 million to $864 million for 2020, compared to $185 million for 2019. This increase was primarily driven by a $781 million impairment related to certain coal-fired plants at AES Gener and a $30 million impairment of the Estrella del Mar I power barge in Panama, compared to a $115 million prior year impairment at Kilroot and Ballylumford upon meeting the held-for-sale criteria in 2019.
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 2018 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.
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:
|Years Ended December 31,||2020||2019||2018|
(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 gains of $57 million, losses of $31 million, and gains of $23 million on foreign currency derivative contracts for the years ended December 31, 2020, 2019 and 2018, respectively.
The Company recognized net foreign currency transaction gains of $55 million for the year ended December 31, 2020, primarily driven by realized and unrealized gains on foreign currency derivatives related to government receivables in Argentina and unrealized gains at the Parent Company resulting from the appreciation of intercompany receivables denominated in Euro.
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.
|85 | 2020 Annual Report|
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.
Other non-operating expense
Other non-operating expense was $202 million and $92 million in 2020 and 2019, respectively, due to the other-than-temporary impairment of the OPGC equity method investment. In December 2019, an other-than-temporary impairment of $92 million 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. In March 2020, the Company recognized an additional $43 million other-than-temporary impairment due to the economic slowdown. In June 2020, the Company agreed to sell its entire stake in the OPGC investment, resulting in an other-than-temporary impairment of $158 million.
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.
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 $136 million to $216 million in 2020 as compared to $352 million for 2019. The Company's effective tax rates were 44% and 35% for the years ended December 31, 2020 and 2019.
The net increase in the 2020 effective tax rate was primarily due to the 2020 impacts of the other-than-temporary impairment of the OPGC equity method investment and the loss on sale of the Company’s entire interest in AES Uruguaiana, partially offset by the recognition of a federal ITC for the Na Pua Makani wind facility in Hawaii. Further, the 2019 rate was impacted by the items described below. See Note 25—Held-for-Sale and Dispositions included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for details of the sales.
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. 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 included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for details of the sales.
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 addition information regarding these reduced rates.
Net equity in earnings (losses) of affiliates
Net equity in losses of affiliates decreased $49 million, or 28%, to $123 million in 2020, compared to $172 million in 2019. This was primarily driven by a $31 million increase in earnings due to lower long-lived asset impairments at Guacolda, Gener's 50%-owned equity affiliate, during 2020 as compared to 2019.
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
|86 | 2020 Annual Report|
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.
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 from discontinued operations
Net income from discontinued operations was $3 million and $1 million for the years ended December 31, 2020 and 2019, respectively, with no material drivers.
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.
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 $69 million, or 39%, to $106 million in 2020, compared to $175 million in 2019. This decrease was primarily due to:
•Lower earnings in Chile due to long-lived asset impairments at Gener, partially offset by net gains from early contract terminations at Angamos and lower interest expense due to incremental capitalized interest;
•Lower earnings in Colombia due to drier hydrology and a life extension project at the Chivor hydroelectric plant;
•Prior year insurance recoveries net of outages at Andres; and
•HLBV allocation of losses to noncontrolling interests at Distributed Energy.
These increases were partially offset by:
•Higher earnings in Brazil due to the favorable revision of the GSF liability; and
•Prior year losses on extinguishment of debt at Mong Duong and Colon.
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:
•Gains on sales of Electrica Santiago and CTNG in Chile in 2018;
•Lower earnings in Chile in 2019 primarily due to 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 in 2019 primarily due to lower hydrology and the outage at Changuinola as a result of upgrading the tunnel lining.
These decreases were partially offset by:
•Other-than-temporary impairment of Guacolda in 2018.
Net income attributable to The AES Corporation
Net income attributable to The AES Corporation decreased $257 million, or 85%, to $46 million in 2020, compared to $303 million in 2019. This decrease was primarily due to:
•Long-lived asset impairments at Gener and Panama;
•Net impact of current and prior year other-than-temporary impairments of OPGC;
•Higher losses on extinguishment of debt in the current year, primarily due to major refinancings at the Parent Company;
•Lower margins at our US and Utilities SBU;
|87 | 2020 Annual Report|
•Losses on sale of Uruguaiana and the Kazakhstan HPPs as a result of the final arbitration decision; and
•Prior year net insurance recoveries at Andres.
These decreases were partially offset by:
•Prior year long-lived asset impairments at Kilroot and Ballylumford;
•Net impact of current and prior year long-lived asset impairments at Guacolda;
•Prior year unrealized losses on foreign currency derivatives related to government receivables in Argentina;
•Higher margins at our South America and MCAC SBUs;
•Lower income tax expense;
•Lower interest expense due to incremental capitalized interest in Chile; and
•Gain on sale of land held by AES Redondo Beach at Southland.
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:
•Gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG and Electrica Santiago in 2018, net of tax;
•Long-lived asset impairments at Guacolda, Hawaii, Kilroot and Ballylumford, and other-than-temporary impairment at OPGC in 2019;
•Loss on sale at Kilroot and Ballylumford in 2019;
•Losses on extinguishment of debt at DPL, AES Gener, Mong Duong, and Colon in 2019;
•Losses recognized at commencement of sales-type leases at Distributed Energy in 2019;
•The impact of sold businesses in our Eurasia SBU;
•Lower margins at Argentina and Chile in 2019, primarily due to lower generation; and
•Lower margins at Changuinola in 2019, driven by the outage as a result of upgrading the tunnel lining and lower hydrology in Panama.
These decreases were partially offset by:
•Income tax expense in 2018 to finalize the initial impact of U.S. tax reform enacted in December 2017;
•Loss on extinguishment of debt at the Parent Company in 2018;
•Long-lived asset impairments at Shady Point and Nejapa, and other-than-temporary impairment at Guacolda in 2018;
•Gains on insurance proceeds in 2019, associated with the lightning incident at the Andres facility in 2018 and the Changuinola tunnel leak;
•Gain on sale of a portion of our interest in sPower’s operating assets and gain on disposal of Stuart and Killen at DPL in 2019; and
•Higher earnings at our US and Utilities SBU in 2019, primarily as a result of renewable projects that came online.
SBU Performance Analysis
We are organized into 4 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).
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.
|88 | 2020 Annual Report|
For the year ended December 31, 2020, the Company changed the definitions of Adjusted Operating Margin, Adjusted PTC and Adjusted EPS to exclude net gains at Angamos, one of our businesses in the South America SBU, associated with the early contract terminations with Minera Escondida and Minera Spence. We believe the inclusion of the effects of this non-recurring transaction would result in a lack of comparability in our results of operations and would distort the metrics that our investors use to measure us.
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; (c) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations, and office consolidation; and (d) net gains at Angamos, one of our businesses in the South America SBU, associated with the early contract terminations with Minera Escondida and Minera Spence. 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 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.
|Reconciliation of Adjusted Operating Margin (in millions)||Years Ended December 31,|
Noncontrolling interests adjustment (1)
|Unrealized derivative losses||24||11||19|
|Net gains from early contract terminations at Angamos||(182)||—||—|
Restructuring costs (2)
|Total Adjusted Operating Margin||$||1,728||$||1,705||$||1,928|
(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.
|89 | 2020 Annual Report|
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; (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations, and office consolidation; and (g) net gains at Angamos, one of our businesses in the South America SBU, associated with the early contract terminations with Minera Escondida and Minera Spence. 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, strategic decisions to dispose of or acquire business interests, retire debt or implement restructuring initiatives, and the non-recurring nature of the impact of the early contract terminations at Angamos, 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 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.
|Reconciliation of Adjusted PTC (in millions)||Years Ended December 31,|
|Income (loss) from continuing operations, net of tax, attributable to The AES Corporation||$||43||$||302||$||985|
|Income tax expense attributable to The AES Corporation||130||250||563|
|Unrealized derivative and equity securities losses||3||113||33|
|Unrealized foreign currency losses (gains)||(10)||36||51|
|Disposition/acquisition losses (gains)||112||12||(934)|
|Loss on extinguishment of debt||223||121||180|
|Net gains from early contract terminations at Angamos||(182)||—||—|
|Total Adjusted PTC||$||1,247||$||1,240||$||1,185|
|90 | 2020 Annual Report|
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; (g) net gains at Angamos, one of our businesses in the South America SBU, associated with the early contract terminations with Minera Escondida and Minera Spence; and (h) 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 remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests, retire debt or implement restructuring initiatives, the one-time impact of the 2017 U.S. tax law reform and subsequent period adjustments related to enactment effects, and the non-recurring nature of the impact of the early contract terminations at Angamos, 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.
|91 | 2020 Annual Report|
|Reconciliation of Adjusted EPS||Years Ended December 31,|
|Diluted earnings (loss) per share from continuing operations||$||0.06||$||0.45||$||1.48|
|Unrealized derivative and equity securities losses||0.01||0.17||(1)||0.05|
|Unrealized foreign currency losses (gains)||(0.01)||0.05||(2)||0.09||(3)|
|Disposition/acquisition losses (gains)||0.17||(4)||0.02||(5)||(1.41)||(6)|
|Loss on extinguishment of debt||0.33||(10)||0.18||(11)||0.27||(12)|
|Net gains from early contract terminations at Angamos||(0.27)||(13)||—||—|
|U.S. Tax Law Reform Impact||0.02||(14)||(0.01)||0.18||(15)|
|Less: Net income tax expense (benefit)||(0.26)||(16)||(0.11)||(17)||0.12||(18)|
(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 loss on sale of Uruguaiana of $85 million, or $0.13 per share, loss on sale of the Kazakhstan HPPs of $30 million, or $0.05 per share, as a result of the final arbitration decision, and advisor fees associated with the successful acquisition of additional ownership interest in AES Brasil of $9 million, or $0.01 per share; partially offset by gain on sale of OPGC of $23 million, or $0.03 per share.
(5)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.
(6)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.
(7)Amount primarily relates to asset impairments at Gener of $527 million, or $0.79 per share, other-than-temporary impairment of OPGC of $201 million, or $0.30 per share, impairments at our Guacolda and sPower equity affiliates, impacting equity earnings by $85 million, or $0.13 per share, and $57 million, or $0.09 per share, respectively; impairment at Hawaii of $38 million, or $0.06 per share, and impairment at Panama of $15 million, or $0.02 per share.
(8)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.
(9)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.
(10)Amount primarily relates to losses on early retirement of debt at the Parent Company of $146 million, or $0.22 per share, DPL of $32 million, or $0.05 per share, Angamos of $17 million, or $0.02 per share, and Panama of $11 million, or $0.02 per share.
(11)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.
(12)Amount primarily relates to loss on early retirement of debt at the Parent Company of $171 million, or $0.26 per share.
(13)Amount relates to net gains at Angamos associated with the early contract terminations with Minera Escondida and Minera Spence of $182 million, or $0.27 per share.
(14)Amount represents adjustment to tax law reform remeasurement due to incremental deferred taxes related to DPL of $16 million, or $0.02 per share.
(15)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.
(16)Amount primarily relates to income tax benefits associated with the impairments at Gener and Guacolda of $164 million, or $0.25 per share, and income tax benefits associated with losses on early retirement of debt at the Parent Company of $31 million, or $0.05 per share; partially offset by income tax expense related to net gains at Angamos associated with the early contract terminations with Minera Escondida and Minera Spence of $49 million, or $0.07 per share.
(17)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.
(18)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 $0.05 per share.
|92 | 2020 Annual Report|
US and Utilities SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
|For the Years Ended December 31,||2020||2019||2018||$ Change 2020 vs. 2019||% Change 2020 vs. 2019||$ Change 2019 vs. 2018||% Change 2019 vs. 2018|
Adjusted Operating Margin (1)
Adjusted PTC (1)
(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 2020 versus 2019
Operating Margin decreased $116 million, or 15%, which was driven primarily by the following (in millions):
|Decrease at DPL due to lower regulated retail margin primarily due to changes to DP&L’s ESP and lower volumes mainly from milder weather||$||(63)|
|Decrease due to the sale and closure of generation facilities at DPL, including a credit to depreciation expense in 2019 as a result of a reduction to an ARO liability and cost recoveries from DPL's joint owners of Stuart and Killen in the prior year||(50)|
|Decrease at Southland driven by higher losses from commodity derivatives and lower capacity sales due to unit retirements, partially offset by lower depreciation expense||(47)|
|Decrease at IPL primarily due to lower retail margin driven by lower volumes from milder weather and lower demand from the impact of COVID-19, partially offset by lower maintenance expense from scheduled plant outages||(36)|
|Decrease at Hawaii primarily driven by lower availability due to increasing forced outages and higher expenses related to the shortened useful life of the coal plant||(20)|
|Increase at Southland Energy due to the CCGT units beginning commercial operations during Q1 2020||113|
|Total US and Utilities SBU Operating Margin Decrease||$||(116)|
Adjusted Operating Margin decreased $82 million primarily due to the drivers above, adjusted for NCI and excluding unrealized gains and losses on derivatives and costs associated with dispositions of business interests.
Adjusted PTC decreased $64 million, primarily driven by the decrease in Adjusted Operating Margin described above and increased interest expense primarily at Southland Energy due to lower capitalized interest following completion of the CCGT units and new debt issuances, partially offset by a gain on sale of land held by AES Redondo Beach at Southland, lower pension expense at IPL, and an increase in allocation of earnings from equity affiliates driven by renewable projects that came online in 2020 at sPower.
Fiscal year 2019 versus 2018
Operating Margin increased $21 million, or 3%, which was driven primarily by the following (in millions):
|Increase at IPL primarily driven by higher retail rates following the 2018 rate order, partially offset by lower volumes due to unfavorable weather and higher maintenance expense related to distribution line clearance||$||59|
|Increase at DPL due to the 2018 distribution rate order, including the decoupling rider which is designed to eliminate the impacts of weather and demand, partially offset by changes to DPL's ESP||22|
|Decrease due to the sale and closure of generation facilities at Shady Point and DPL, including cost recoveries from DPL's joint owners of Stuart and Killen||(47)|
|Decrease in Puerto Rico mainly driven by an increase of rock ash disposal||(23)|
|Total US and Utilities SBU Operating Margin Increase||$||21|
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 $58 million, primarily driven by an increase in earnings attributable to AES as a result of contributions from new renewable projects and lower interest expense at DPL, partially offset by the decrease in Adjusted Operating Margin described above and a decrease in AFUDC for the Eagle Valley CCGT project at IPL.
|93 | 2020 Annual Report|
South America SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
|For the Years Ended December 31,||2020||2019||2018||$ Change 2020 vs. 2019||% Change 2020 vs. 2019||$ Change 2019 vs. 2018||% Change 2019 vs. 2018|
Adjusted Operating Margin (1)
Adjusted PTC (1)
(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. In addition, AES owned 24.35% of AES Brasil until August 2020 when ownership increased to 42.85%, and increased again to 44.13% in December 2020 due to acquisition of additional shares in the company.
Fiscal year 2020 versus 2019
Operating Margin increased $370 million, or 42%, which was driven primarily by the following (in millions):
|Increase in Chile primarily related to early contract terminations at Angamos||$||302|
|Increase in Brazil mainly due to a reduction in cost of sales as a result of a revision to the GSF liability, partially offset by depreciation of the Brazilian real against the USD||140|
|Recovery of previously expensed payments from customers in Chile||57|
|Lower reservoir levels as a result of the life extension project at Chivor during Q1 2020 and drier hydrology in Colombia||(108)|
|Lower capacity prices (Resolution 31/2020) in Argentina partially offset by the impact of new wind projects beginning commercial operations in 2020||(21)|
|Total South America SBU Operating Margin Increase||$||370|
Adjusted Operating Margin increased $51 million primarily due to the drivers above, adjusted for NCI and the net gains on early contract terminations at Angamos.
Adjusted PTC increased $30 million, mainly driven by the increase in Adjusted Operating Margin described above, as well as lower interest expense due to incremental capitalized interest at Alto Maipo. These positive impacts were partially offset by realized FX losses and lower interest income primarily driven by lower interest rates on CAMMESA receivables in Argentina, and higher interest expense in Brazil due to higher inflation rates.
Fiscal year 2019 versus 2018
Operating Margin decreased $144 million, or 14%, which was driven primarily by the following (in millions):
|Decrease in Argentina primarily driven by lower generation and lower energy and capacity prices as defined by resolution 1/2019, which modified generators' remuneration schemes||$||(59)|
|Decrease due to the depreciation of the Colombian peso and Brazilian real against the USD, offset by savings in fixed costs as a result of the depreciation of the Argentine peso||(38)|
|Decrease in Chile primarily due to lower contracted energy sales and lower efficient plant availability, partially offset by lower spot prices on energy purchases||(30)|
|Decrease due to the sale of Electrica Santiago and the transmission lines in 2018||(21)|
|Decrease in Chile primarily due to higher fixed costs associated with IT initiatives and realized FX losses related to forward instruments, partially offset by savings on employee expenses||(11)|
|Decrease in Brazil primarily driven by lower spot sales and prices, partially offset by higher contracted energy sales||(10)|
|Increase in Colombia due to higher spot prices primarily driven by drier system hydrology||30|
|Increase in Brazil due to new solar plants in operation||10|
|Total South America SBU Operating Margin Decrease||$||(144)|
Adjusted Operating Margin decreased $113 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC decreased $15 million, mainly driven by the decrease in Adjusted Operating Margin described above, partially offset by realized FX gains in Argentina and Chile in 2019 as compared to losses in 2018, and higher equity earnings in 2019 related to better operating results at Guacolda.
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The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions) for the periods indicated:
|For the Years Ended December 31,||2020||2019||2018||$ Change 2020 vs. 2019||% Change 2020 vs. 2019||$ Change 2019 vs. 2018||% Change 2019 vs. 2018|
Adjusted Operating Margin (1)
Adjusted PTC (1)
(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 2020 versus 2019
Operating Margin increased $72 million, or 15%, which was driven primarily by the following (in millions):
|Higher availability in Panama mainly due to the outage of Changuinola in 2019 for the tunnel lining upgrade||$||63|
|Increase in Panama driven by improved hydrology resulting in higher net spot market sales||43|
|Increase in Dominican Republic due to higher LNG sales margin driven by the Eastern Pipeline COD in 2020||27|
|Increase in Panama mainly driven by higher availability and capacity tank revenue and lower fixed costs, partially offset by lower energy sales margin at the Colon combined cycle plant||9|
|Decrease in Dominican Republic related to Andres facility due to steam turbine failure in 2020 and business interruption insurance recovered in 2019||(49)|
|Decrease in Panama driven by lower margin at the Estrella de Mar I power barge mainly due to disconnection from the grid in August 2020||(26)|
|Total MCAC SBU Operating Margin Increase||$||72|
Adjusted Operating Margin increased $42 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC decreased $80 million, mainly driven by insurance recoveries associated with property damage at Andres and Changuinola in 2019, partially offset by the increase in Adjusted Operating Margin described above.
Fiscal year 2019 versus 2018
Operating Margin decreased $47 million, or 9%, which was driven primarily by the following (in millions):
|Lower availability due to the outage of Changuinola for the tunnel lining upgrade||$||(123)|
|Lower availability driven by lower hydrology in Panama||(40)|
|Decrease in Dominican Republic due to lower energy prices||(18)|
|Lower energy costs and business interruption insurance recovered due to the lightning incident at the Andres facility in 2018||45|
|Higher contract sales at Panama mainly driven by contract renewals at higher prices||41|
|Higher sales at Panama driven by the commencement of operations at the Colon combined cycle facility in September 2018||40|
|Increase in Mexico due to pension plan pass-through adjustment||12|
|Total MCAC SBU Operating Margin Decrease||$||(47)|
Adjusted Operating Margin decreased $39 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $67 million, mainly driven by the insurance recoveries associated with property damage at Andres and Changuinola, partially offset by a decrease in Adjusted Operating Margin described above.
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|For the Years Ended December 31,||2020||2019||2018||$ Change 2020 vs. 2019||% Change 2020 vs. 2019||$ Change 2019 vs. 2018||% Change 2019 vs. 2018|
Adjusted Operating Margin (1)
Adjusted PTC (1)
(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 2020 versus 2019
Operating Margin decreased $2 million, or 1%, which was driven primarily by the following (in millions):
|Impact of the sale of Kilroot and Ballylumford businesses in June 2019||(6)|
|Total Eurasia SBU Operating Margin Decrease||$||(2)|
Adjusted Operating Margin decreased $6 million due to the drivers above, adjusted for NCI.
Adjusted PTC increased $18 million, mainly driven by lower interest expense due to regular debt repayments in Bulgaria and a positive variance in OPGC equity earnings, partially offset by the decrease in Adjusted Operating Margin described above.
Fiscal year 2019 versus 2018
Operating Margin decreased $39 million, or 17%, which was driven primarily by the following (in millions):
|Impact of the sale of Kilroot and Ballylumford businesses in June 2019||$||(46)|
|Impact of the sale of the Masinloc power plant in March 2018||(24)|
|Lower depreciation at the Jordan plants due to their classification as held-for-sale||20|
|Total Eurasia SBU Operating Margin Decrease||$||(39)|
Adjusted Operating Margin decreased $46 million, primarily due to the drivers above, adjusted for NCI.
Adjusted PTC decreased $63 million, primarily driven 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.
Key Trends and Uncertainties
During 2021 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 have a material impact on 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.
The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility in financial markets. The following discussion highlights our assessment of the impacts of the pandemic on our current financial and operating status, and our financial and operational outlook based on information known as of this filing. Also see Item 1A.—Risk Factors of this Form 10-K.
Throughout the COVID-19 pandemic we have conducted our essential operations without significant disruption. We derive approximately 85% of our total revenues from our regulated utilities and long-term sales and
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supply contracts or PPAs at our generation businesses, which contributes to a relatively stable revenue and cost structure at most of our businesses. The impact of the COVID-19 pandemic on the energy market materialized in our operational locations in the second quarter and was generally better than our revised expectations for the second half of 2020. Across our global portfolio, our utilities businesses experienced a low single digit percentage decline in the fourth quarter. Our business model outside of utilities is primarily based on take-or-pay contracts or tolling agreements, with limited exposure to demand. Any uncontracted portion of our generation business is exposed to increased price risk resulting from lower demand associated with the pandemic. We are also experiencing a decline in electricity spot prices in some of our markets due to lower system demand. While we cannot predict the length and magnitude of the pandemic or how it could impact global economic conditions, a delayed recovery with respect to demand may adversely impact our financial results for 2021.
We continue to monitor and manage our credit exposures in a prudent manner. Our credit exposures have continued in-line with historical levels and within the customary 45-60 day grace period. These impacts are expected to be partially offset by recoveries through U.S. regulatory rate-making mechanisms and a combination of the securitization of customer payment moratorium receivables and agreements with the generating companies in El Salvador. We have not experienced material credit-related impacts from our PPA offtakers due to the COVID-19 pandemic.
Our supply chain management has remained robust during this challenging time and we continue to closely manage and monitor developments. We continue to experience certain minor delays in some of our development projects, primarily in permitting processes and the implementation of interconnections, due to governments and other authorities having limited capacity to perform their functions.
The Coronavirus Aid, Relief, and Economic Security (“CARES”) Act was passed by the U.S. Congress and signed into law on March 27, 2020. While we currently expect a limited impact from this legislation on our business, certain elements such as changes in the deductibility of interest may provide some cash benefits in the near term.
Additionally, the Company continues to monitor the potential impact of the COVID-19 pandemic on our financial results and operations, which may result in the need to record a valuation allowance against deferred tax assets in the jurisdictions where we operate.
Macroeconomic and Political
The macroeconomic and political environments in some countries where our subsidiaries conduct business have changed during 2020. 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 for further information.
Argentina — In the run up to the 2019 Presidential elections, the Argentine peso devalued significantly and the government of Argentina imposed capital controls and announced a restructuring of Argentina’s debt payments. 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. Following the election of Alberto Fernández in October 2019, the administration has been evaluating solutions to the Argentine economic crisis. On February 27, 2020, the Secretariat of Energy passed Resolution No. 31/2020 that includes the denomination of tariffs in local currency indexed by local inflation (currently delayed due to the COVID-19 pandemic), and reductions in capacity payments received by generators. These regulatory changes have negatively impacted our financial results. In addition, Argentina restructured its public debt in 2020 through an agreement with its international creditors. Although the situation in Argentina remains challenging, it has not had a material impact on our current exposures to date, and payments on the long-term receivables for the FONINVEMEM Agreements are current. For further information, see Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.
Chile — In October 2019, Chile saw significant protests associated with economic conditions resulting in the declaration of a state of emergency in several major cities. In response to the social unrest, the Chilean government held a referendum in October 2020, which determined that a new constitution will be drafted by a constitutional convention. A second vote will be held alongside municipal and gubernatorial elections in April 2021 to elect the members of the constitutional convention. A third vote, which is expected to occur in 2022, would accept or reject the new constitution after it is drafted. Other initiatives to address the concerns of the protesters are under consideration by Congress and could result in regulatory or policy changes that may affect our results of operations in Chile.
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In November 2019, the Chilean government enacted Law 21,185 that establishes a Stabilization Fund for regulated energy prices. Historically, the government updated the prices for regulated energy contracts every six months to reflect the indexation the contracts have to exchange rates and commodities prices. The new law freezes regulated prices and 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. The receivables will be paid by distribution companies and the face value will be recognized by a Tariff Decree issued by the regulator every six months. On December 31, 2020, AES Gener executed an agreement for the sale of $105 million of receivables generated pursuant the Tariff Stabilization Law at a discount of $20 million. Of the $85 million of net receivables outstanding pursuant the Tariff Stabilization Law, $23 million were collected by AES Gener in February 2021.
Puerto Rico — Our subsidiaries in Puerto Rico have long-term PPAs with state-owned PREPA, which has been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico.
The Puerto Rico Oversight, Management, and Economic Stability Act (“PROMESA”) was enacted to create a structure for exercising federal oversight over the fiscal affairs of U.S. territories and created procedures for adjusting debt accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). PROMESA also expedites the approval of key energy projects and other critical projects in Puerto Rico.
PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017. As a result of the bankruptcy filing, AES Puerto Rico and AES Ilumina’s non-recourse debt of $238 million and $31 million, respectively, continue to be in technical default and are classified as current as of December 31, 2020. The Company is in compliance with its debt payment obligations as of December 31, 2020.
The Company's receivable balances in Puerto Rico as of December 31, 2020 totaled $55 million, of which $1 million was overdue. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.
On January 2, 2020, the Governor of Puerto Rico signed a bill that prohibits the disposal and unencapsulated beneficial use of coal combustion residuals in Puerto Rico. Prior to this bill's approval, the Company had put in place arrangements to dispose or beneficially use its coal ash and combustion residual outside of Puerto Rico.
Considering the information available as of the filing date, management believes the carrying amount of our long-lived assets in Puerto Rico of $534 million is recoverable as of December 31, 2020.
Reference Rate Reform — In July 2017, the UK Financial Conduct Authority announced that it intends to phase out LIBOR by the end of 2021. In the U.S., the Alternative Reference Rate Committee at the Federal Reserve identified the Secured Overnight Financing Rate ("SOFR") as its preferred alternative rate for LIBOR; alternative reference rates in other key markets are under development. On November 30, 2020, the ICE Benchmark Association ("IBA") announced it had begun consultation on its intention to cease publication of two specific LIBOR rates by December 31, 2021, while extending the timeline for the overnight, one-month, three-month, six-month, and 12-month USD LIBOR rates through June 30, 2023. The IBA expects to make separate announcements in this regard following the outcome of the consultation. AES holds a substantial amount of debt and derivative contracts referencing LIBOR as an interest rate benchmark. Although the full impact of the reform remains unknown, we have begun to engage with AES counterparties to discuss specific action items to be undertaken in order to prepare for amendments when they become due.
United States Tax Law Reform
Federal Taxes — In December 2017, the United States enacted the TCJA. The legislation significantly revised the U.S. corporate income tax system by, among other things, lowering the corporate income tax rate, introducing new limitations on interest expense deductions, subjecting foreign earnings in excess of an allowable return to current U.S. taxation, and adopting a semi-territorial corporate tax system. These changes impacted our 2018 and 2019 effective tax rates and may materially impact our effective tax rate in future periods. Furthermore, we anticipate that growth in our U.S. businesses and higher U.S. tax expense may fully utilize our remaining net operating loss carryforwards in the near term, which could lead to material cash tax payments in the United States. Our interpretation of the TCJA may change in the event the U.S. Treasury and the Internal Revenue Service issue additional guidance. The Company's effective tax rate in 2020 reflects the application of the GILTI high-tax exclusion under the final regulations published on July 23, 2020. This election reduced our provision for GILTI income from,
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among others, certain subsidiaries in Chile and the Dominican Republic. Should these subsidiaries fail to qualify for the exclusion under the regulations, the Company’s U.S. taxable income and consolidated income tax expense for 2020 may be materially impacted. These regulations may materially impact our future year effective tax rates and future cash tax obligations.
State Taxes — The reactions of the individual states to federal tax reform are still evolving. Most states will assess whether and how the federal changes will be incorporated into their state tax legislation. As we expect higher taxable income in the future at the federal level, this may also lead to higher state taxable income. Our current state tax provisions predominantly have full valuation allowances against state net operating losses. These positions will be re-assessed in the future as state tax law evolves and may result in material changes in position.
U.S. Renewable Tax Credits — The Consolidated Appropriations Act, 2021 ("CAA, 2021") became law on December 27, 2020. Included in the CAA, 2021 is the Taxpayer Certainty and Disaster Tax Relief Act of 2020 ("TCDTRA"), which extends the sunset or phase-down periods of federal tax credits related to the development and operation of certain renewable energy electric generating facilities, and provides new tax credit extension rules specifically applying to offshore wind power electric generating facilities. Specifically, the TCDTRA extends the 26% Investment Tax Credit for qualified solar projects beginning construction in 2021 and 2022 that are placed in service before January 1, 2026 and permits a 22% Investment Tax Credit for qualified projects beginning construction in 2023 that are placed in service before January 1, 2026. It also extends the 60% Production Tax Credit for onshore wind by one year, allowing qualified wind projects beginning construction in 2021 to be eligible.
In addition to the tax credit extenders, the TCDTRA provides for a five-year extension of the controlled foreign corporation look-through rule through 2025. Under this rule, dividends and interest paid by one controlled foreign subsidiary to another are exempt from U.S. tax. AES currently relies on the controlled foreign corporation look-through rule to exempt dividends and interest paid between foreign subsidiaries from current U.S. tax.
Several initiatives have been announced by regulators and offtakers in recent years, with the intention of reducing GHG emissions generated by the energy industry. Our strategy of shifting towards clean energy platforms, including renewable energy, energy storage, LNG, and modernized grids is designed to position us for continued growth while reducing our carbon intensity. The shift to renewables has caused certain customers to migrate to other low-carbon energy solutions and this trend may continue. Certain of our contracts contain clauses designed to compensate for early contract terminations, but we cannot guarantee full recovery. Although the Company cannot currently estimate the financial impact of these decarbonization initiatives, new legislative or regulatory programs further restricting carbon emissions could require material capital expenditures, result in a reduction of the estimated useful life of certain coal facilities, or have other material adverse effects on our financial results. For further discussion of our strategy of shifting towards clean energy platforms see Item 1—Executive Summary.
Chilean Decarbonization Plan — The Chilean government has announced an initiative to phase out coal power plants by 2040 and achieve carbon neutrality by 2050. On June 4, 2019, AES Gener signed an agreement with the Chilean government to cease the operation of two coal units for a total of 322 MW as part of the phase-out. Under the agreement, Ventanas 1 (114 MW) will cease operation in November 2022 and Ventanas 2 (208 MW) in May 2024; however AES Gener has announced its intention to accelerate the disconnection of these units. On December 26, 2020, the Chilean government issued Supreme Decree Number 42, which allows coal plants to remain connected to the grid in “strategic reserve status” for five years after ceasing operations, receive a reduced capacity payment, and dispatch, if necessary, to ensure the electric system’s reliability. On December 29, 2020, Ventanas 1 ceased operation and entered "strategic reserve status." Ventanas 2 is also expected to enter "strategic reserve status" in August 2021. See Item 1—Business—South America SBU—Chile for further discussion. Considering the information available as of the filing date, management believes the carrying amount of our coal-fired long-lived assets in Chile of $1.9 billion is recoverable as of December 31, 2020.
Puerto Rico Energy Public Policy Act — On April 11, 2019, the Governor of Puerto Rico signed the Puerto Rico Energy Public Policy Act (“the Act”) establishing guidelines for grid efficiency and eliminating coal as a source for electricity generation by January 1, 2028. The Act supports the accelerated deployment of renewables through the Renewable Portfolio Standard and the conversion of coal generating facilities to other fuel sources, with compliance targets of 40% by 2025, 60% by 2040, and 100% by 2050. AES Puerto Rico’s long-term PPA with PREPA expires November 30, 2027. PREPA and AES Puerto Rico have discussed different strategic alternatives, but have yet to reach any agreement. Any agreement that may be reached would be subject to lender and
|99 | 2020 Annual Report|
regulatory approval, including that of the Oversight Board that filed for bankruptcy on behalf of PREPA. The Company is evaluating certain developments occurring during the first quarter of 2021 to determine if a reassessment of the recoverability and useful life of the plant is necessary. Considering the information available as of the filing date, management believes the carrying amount of our long-lived assets in Puerto Rico of $534 million is recoverable as of December 31, 2020.
Hawaii — In July 2020, the Hawaii State Legislature passed a bill that will prohibit AES Hawaii from generating electricity from coal after December 31, 2022. As this will restrict the Company from contracting the asset beyond the expiration of its existing PPA, management reassessed the economic useful life of the generation facility. A decrease in the useful life was identified as an impairment indicator. The Company performed an impairment analysis and determined that the carrying amount of the asset group was not recoverable. As a result, the Company recognized asset impairment expense of $38 million. AES Hawaii is reported in the US and Utilities SBU reportable segment.
For further information about the risks associated with decarbonization initiatives, see Item 1A.—Risk Factors—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 included in this Form 10-K.
AES Maritza PPA Review — DG Comp is conducting a preliminary review of whether AES Maritza’s PPA with NEK is compliant with the European Union's State Aid rules. Although no formal investigation has been launched by DG Comp to date, AES Maritza has engaged in discussions with the DG Comp case team to discuss the agency’s review. In the near term, Maritza expects to engage in discussions with Bulgaria (with the involvement of DG Comp) to attempt to reach a negotiated resolution concerning DG Comp’s review. Separately, Bulgaria recently submitted its proposed plan for the reform of its electricity market to the European Commission (the “Market Reform Plan”). The proposed Market Reform Plan is part of Bulgaria’s plan to introduce a market-wide capacity remuneration mechanism, which would require approval by DG Comp. The Market Reform Plan proposes a deadline of June 30, 2021 for the termination of AES Maritza’s PPA, and anticipates discussions with AES Maritza about that issue. We do not believe termination of the PPA is justified, nor do we believe that the unilaterally proposed deadline for the termination of the PPA is realistic, given that the discussions with Bulgaria have not yet begun. We expect that the anticipated discussions with Bulgaria could involve a range of potential outcomes, including but not limited to the termination of the PPA and payment of some level of compensation to AES Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp approval. At this time, we cannot predict the outcome of the anticipated discussions between AES Maritza and Bulgaria, nor can we predict how DG Comp might resolve its review if the discussions fail to result in an agreement concerning the review. AES Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurances that this matter will be resolved favorably; if it is not, there could be a material adverse effect on the Company’s financial condition, results of operation, and cash flows.
Considering the information available as of the filing date, management believes the carrying value of our long-lived assets at Maritza of approximately $1.1 billion is recoverable as of December 31, 2020.
Tietê GSF Settlement — In September 2020, Law 14.052/2020 published by ANEEL was approved by the President of Brazil, establishing terms for compensation to MRE hydro generators for the incorrect application of the GSF mechanism from 2013 to 2018, which resulted in higher charges assessed to MRE hydro generators by the regulator. Under this law, compensation will be in the form of an offer for a concession extension for each hydro generator, in exchange for full payment of billed GSF trade payables. In December 2020, ANEEL published a regulation establishing the terms and conditions for potential compensation to Tietê in the form of a concession extension period of approximately 2.6 years. As a result, the previously recognized contingent liabilities related to GSF payments were updated to reflect the Company's best estimate for the fair value of compensation to be received from the concession extension offered in conjunction with the regulation. This compensation was estimated to have a fair value of $184 million, and was recorded as a reversal of Non-Regulated Cost of Sales on the Consolidated Statements of Operations. The concession extension also met the criteria for recognition as a definite-lived intangible asset that will be amortized from the date of the agreement, which is expected in the first quarter of 2021, until the end of the new concession period. The value of the concession extension is based on a preliminary time-value equivalent calculation made by the CCEE and subsequent adjustments requested by Tietê. Both the concession extension period and its equivalent asset value are subject to agreement between ANEEL and AES.
|100 | 2020 Annual Report|
Management does not expect the agreement to result in a materially different concession extension period or equivalent asset value, however the final compensation value and extension period could differ from the original estimates as of December 31, 2020, which could require adjustments.
Foreign Exchange Rates
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. In 2018 and 2019 there was a significant devaluation in the Argentine peso against the USD, which had an impact on our 2018 and 2019 results. Continued material devaluation of the Argentine peso against the USD could have an impact on our future results. The Argentine economy continues to be considered highly inflationary under U.S. GAAP; as such, all of our Argentine businesses are reported using the USD as the functional currency. For additional information, refer to Item 7A.—Quantitative and Qualitative Disclosures About Market Risk.
Long-lived Assets and Equity Affiliates — In August 2020, AES Gener reached an agreement with Minera Escondida and Minera Spence to early terminate two PPAs of the Angamos coal-fired plant in Chile. AES Gener also announced its intention to accelerate the retirement of the Ventanas 1 and Ventanas 2 coal-fired plants. Management will no longer be pursuing a contracting strategy for these assets and the plants will primarily be utilized as peaker plants and for grid stability. Due to these developments, the Company performed an impairment analysis and determined that the carrying amounts of these asset groups were not recoverable. As a result, the Company recognized asset impairment expense of $781 million.
During the year ended December 31, 2020, the Company recognized asset and other-than-temporary impairment expenses of $1.1 billion, inclusive of the asset impairment noted above. See Note 8—Investments In and Advances To Affiliates and Note 22—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. After recognizing these impairment expenses, the carrying value of our investments in equity affiliates and long-lived assets that were assessed for impairment in 2020 totaled $2.1 billion at December 31, 2020.
Events or changes in circumstances that may necessitate recoverability tests and potential impairments of long-lived assets may include, but are not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, evolving industry expectations to transition away from fossil fuel sources for generation, or an expectation it is more likely than not the asset will be disposed of before the end of its estimated useful life.
Goodwill — The Company considers a reporting unit at risk of impairment when its fair value does not exceed its carrying amount by 10%. In 2019, during the annual goodwill impairment test performed as of October 1, 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" largely due to the Chilean government's announcement to phase out coal generation by 2040, and a decline in long-term energy prices.
As a result of the long-lived asset impairments at Gener during the third quarter of 2020, the Company determined there was a triggering event requiring a reassessment of goodwill impairment at September 1, 2020. The Company determined the fair value of its Gener reporting unit exceeded its carrying value by 13%. Although the fair value exceeds its carrying value by more than 10%, the Company continues to monitor the Gener reporting unit for potential interim goodwill impairment triggering events.
Through 2028, Gener’s plants remain largely contracted, with PPAs expiring between 2029 and 2042. The Company utilized the income approach in deriving the fair value of the Gener reporting unit, which included estimated cash flows based on the estimated useful lives of the underlying generating asset class. These cash flows were discounted using a weighted average cost of capital of 7%, which was determined based on the Capital Asset Pricing Model. See Item 7.—Critical Accounting Policies and Estimates—Fair Value of Nonfinancial Assets and Liabilities and Note 9—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
While the duration and severity of the impacts of the COVID-19 pandemic remain unknown, further disruptions in the global market could result in changes to assumptions utilized in the goodwill assessment. Impairments would
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negatively impact our consolidated results of operations and net worth. See Item 1A.—Risk Factors of this Form 10-K for further information.
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, 2020. 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.
Capital Resources and Liquidity
As of December 31, 2020, the Company had unrestricted cash and cash equivalents of $1.1 billion, of which $71 million was held at the Parent Company and qualified holding companies. The Company had $335 million in short-term investments, held primarily at subsidiaries, and restricted cash and debt service reserves of $738 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $16.4 billion and $3.4 billion, respectively. Of the $1.4 billion of our current non-recourse debt, $1.2 billion was presented as such because it is due in the next twelve months and $276 million relates to debt considered in default due to covenant violations. None of the defaults are payment defaults but are instead technical defaults triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents, of which $269 million is due to the bankruptcy of the offtaker.
We expect current maturities of non-recourse debt to be repaid from net cash provided by operating activities of the subsidiary to which the debt relates, through opportunistic refinancing activity, or some combination thereof. We have $1 million of recourse debt which matures within the next twelve months. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, and other factors. The amounts involved in any such repurchases may be material.
We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies, and related assets. Our non-recourse financing is designed to limit cross-default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.
Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company's only material unhedged exposure to variable interest rate debt relates to drawings of $70 million under its revolving credit facility. On a consolidated basis, of the Company's $20.2 billion of total gross debt outstanding as of December 31, 2020, approximately $2.7 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate. Brazil holds $800 million of our floating rate non-recourse exposure as we have no ability to fix local debt interest rates efficiently.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project's non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment, or other services with our subsidiaries or
|102 | 2020 Annual Report|
lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business' obligations up to the amount provided for in the relevant guarantee or other credit support. As of December 31, 2020, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $1.4 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).
As a result of the Parent Company's split rating, some counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. As of December 31, 2020, we had $110 million in letters of credit outstanding provided under our unsecured credit facilities, and $77 million in letters of credit outstanding provided under our revolving credit facility. These letters of credit operate to guarantee performance relating to certain project development and construction activities and business operations. During the year ended December 31, 2020, the Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.
We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.
Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.
As of December 31, 2020, the Company had approximately $110 million of gross accounts receivable classified as Other noncurrent assets. These noncurrent receivables mostly consist of accounts receivable in Argentina and Chile that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond December 31, 2021, or one year from the latest balance sheet date. The majority of Argentine receivables have been converted into long-term financing for the construction of power plants. Noncurrent receivables in Chile pertain primarily to revenues recognized on regulated energy contracts that were impacted by the Stabilization Fund created by the Chilean government. A portion relates to the extension of existing PPAs with the addition of renewable energy. See Note 7—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data, Item 1.—Business—South America SBU—Argentina—Regulatory Framework and Market Structure, and Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operation—Key Trends and Uncertainties—Macroeconomic and Political—Chile of this Form 10-K for further information.
As of December 31, 2020, the Company had approximately $1.3 billion of loans receivable primarily related to a facility constructed under a BOT contract in Vietnam. This loan receivable represents contract consideration related to the construction of the facility, which was substantially completed in 2015, and will be collected over the 25-year term of the plant's PPA. As of December 31, 2020, Mong Duong met the held-for-sale criteria and the loan receivable balance of $1.3 billion, net of CECL reserve of $32 million, was reclassified to held-for-sale assets. Of the loan receivable balance, $80 million was classified as Current held-for-sale assets and $1.2 billion was classified as Noncurrent held-for-sale assets on the Consolidated Balance Sheet. See Note 20—Revenue included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
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Cash Sources and Uses
The primary sources of cash for the Company in the year ended December 31, 2020 were debt financings, cash flows from operating activities, sales of short-term investments, and sales to noncontrolling interests. The primary uses of cash in the year ended December 31, 2020 were repayments of debt, capital expenditures, and purchases of short-term investments.
The primary sources of cash for the Company in the year ended December 31, 2019 were debt financings, cash flows from operating activities, and sales of short-term investments. The primary uses of cash in the year ended December 31, 2019 were repayments of debt, capital expenditures, and purchases of short-term investments.
The primary sources of cash for the Company in the year ended December 31, 2018 were debt financings, cash flows from operating activities, proceeds from the sales of business interests, and sales of short-term investments. The primary uses of cash in the year ended December 31, 2018 were repayments of debt, capital expenditures, and purchases of short-term investments.
A summary of cash-based activities are as follows (in millions):
|Year Ended December 31,|
|Issuance of non-recourse debt||$||4,680||$||5,828||$||1,928|
|Issuance of recourse debt||3,419||—||1,000|
|Net cash provided by operating activities||2,755||2,466||2,343|
|Borrowings under the revolving credit facilities||2,420||2,026||1,865|
|Sale of short-term investments||627||666||1,302|
|Sales to noncontrolling interests||553||128||95|
|Proceeds from the sale of business interests, net of cash and restricted cash sold||169||178||2,020|
|Issuance of preferred shares in subsidiaries||112||—||—|
|Total Cash Sources||$||14,744||$||11,451||$||10,693|
|Repayments of non-recourse debt||$||(4,136)||$||(4,831)||$||(1,411)|
|Repayments of recourse debt||(3,366)||(450)||(1,933)|
|Repayments under the revolving credit facilities||(2,479)||(1,735)||(2,238)|
|Purchase of short-term investments||(653)||(770)||(1,411)|
|Distributions to noncontrolling interests||(422)||(427)||(340)|
|Dividends paid on AES common stock||(381)||(362)||(344)|
|Contributions and loans to equity affiliates||(332)||(324)||(145)|
|Acquisitions of noncontrolling interests||(259)||—||—|
|Acquisitions of business interests, net of cash and restricted cash acquired||(136)||(192)||(66)|
|Payments for financing fees||(107)||(126)||(39)|
|Payments for financed capital expenditures||(60)||(146)||(275)|
|Total Cash Uses||$||(14,489)||$||(11,882)||$||(10,478)|
|Net increase (decrease) in Cash, Cash Equivalents, and Restricted Cash||$||255||$||(431)||$||215|
Consolidated Cash Flows
The following table reflects the changes in operating, investing, and financing cash flows for the comparative twelve month periods (in millions):
|December 31,||$ Change|
|Cash flows provided by (used in):||2020||2019||2018||2020 vs. 2019||2019 vs. 2018|
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Fiscal Year 2020 versus 2019
Net cash provided by operating activities increased $289 million for the year ended December 31, 2020, compared to December 31, 2019.
Operating Cash Flows (1)
(1)Amounts included in the chart above include the results of discontinued operations, where applicable.
(2)The change in adjusted net income is defined as the variance in net income, net of the total adjustments to net income as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.
(3)The change in working capital is defined as the variance in total changes in operating assets and liabilities as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.
•Adjusted net income decreased $40 million, primarily due to lower margins at our US and Utilities SBU and prior year gains on insurance proceeds associated with the lightning incident at the Andres facility in 2018 and the Changuinola tunnel leak, partially offset by higher margins at our South America and MCAC SBUs.
•Working capital requirements decreased $329 million, primarily due to an increase in deferred income at Angamos as a result of the early contract terminations with Minera Escondida and Minera Spence.
Fiscal Year 2019 versus 2018
Net cash provided by operating activities increased $123 million for the year ended December 31, 2019, compared to December 31, 2018.
Operating Cash Flows (1)
(1)Amounts included in the chart above include the results of discontinued operations, where applicable.
(2)The change in adjusted net income is defined as the variance in net income, net of the total adjustments to net income as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.
(3)The change in working capital is defined as the variance in total changes in operating assets and liabilities as shown on the Consolidated Statements of Cash Flows in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.
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•Adjusted net income decreased $24 million, primarily due to lower margins at our South America and MCAC SBUs. These impacts were partially offset by the gains on insurance recoveries in 2019 associated with the lightning incident at the Andres facility in 2018 and the Changuinola tunnel leak, and higher margins at our US and Utilities SBU.
•Working capital requirements decreased $147 million, primarily due to higher collections of overdue receivables from distribution companies in the Dominican Republic, higher collections of insurance receivables at Andres, and lower supplier payments and VAT recoveries at Gener. These impacts were partially offset by a decrease in income tax liabilities at Argentina as a result of lower operating margin and income tax rates, and higher supplier payments and collections at Puerto Rico in 2018.
Fiscal Year 2020 versus 2019
Net cash used in investing activities decreased $426 million for the year ended December 31, 2020 compared to December 31, 2019.
Investing Cash Flows
•Cash from short-term investing activities increased $78 million, primarily at Tietê as a result of lower net short-term investment purchases in 2020.
•Insurance proceeds decreased $141 million, largely due to prior year insurance proceeds associated with the lightning incident at the Andres facility in 2018 and the Changuinola tunnel leak.
•Capital expenditures decreased $505 million, discussed further below.
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•Growth expenditures decreased $356 million, primarily driven by the timing of payments for the Southland repowering project, renewable energy projects in Argentina, and a pipeline project at Andres, as well as the completion of solar projects at AES Brasil, a wind project in Hawaii, and the Colon LNG facility in Panama. This impact was partially offset by higher investments at IPALCO and in renewable projects at Gener.
•Maintenance expenditures decreased $143 million, primarily due to prior year expenditures at Andres as a result of the steam turbine lightning damage and in Panama as a result of the Changuinola tunnel lining upgrade, as well as due to the timing of payments in the prior year at IPALCO.
•Environmental expenditures decreased $6 million, primarily due to the timing of payments in the prior year related to projects at Gener.
Fiscal Year 2019 versus 2018
Net cash used in investing activities increased $2.2 billion for the year ended December 31, 2019 compared to December 31, 2018.
Investing Cash Flows
•Proceeds from dispositions decreased $1.8 billion, primarily due to sales of Masinloc, Electrica Santiago, CTNG, Eletropaulo, and the DPL peaker assets in 2018; partially offset by the sale of a portion of our interest in a portfolio of sPower’s operating assets and the sale of the Kilroot and Ballylumford plants in the United Kingdom in 2019.
•Contributions and loans to equity affiliates increased by $179 million, primarily due to project funding requirements at sPower.
•Capital expenditures increased $284 million, discussed further below.
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•Growth expenditures increased $130 million, primarily due to higher investments in solar projects at Distributed Energy and renewable energy projects in Argentina, partially offset by a decrease in payments for the Southland repowering projects.
•Maintenance expenditures increased $173 million, primarily at Andres as a result of the steam turbine lightning damage, at DPL from storm damages, and at Changuinola due to the upgrade of the tunnel lining.
•Environmental expenditures decreased $19 million, primarily at IPALCO due to lower spending for NAAQS, NPDES, and CCR rule compliance.
Fiscal Year 2020 versus 2019
Net cash used in financing activities decreased $8 million for the year ended December 31, 2020 compared to December 31, 2019.
Financing Cash Flows
See Notes 11—Debt and 17—Equity in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant debt and equity transactions, respectively.
•The $503 million impact from recourse debt transactions is primarily due to higher net borrowings at the Parent Company.
•The $425 million impact from sales to noncontrolling interests is primarily due to the proceeds received from the sale of a 35% ownership interest in Southland Energy.
•The $112 million impact from issuance of preferred shares in subsidiaries is due to proceeds from the issuance of preferred shares to minority interests of Cochrane.
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•The $453 million impact from non-recourse debt transactions is primarily due to lower net borrowings at Southland and Gener, partially offset by a decrease in net repayments at AES Brasil and DPL and higher net borrowings at Distributed Energy, Panama, and Vietnam.
•The $290 million impact from Parent Company revolver transactions is primarily due to higher net repayments in the current year.
•The $259 million impact from acquisitions of noncontrolling interests is primarily due to the acquisition of an additional 19.8% ownership interest in AES Brasil.
Fiscal Year 2019 versus 2018
Net cash used in financing activities decreased $1.6 billion for the year ended December 31, 2019 compared to December 31, 2018.
Financing Cash Flows
See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant debt transactions.
•The $483 million impact from recourse debt activity is primarily due to higher net repayments of Parent Company debt in 2018.
•The $480 million impact from non-recourse debt transactions is primarily due to net issuances at Gener, Alto Maipo and DPL, which were partially offset by net repayments at AES Brasil, and lower net issuances in 2018 at IPALCO.
•The $387 million impact from Parent Company revolver transactions is primarily from higher repayments in 2018, and higher borrowings in 2019 for general corporate cash management activities.
•The $278 million impact from non-recourse revolver transactions is primarily due to higher net borrowings at DPL and net repayments at IPALCO in 2018.
Parent Company Liquidity
The following discussion is included as a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to Cash and cash equivalents, which is determined in accordance with GAAP. Parent Company Liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are dividends and other distributions from our subsidiaries, including refinancing proceeds, proceeds from debt and equity financings at the Parent Company level, including availability under our revolving credit facility, and proceeds from asset sales. Cash requirements at the Parent Company level are primarily to fund interest and principal repayments of debt, construction commitments, other equity commitments, common stock repurchases, acquisitions, taxes, Parent Company overhead and development costs, and dividends on common stock.
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The Company defines Parent Company Liquidity as cash available to the Parent Company, including cash at qualified holding companies, plus available borrowings under our existing credit facility. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable GAAP financial measure, Cash and cash equivalents, at the periods indicated as follows (in millions):
|December 31, 2020||December 31, 2019|
|Consolidated cash and cash equivalents||$||1,089||$||1,029|
|Less: Cash and cash equivalents at subsidiaries||(1,018)||(1,016)|
|Parent Company and qualified holding companies' cash and cash equivalents||71||13|
|Commitments under the Parent Company credit facility||1,000||1,000|
|Less: Letters of credit under the credit facility||(77)||(19)|
|Less: Borrowings under the credit facility||(70)||(180)|
|Borrowings available under the Parent Company credit facility||853||801|
|Total Parent Company Liquidity||$||924||$||814|
The Parent Company paid dividends of $0.57 per outstanding share to its common stockholders during the year ended December 31, 2020. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance that we will continue to pay dividends, or if continued, the amount of such dividends.
Our total recourse debt was $3.4 billion at December 31, 2020 and 2019. See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail.
We believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future. This belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries' ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our revolving credit facility. See Item 1A.—Risk Factors—The AES Corporation's ability to make payments on its outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries, of this Form 10-K.
Various debt instruments at the Parent Company level, including our revolving credit facility, contain certain restrictive covenants. The covenants provide for, among other items, limitations on other indebtedness; liens, investments and guarantees; limitations on dividends, stock repurchases and other equity transactions; restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements; maintenance of certain financial ratios; and financial and other reporting requirements. As of December 31, 2020, we were in compliance with these covenants at the Parent Company level.
While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:
•reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;
•triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;
•causing us to record a loss in the event the lender forecloses on the assets; and
•triggering defaults in our outstanding debt at the Parent Company.
For example, our revolving credit facility and outstanding debt securities at the Parent Company include events of default for certain bankruptcy-related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.
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Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying Consolidated Balance Sheets amounts to $1.4 billion. The portion of current debt related to such defaults was $276 million at December 31, 2020, all of which was non-recourse debt related to three subsidiaries — AES Puerto Rico, AES Ilumina, and AES Jordan Solar. None of the defaults are payment defaults, but are instead technical defaults triggered by failure to comply with other covenants or other conditions contained in the non-recourse debt documents, of which $269 million is due to the bankruptcy of the offtaker. See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail.
None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under the Parent Company's debt agreements as of December 31, 2020, in order for such defaults to trigger an event of default or permit acceleration under the Parent Company's indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a "material subsidiary" and thereby trigger an event of default and possible acceleration of the indebtedness under the Parent Company's outstanding debt securities. A material subsidiary is defined in the Parent Company's revolving credit facility as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of December 31, 2020, none of the defaults listed above, individually or in the aggregate, results in or is at risk of triggering a cross-default under the recourse debt of the Parent Company.
Contractual Obligations and Parent Company Contingent Contractual Obligations
A summary of our contractual obligations, commitments and other liabilities as of December 31, 2020 is presented below (in millions):
|Contractual Obligations||Total||Less than 1 year||1-3 years||3-5 years||More than 5 years||Other|
Debt obligations (1) (2)
Interest payments on long-term debt (3)
Finance lease obligations (2)
Operating lease obligations (2)
|Other purchase obligations||6,057||1,904||1,241||1,096||1,816||—||12|
Other long-term liabilities reflected on AES' consolidated balance sheet under GAAP (2) (4)
(1)Includes recourse and non-recourse debt presented on the Consolidated Balance Sheet. These amounts exclude finance lease liabilities which are included in the finance lease category.
(2)Excludes any businesses classified as held-for-sale. See Note 25—Held-for-Sale and Dispositions in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information related to held-for-sale businesses.
(3)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020.
(4)These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the "Other" column of the table above as the Company is not able to reasonably estimate the timing of the future payments. In addition, these amounts do not include: (1) regulatory liabilities (See Note 10—Regulatory Assets and Liabilities), (2) contingencies (See Note 13—Contingencies), (3) pension and other postretirement employee benefit liabilities (see Note 15—Benefit Plans), (4) derivatives and incentive compensation (See Note 6—Derivative Instruments and Hedging Activities) or (5) any taxes (See Note 23—Income Taxes) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on the items excluded.
(5)For further information see the note referenced below in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.
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The following table presents our Parent Company's contingent contractual obligations as of December 31, 2020:
|Contingent contractual obligations||Amount (in millions)||Number of Agreements||Maximum Exposure Range for Each Agreement (in millions)|
|Guarantees and commitments||$||1,358||69||$0 — 157|
|Letters of credit under the unsecured credit facilities||110||25||$0 — 56|
|Letters of credit under the revolving credit facility||77||17||$0 — 62|
(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.
We have a diverse portfolio of performance-related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, sponsor support and liquidated damages under power sales agreements for projects in development, in operation and under construction. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations beyond 2020, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.
Critical Accounting Policies and Estimates
The Consolidated Financial Statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. AES' significant accounting policies are described in Note 1—General and Summary of Significant Accounting Policies to the Consolidated Financial Statements included in Item 8 of this Form 10-K.
An accounting estimate is considered critical if the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or the impact of the estimates and assumptions on financial condition or operating performance is material.
Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could materially differ from the original estimates, requiring adjustments to these balances in future periods. Management has discussed these critical accounting policies with the Audit Committee, as appropriate. Listed below are the Company's most significant critical accounting estimates and assumptions used in the preparation of the Consolidated Financial Statements.
Income Taxes — We are subject to income taxes in both the U.S. and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. Certain of the Company's subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each tax jurisdiction when determining the adequacy of the provision for income taxes. Accounting guidance for uncertainty in income taxes prescribes a more likely than not recognition threshold. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amounts of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.
Because we have a wide range of statutory tax rates in the multiple jurisdictions in which we operate, any changes in our geographical earnings mix could materially impact our effective tax rate. Furthermore, our tax position could be adversely impacted by changes in tax laws, tax treaties or tax regulations, or the interpretation or enforcement thereof and such changes may be more likely or become more likely in view of recent economic trends in certain of the jurisdictions in which we operate.
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In accordance with SAB 118, the Company made reasonable estimates of the impacts of U.S. tax reform on its 2017 financial results, and recorded adjustments to those estimates in 2018 as analysis was completed. As of December 31, 2018, our analysis of the one-time impacts of the TCJA was complete under SAB 118. However, in the first quarter of 2019, the U.S. Treasury Department issued final regulations on the one-time transition tax which included changes from the proposed regulations issued in 2018.
In addition, no taxes have been recorded on undistributed earnings for certain of our non-U.S. subsidiaries to the extent such earnings are considered to be indefinitely reinvested in the operations of those subsidiaries. Should the earnings be remitted as dividends, the Company may be subject to additional foreign withholding and state income taxes.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company 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.
Impairments — Our accounting policies on goodwill and long-lived assets are described in detail in Note 1—General and Summary of Significant Accounting Policies, included in Item 8 of this Form 10-K. The Company makes considerable judgments in its impairment evaluations of goodwill and long-lived assets, starting with determining if an impairment indicator exists. Events that may result in an impairment analysis being performed 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, evolving industry expectations to transition away from fossil fuel sources for generation, 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. The Company exercises judgment in determining if these events represent an impairment indicator requiring the computation of the fair value of goodwill and/or the recoverability of long-lived assets. The fair value determination is typically the most judgmental part in an impairment evaluation. Please see Fair Value below for further detail.
As part of the impairment evaluation process, management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap between fair value and carrying amount decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment, which could be material. Our impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.
Further discussion of the impairment charges recognized by the Company can be found within Note 9—Goodwill and Other Intangible Assets and Note 22—Asset Impairment Expense to the Consolidated Financial Statements included in Item 8 of this Form 10-K.
Depreciation — 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. The Company considers many factors in its estimate of useful lives, including expected usage, physical deterioration, technological changes, existence and length of off-taker agreements, and laws and regulations, among others. In certain circumstances, these estimates involve significant judgment and require management to forecast the impact of relevant factors over an extended time horizon.
Useful life estimates are continually evaluated for appropriateness as changes in the relevant factors arise, including when a long-lived asset group is tested for recoverability. Depreciation studies are performed periodically for assets subject to composite depreciation. Any change to useful lives is considered a change in accounting estimate and is made on a prospective basis.
Fair Value — For information regarding the fair value hierarchy, see Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K.
Fair Value of Financial Instruments — A significant number of the Company's financial instruments are carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period. Investments are generally fair valued based on quoted market prices or other observable market data such as interest rate indices. The Company's investments are primarily certificates of deposit and mutual funds. Derivatives
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are valued using observable data as inputs into internal valuation models. The Company's derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 5—Fair Value included in Item 8 of this Form 10-K.
Fair Value of Nonfinancial Assets and Liabilities — Significant estimates are made in determining the fair value of long-lived tangible and intangible assets (i.e., property, plant and equipment, intangible assets and goodwill) during the impairment evaluation process. In addition, the majority of assets acquired and liabilities assumed in a business combination and asset acquisitions by VIEs are required to be recognized at fair value under the relevant accounting guidance.
The Company may engage an independent valuation firm to assist management with the valuation. The Company generally utilizes the income approach to value nonfinancial assets and liabilities, specifically a Discounted Cash Flow ("DCF") model to estimate fair value by discounting cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.
Management applies considerable judgment in selecting several input assumptions during the development of our cash flow forecasts. Examples of the input assumptions that our forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices, and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources (e.g., Economic Intelligence Unit) and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical trends which often do not recur. It is not uncommon that different market data sources have different views of the macroeconomic factor expectations and related assumptions. As a result, macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations these ranges become wide and the use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.
A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg). The Company selects and uses a set of publicly traded companies from the relevant industry to estimate the discount rate inputs. Management applies judgment in the selection of such companies based on its view of the most likely market participants. It is reasonably possible that the selection of a different set of likely market participants could produce different input assumptions and result in the use of a different discount rate.
Accounting for Derivative Instruments and Hedging Activities — We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity, and foreign currency exposures. We do not enter into derivative transactions for trading purposes. See Note 6—Derivative Instruments and Hedging Activities included in Item 8 of this Form 10-K for further information on the classification.
The fair value measurement standard requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Credit risk for AES is evaluated at the level of the entity that is party to the contract. Nonperformance risk on the Company's derivative instruments is an adjustment to the fair value position that is derived from internally developed valuation models that utilize market inputs that may or may not be observable.
As a result of uncertainty, complexity, and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings, and future foreign exchange rates. Refer to Note 5—Fair Value included in Item 8 of this Form 10-K for additional details.
The fair value of our derivative portfolio is generally determined using internal and third party valuation models, most of which are based on observable market inputs, including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g., Bloomberg, Reuters and Platt's). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market
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assumptions to determine a financial instrument's fair value. In certain instances, published pricing may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. 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. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.
Regulatory Assets — Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities, and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.
Consolidation — The Company enters into transactions impacting the Company's equity interests in its affiliates. In connection with each transaction, the Company must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, the Company is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights.
If the entity is determined to be a variable interest entity, the most significant judgment in determining whether the Company must consolidate the entity is whether the Company, including its related parties and de facto agents, collectively have power and benefits. If AES is determined to have power and benefits, the entity will be consolidated by AES.
Alternatively, if the entity is determined to be a voting model entity, the most significant judgments involve determining whether the non-AES shareholders have substantive participating rights. The assessment of shareholder rights and whether they are substantive participating rights requires significant judgment since the rights provided under shareholders' agreements may include selecting, terminating, and setting the compensation of management responsible for implementing the subsidiary's policies and procedures, and establishing operating and capital decisions of the entity, including budgets, in the ordinary course of business. On the other hand, if shareholder rights are only protective in nature (referred to as protective rights), then such rights would not overcome the presumption that the owner of a majority voting interest shall consolidate its investee. Significant judgment is required to determine whether minority rights represent substantive participating rights or protective rights that do not affect the evaluation of control. While both represent an approval or veto right, a distinguishing factor is the underlying activity or action to which the right relates.
Pension and Other Postretirement Plans — The Company recognizes a net 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. The valuation of the Company's benefit obligation, fair value of plan assets, and net periodic benefit costs requires various estimates and assumptions, the most significant of which include the discount rate and expected return on plan assets. These assumptions are reviewed by the Company on an annual basis. Refer to Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K for further information.
Revenue Recognition — The Company recognizes revenue to depict the transfer of energy, capacity, and other services to customers in an amount that reflects the consideration to which we expect to be entitled. In applying the revenue model, we determine whether the sale of energy, capacity, and other services represent a single performance obligation based on the individual market and terms of the contract. Generally, the promise to transfer energy and capacity represent a performance obligation that is satisfied over time and meets the criteria to be accounted for as a series of distinct goods or services. Progress toward satisfaction of a performance obligation is measured using output methods, such as MWhs delivered or MWs made available, and when we are entitled to consideration in an amount that corresponds directly to the value of our performance completed to date, we recognize revenue in the amount to which we have the right to invoice. For further information regarding the nature of our revenue streams and our critical accounting policies affecting revenue recognition, see Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K.
Leases — The Company recognizes operating and finance right-of-use assets and lease liabilities on the
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Consolidated Balance Sheets for most leases with an initial term of greater than 12 months. Lease liabilities and their corresponding right-of-use assets are recorded based on the present value of lease payments over the expected lease term. Our subsidiaries’ incremental borrowing rates are used in determining the present value of lease payments when the implicit rate is not readily determinable. Certain adjustments to the right-of-use asset may be required for items such as prepayments, lease incentives, or initial direct costs. For further information regarding the nature of our leases and our critical accounting policies affecting leases, see Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K.
Credit Losses — The Company uses a forward-looking "expected loss" model to recognize allowances for credit losses on trade and other receivables, held-to-maturity debt securities, loans, and other instruments. For available-for-sale debt securities with unrealized losses, the Company continues to measure credit losses as it was done under previous GAAP, except that unrealized losses due to credit-related factors are now recognized as an allowance on the Consolidated Balance Sheet with a corresponding adjustment to earnings in the Consolidated Statements of Operations. For further information regarding credit losses, see Note 1—General and Summary of Significant Accounting Policies included in Item 8 of this Form 10-K.
New Accounting Pronouncements
See Note 1—General and Summary of Significant Accounting Policies included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information about new accounting pronouncements adopted during 2020 and accounting pronouncements issued, but not yet effective.
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 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 2020 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 through 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 2021, we project pre-tax earnings exposure on a 10% move in commodity prices would be less than $5 million for power,
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less than $(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, lower 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 the 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 existing once-through cooling generation units (“Legacy Assets”) have been requested to continue operating beyond their current retirement date and have been approved for an extended permit for between one and three years. These assets have contracts in capacity and have seen incremental value in energy revenues.
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 significant portion 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 with spot market exposure for uncontracted 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.
In the MCAC SBU, our businesses have commodity exposure on unhedged volumes. Panama is highly contracted under financial and load-following PPA type structures, exposing the business to hydrology-based variance. To the extent hydrological inflows are greater than or less than the contract volumes, the business will be sensitive to changes in spot power prices which may be driven by oil and natural gas prices in some time periods. In the Dominican Republic, we own natural gas- and coal-fired assets contracted under a portfolio of contract sales, 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.
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 cu