EDGAR 10-K Filing

Company CIK: 874761
Filing Year: 2021
Filename: 874761_10-K_2021_0000874761-21-000015.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
Item 1.-Business is an outline of our strategy and our businesses by SBU, including key financial drivers. Additional items that may have an impact on our businesses are discussed in Item 1A.-Risk Factors and Item 3.-Legal Proceedings.
5 | 2020 Annual Report
Executive Summary
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.
Our Strategy
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.
Strategic Highlights
In 2020, we achieved significant milestones on our strategic objectives, including:
Sustainable Growth
•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
Innovative Solutions
•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
Superior Results
•Following our efforts to strengthen our balance sheet, our Parent Company credit rating was upgraded to investment grade (BBB-) by S&P
Overview
Generation
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.
Utilities
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
Segments
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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(1) Non-GAAP measure. See Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-SBU Performance Analysis-Non-GAAP Measures for reconciliation and definition.
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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)
Bosforo (1)
El Salvador Solar 100 50 % 2018-2019 2043-2044 CAESS, EEO, CLESA, DEUSEM
AES Nejapa El Salvador Landfill Gas 6 100 % 2011 2035 CAESS
Opico El Salvador Solar 4 100 % 2020 2040 CLESA
Moncagua El Salvador Solar 3 100 % 2015 2035 EEO
El Salvador Subtotal 113
Southland-Alamitos US-CA Gas 1,200 100 % 1998 2023 Various
AES Clean Energy (sPower OpCo A (1))
US-Various Solar 1,101 26 % 2017-2019 2028-2046 Various
Southland-Redondo Beach US-CA Gas 876 100 % 1998 2021 Various
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
Energy Storage 39
Southland-Huntington Beach US-CA Gas 236 100 % 1998 2023 Various
Buffalo Gap II (3)
US-TX Wind 228 100 % 2007
Hawaii (4)
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)
US-TX Wind 170 100 % 2008
Highlander (AES Clean Energy/sPower) US-VA Solar 165 50 % 2020 2035 Apple, Akami, Etsy, Microsoft
AES Clean Energy (sPower OpCo A (1))
US-Various Wind 140 26 % 2017 2036 Various
AES Clean Energy (sPower OpCo B (1))
US-Various Solar 126 50 % 2019 2039-2044 Various
Buffalo Gap I (3)
US-TX Wind 108 100 % 2006 2021 Direct Energy
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
Laurel Mountain US-WV Wind 98 100 % 2011
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
Energy Storage 20
Kekaha (AES Clean Energy/AES Distributed Energy (3))
US-HI Solar 14 100 % 2019 2045 Kaua'i Island Utility Cooperative
Energy Storage 14
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
7,781
_____________________________
(1)Unconsolidated entity, accounted for as an equity affiliate.
13 | 2020 Annual Report
(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
CAESS El Salvador 624,000 1,945 75 % 2000
CLESA El Salvador 432,000 936 80 % 1998
DEUSEM El Salvador 87,000 144 74 % 2000
EEO El Salvador 330,000 615 89 % 2000
El Salvador Subtotal 1,473,000 3,640
DPL (1)
US-OH 531,000 13,468 100 % 2011
IPL (2)
US-IN 512,000 14,559 Coal/Gas/Oil/Energy Storage 3,973 70 % 2001
United States Subtotal 1,043,000 28,027 3,973
2,516,000 31,667
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(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
Energy Storage 42
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
IPL
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;
15 | 2020 Annual Report
•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.
DPL
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.
AES Southland
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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AES Hawaii
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.
Puerto Rico
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.
El Salvador
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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(1) Non-GAAP measure. See Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-SBU Performance Analysis-Non-GAAP Measures for reconciliation and definition.
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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)
Chivor Colombia Hydro 1,000 67 % 2000 2020-2037 Various
Castilla Colombia Solar 21 67 % 2019 2034 Ecopetrol
Tunjita Colombia Hydro 20 67 % 2016
Colombia Subtotal 1,041
Gener - Chile (1)
Chile Coal/Hydro/Diesel/Solar/Wind/Biomass 1,578 67 % 2000 2020-2040 Various
Guacolda (2)
Chile Coal 764 33 % 2000 2020-2032 Various
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
Chile Subtotal 3,512
TermoAndes (3)
Argentina Gas/Diesel 643 67 % 2000 2020 Various
AES Gener Subtotal 5,196
Alicura Argentina Hydro 1,050 100 % 2000
Paraná-GT Argentina Gas/Diesel 870 100 % 2001
San Nicolás Argentina Coal/Gas/Oil/Energy Storage 691 100 % 1993
Guillermo Brown (4)
Argentina Gas/Diesel 576 - % 2016
Cabra Corral Argentina Hydro 102 100 % 1995 Various
Vientos Bonaerenses Argentina Wind 100 100 % 2020 2024-2040 Various
Vientos Neuquinos Argentina Wind 100 100 % 2020 2024-2040 Various
Ullum Argentina Hydro 45 100 % 1996 Various
Sarmiento Argentina Gas/Diesel 33 100 % 1996
El Tunal Argentina Hydro 10 100 % 1995 Various
Argentina Subtotal 3,577
Tietê (5)
Brazil Hydro 2,658 44 % 1999 2029 Various
Alto Sertão II Brazil Wind 386 44 % 2017 2033-2035 Various
Ventus Brazil Wind 187 44 % 2020 2034 Regulated Market
Guaimbê Brazil Solar 150 44 % 2018 2037 CCEE
AGV Solar Brazil Solar 75 44 % 2019 2039 Various
Boa Hora Brazil Solar 69 44 % 2019 2035 CCEE
Drogaria Araujo Brazil Solar 5 44 % 2019 2029 Drogaria Araujo
Brasil Community Solar Brazil Solar 1 44 % 2020
AES Brasil Subtotal 3,531
12,304
_____________________________
(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
McDonalds Brazil Solar 5 44 % 1H 2021
Farmácias São João Brazil Solar 3 44 % 1H 2021
AES Brasil Subtotal 330
Alto Maipo (1)
Chile Hydro 531 62 % 2H 2021
Los Olmos Chile Wind 110 67 % 1H 2021
Campo Lindo Chile Wind 73 67 % 1H 2021
Mesamávida Chile Wind 68 67 % 2H 2021
Andes Solar 2b Chile Solar 180 67 % 2H 2021
Energy Storage 112
Chile Subtotal 1,074
San Fernando Colombia Solar 59 67 % 2H 2021
Colombia Subtotal 59
1,463
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(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
Chile
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;
•forced outages;
•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.
Colombia
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:
•forced outages;
•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.
Argentina
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:
•forced outages;
•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.
Brazil
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;
•asset management;
•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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(1) Non-GAAP measure. See Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-SBU Performance Analysis-Non-GAAP Measures for reconciliation and definition.
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MCAC SBU
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
Andres (1)
Dominican Republic Gas 319 85 % 2003 2022 Ede Norte, Ede Este, Ede Sur, Non-Regulated Users
Itabo (2)
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
Mexico Subtotal 1,361
Colon (4)
Panama Gas 381 50 % 2018 2028 ENSA, Edemet, Edechi
Bayano Panama Hydro 260 49 % 1999 2030 ENSA, Edemet, Edechi, Other
Changuinola Panama Hydro 223 90 % 2011 2030 AES Panama
Chiriqui-Esti Panama Hydro 120 49 % 2003 2030 ENSA, Edemet, Edechi, Other
Penonome I Panama Wind 55 49 % 2020 2023 Altenergy
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
Panama Subtotal 1,141
3,459
_____________________________
(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
Panama Subtotal 21
_____________________________
(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:
MCAC Businesses
Dominican Republic
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.
Panama
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.
Mexico
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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(1) Non-GAAP measure. See Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-SBU Performance Analysis-Non-GAAP Measures for reconciliation and definition.
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Eurasia SBU
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)
Maritza Bulgaria Coal 690 100 % 2011 2026 NEK
St. Nikola Bulgaria Wind 156 89 % 2010 2025 Electricity Security Fund
Bulgaria Subtotal 846
Delhi ES India Energy Storage 10 60 % 2019
India Subtotal 10
Amman East (1)
Jordan Gas 381 37 % 2009 2033 National Electric Power Company
IPP4 (1)
Jordan Heavy Fuel Oil 250 36 % 2014 2039 National Electric Power Company
AM Solar Jordan Solar 52 36 % 2019 2039 National Electric Power Company
Jordan Subtotal 683
Netherlands ES Netherlands Energy Storage 10 100 % 2015
Netherlands Subtotal 10
Mong Duong 2 (2)
Vietnam Coal 1,242 51 % 2015 2040 EVN
Vietnam Subtotal 1,242
2,791
_____________________________
(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:
Eurasia Businesses
Vietnam
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.
Bulgaria
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.
Jordan
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.
India
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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Other Investments
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.
Fluence
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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Uplight
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.
5B
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.
Customers
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.
Safety
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.
Talent
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.
Compensation
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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Executive Officers
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.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
You should consider carefully the following risks, along with the other information contained in or incorporated by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and
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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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•illiquid markets;
•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.

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

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-term leases, none of which we believe are material. With a few exceptions, our facilities, which are described in Item 1 - Business of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project's related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company's consolidated financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material, but cannot be estimated as of December 31, 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.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Stock Repurchase Program - The Board authorization permits the Parent Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Stock Repurchase Program does not have an expiration date and can be modified or terminated by the Board of Directors at any time. The cumulative 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.
Market Information
Our common stock is traded on the New York Stock Exchange under the symbol "AES."
Dividends
The Parent Company commenced a quarterly cash dividend in the fourth quarter of 2012. The Parent Company has increased this dividend annually and the quarterly per-share cash dividends for the last three years are displayed below.
Commencing the fourth quarter of 2020 2019 2018
Cash dividend $0.1505 $0.1433 $0.1365
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.
Holders
As of February 22, 2021, there were approximately 3,771 record holders of our common stock.
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Performance Graph
THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE
Source: Bloomberg
We have selected the Standard and Poor's ("S&P") 500 Utilities Index as our peer group index. The S&P 500 Utilities Index is a published sector index comprising the 28 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 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.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected financial data as of the dates and for the periods indicated. This data should be read together with Item 7.-Management's Discussion and Analysis 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
2020 2019 2018 2017 2016
Statement of Operations Data for the Years Ended December 31: (in millions, except per share amounts)
Revenue $ 9,660 $ 10,189 $ 10,736 $ 10,530 $ 10,281
Income (loss) from continuing operations (1)
149 477 1,349 (148) 191
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)
3 1 218 (654) (1,110)
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:
Total assets $ 34,603 $ 33,648 $ 32,521 $ 33,112 $ 36,124
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
Accumulated deficit (680) (692) (1,005) (2,276) (1,146)
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
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Executive Summary
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)
Revenue:
US and Utilities SBU $ 3,918 $ 4,058 $ 4,230 -3 % -4 %
South America SBU 3,159 3,208 3,533 -2 % -9 %
MCAC SBU 1,766 1,882 1,728 -6 % 9 %
Eurasia SBU 828 1,047 1,255 -21 % -17 %
Corporate and Other 231 46 41 NM 12 %
Eliminations (242) (52) (51) NM 2 %
Total Revenue 9,660 10,189 10,736 -5 % -5 %
Operating Margin:
US and Utilities SBU 638 754 733 -15 % 3 %
South America SBU 1,243 873 1,017 42 % -14 %
MCAC SBU 559 487 534 15 % -9 %
Eurasia SBU 186 188 227 -1 % -17 %
Corporate and Other 120 39 58 NM -33 %
Eliminations (53) 8 4 NM 100 %
Total Operating Margin 2,693 2,349 2,573 15 % -9 %
General and administrative expenses (165) (196) (192) -16 % 2 %
Interest expense (1,038) (1,050) (1,056) -1 % -1 %
Interest income 268 318 310 -16 % 3 %
Loss on extinguishment of debt (186) (169) (188) 10 % -10 %
Other expense (53) (80) (58) -34 % 38 %
Other income 75 145 72 -48 % NM
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 %
NET INCOME 152 478 1,565 -68 % -69 %
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.
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Consolidated Revenue and Operating Margin
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Revenue
(in millions)
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.
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Operating Margin
(in millions)
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
Revenue
(in millions)
Consolidated Revenue - Revenue decreased $547 million, or 5%, in 2019 compared to 2018. Excluding the unfavorable FX impact of $133 million, primarily in South America, this decrease was driven by:
•$229 million in South America primarily driven by lower generation and prices in Argentina and lower contract sales and generation in Chile;
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•$173 million in Eurasia primarily due to the sales of the Masinloc power plant in March 2018 and the Northern Ireland businesses in June 2019; and
•$172 million in US and Utilities primarily driven by the closure of generation facilities at DPL in the first half of 2018 and Shady Point in May 2019, and lower energy prices and sales due to higher temperatures and other favorable market conditions present in 2018 as compared to 2019 at Southland, partially offset by price increases due to the 2018 rate orders at IPL and DPL and an increase in energy pass-through costs in El Salvador.
These unfavorable impacts were partially offset by an increase of $156 million in MCAC driven by the commencement of operations at the Colon combined cycle facility in Panama in September 2018.
Operating Margin
(in millions)
Consolidated Operating Margin - Operating margin decreased $224 million, or 9%, in 2019 compared to 2018. Excluding the unfavorable impact of FX of $46 million, primarily in South America, this decrease was driven by:
•$107 million in South America primarily due to the drivers discussed above;
•$46 million in MCAC due to the outage at Changuinola as a result of upgrading the tunnel lining and lower hydrology in Panama as compared to the prior year, partially offset by the business interruption insurance 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.
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Interest expense
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
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
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
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
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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
Argentina (1)
$ 29 $ (73) $ (71)
Corporate 21 (1) 11
Other 5 7 (12)
Total (2)
$ 55 $ (67) $ (72)
_____________________________
(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.
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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
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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;
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•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
Segments
We are organized into four market-oriented SBUs: US and Utilities (United States, Puerto Rico and El Salvador); South America (Chile, Colombia, Argentina and Brazil); MCAC (Mexico, Central America and the Caribbean); and Eurasia (Europe and Asia).
Non-GAAP Measures
Adjusted Operating Margin, Adjusted PTC and Adjusted EPS are non-GAAP supplemental measures that are used by management and external users of our Consolidated Financial Statements such as investors, industry analysts and lenders.
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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,
2020 2019 2018
Operating Margin $ 2,693 $ 2,349 $ 2,573
Noncontrolling interests adjustment (1)
(831) (670) (686)
Unrealized derivative losses 24 11 19
Disposition/acquisition losses 24 15 21
Net gains from early contract terminations at Angamos (182) - -
Restructuring costs (2)
- - 1
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.
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Adjusted PTC
We define Adjusted PTC as pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; (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,
2020 2019 2018
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
Pre-tax contribution 173 552 1,548
Unrealized derivative and equity securities losses 3 113 33
Unrealized foreign currency losses (gains) (10) 36 51
Disposition/acquisition losses (gains) 112 12 (934)
Impairment losses 928 406 307
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
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Adjusted EPS
We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, the tax impact from the repatriation of sales proceeds, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation; (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.
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Reconciliation of Adjusted EPS Years Ended December 31,
2020 2019 2018
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)
Impairment losses 1.39 (7) 0.61 (8) 0.46 (9)
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)
Adjusted EPS $ 1.44 $ 1.36 $ 1.24
_____________________________
(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.
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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
Operating Margin $ 638 $ 754 $ 733 $ (116) -15 % $ 21 3 %
Adjusted Operating Margin (1)
577 659 678 (82) -12 % (19) -3 %
Adjusted PTC (1)
505 569 511 (64) -11 % 58 11 %
_____________________________
(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
Other (13)
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)
Other 10
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.
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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
Operating Margin $ 1,243 $ 873 $ 1,017 $ 370 42 % $ (144) -14 %
Adjusted Operating Margin (1)
550 499 612 51 10 % (113) -18 %
Adjusted PTC (1)
534 504 519 30 6 % (15) -3 %
_____________________________
(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
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
Other (15)
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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MCAC 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
Operating Margin $ 559 $ 487 $ 534 $ 72 15 % $ (47) -9 %
Adjusted Operating Margin (1)
394 352 391 42 12 % (39) -10 %
Adjusted PTC (1)
287 367 300 (80) -22 % 67 22 %
_____________________________
(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)
Other
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
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
Increase in Mexico due to pension plan pass-through adjustment
Other (4)
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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Eurasia 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
Operating Margin $ 186 $ 188 $ 227 $ (2) -1 % $ (39) -17 %
Adjusted Operating Margin (1)
142 148 194 (6) -4 % (46) -24 %
Adjusted PTC (1)
177 159 222 18 11 % (63) -28 %
_____________________________
(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)
Other 4
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
Other 11
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.
COVID-19 Pandemic
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.
Decarbonization Initiatives
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
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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.
Regulatory
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.
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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.
Impairments
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
Overview
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
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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.
Long-Term Receivables
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,
Cash Sources: 2020 2019 2018
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 - -
Insurance proceeds 9 150 17
Other - 9 123
Total Cash Sources $ 14,744 $ 11,451 $ 10,693
Cash Uses:
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)
Capital expenditures (1,900) (2,405) (2,121)
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)
Other (258) (114) (155)
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
Operating activities $ 2,755 $ 2,466 $ 2,343 $ 289 $ 123
Investing activities (2,295) (2,721) (505) 426 (2,216)
Financing activities (78) (86) (1,643) 8 1,557
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Operating Activities
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)
(in millions)
(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)
(in millions)
(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.
Investing Activities
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
(in millions)
•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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Capital Expenditures
(in millions)
•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
(in millions)
•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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Capital Expenditures
(in millions)
•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.
Financing Activities
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
(in millions)
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
(in millions)
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.
Recourse Debt
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.
Non-Recourse Debt
While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:
•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 Footnote Reference(5)
Debt obligations (1) (2)
$ 20,163 $ 1,440 $ 1,539 $ 3,280 $ 13,904 $ - 11
Interest payments on long-term debt (3)
6,422 721 1,340 1,065 3,296 - n/a
Finance lease obligations (2)
157 5 10 8 134 - 14
Operating lease obligations (2)
645 29 57 52 507 - 14
Electricity obligations 7,552 700 947 868 5,037 - 12
Fuel obligations 5,191 1,370 1,424 952 1,445 - 12
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)
595 - 332 11 243 9 n/a
Total $ 46,782 $ 6,169 $ 6,890 $ 7,332 $ 26,382 $ 9
_____________________________
(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
Surety bond 1 1 $1
Total $ 1,546 112
_____________________________
(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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks
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 currencies: Argentine peso, Brazilian real, Chilean peso, Colombian peso, Dominican peso, Euro, and Mexican peso. These subsidiaries and affiliates have attempted to
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limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps, and options where possible to manage our risk related to certain foreign currency fluctuations.
AES enters into foreign currency hedges to protect economic value of the business and minimize the impact of foreign exchange rate fluctuations to AES' portfolio. While protecting cash flows, the hedging strategy is also designed to reduce forward-looking earnings foreign exchange volatility. Due to variation of timing and amount between cash distributions and earnings exposure, the hedge impact may not fully cover the earnings exposure on a realized basis, which could result in greater volatility in earnings. The largest foreign exchange risks over a 12-month forward-looking period stem from the following currencies: Brazilian real, Colombian peso, and Euro. As of December 31, 2020, assuming a 10% USD appreciation, cash distributions attributable to foreign subsidiaries exposed to movement in the exchange rate are projected to be impacted by less than $(5) million each for Brazilian real, Colombia peso, and Euro. These numbers have been produced by applying a one-time 10% USD appreciation to forecasted exposed cash distributions for 2021 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted cash distributions exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.
Interest Rate Risks
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable-rate and fixed-rate debt, as well as interest rate swap, cap, floor, and option agreements. Decisions on the fixed-floating debt mix are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant's capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed- or variable-rate financing. In certain cases, particularly for non-recourse financing, we execute interest rate swap, cap, and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of December 31, 2020, the portfolio's pre-tax earnings exposure for 2021 to a one-time 100-basis-point increase in interest rates for our Argentine peso, Brazilian real, Chilean peso, Colombian peso, Euro, and USD denominated debt would be approximately $20 million on interest expense for the debt denominated in these currencies. These amounts do not take into account the historical correlation between these interest rates.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of The AES Corporation:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of The AES Corporation (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 24, 2021, expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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Goodwill Impairment Evaluation of the Gener Reporting Unit
Description of the Matter The Company’s goodwill balance was $1,061 million at December 31, 2020, of which $868 million relates to the Gener reporting unit. As disclosed in Note 1 to the consolidated financial statements, the Company’s goodwill is tested for impairment at least annually at the reporting unit level. The goodwill impairment test at the Gener reporting unit involves the use of significant unobservable inputs to determine the fair value of the reporting unit. This estimate of fair value is compared to the carrying value of the reporting unit to determine whether goodwill is impaired.
Auditing the Company's measurement of the fair value of the Gener reporting unit involved a high degree of subjectivity given the lack of observable inputs to estimate the reporting unit’s fair value. Key inputs that had a significant impact on the valuation included the prospective financial information (including the estimated growth in renewable projects, forward electricity prices and developments in the Chilean capacity market) and the discount rate, which are forward-looking and based upon expectations about future economic and market conditions.
How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s goodwill impairment review process at the Gener reporting unit. For example, we tested controls over management’s review of the valuation model, the significant assumptions used to develop the estimates, and the completeness and accuracy of the data used in the valuations.
To test the estimated fair value of the Company’s Gener reporting unit, we performed audit procedures that included, among others, assessing the methodologies used to develop the estimate of fair value, testing the significant assumptions discussed above, and testing the completeness and accuracy of the underlying data used by the Company in its analyses. We compared the significant assumptions used by management to current industry and economic trends as well as historical results. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the reporting unit that would result from changes in the assumptions. We also involved valuation specialists to assist in our evaluation of the overall methodologies and the discount rate used in the fair value estimate.
Evaluation of Impairment Indicators and Re-evaluation of Useful Lives
Description of the Matter At December 31, 2020, the Company's property, plant and equipment had an aggregate net carrying value of approximately $22,826 million. As disclosed in Note 1 to the consolidated financial statements, when circumstances indicate the carrying amount of long-lived assets in a held-for-use asset group may not be recoverable, the Company evaluates the assets for potential impairment, and re-evaluates the remaining useful life. These circumstances may include, but are not limited to, changes in the regulatory environment, demand, power prices or fuel costs, technological advancements, physical deterioration, or an expectation it is more likely than not that the asset will be disposed of before the end of its useful life.
Auditing the Company's identification and evaluation of impairment indicators involved significant auditor judgment considering the many geographic, regulatory and economic environments in which the Company operates. Similarly, auditing the Company’s re-evaluation of useful lives required a high degree of subjectivity, particularly as it relates to the Company’s coal generation assets given the Company’s decarbonization initiatives and the potential risks associated with climate change that have led to increased regulation and other actions. These audit procedures required an evaluation of a wide variety of circumstances for potential changes in useful lives or impairment indicators.
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How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s identification of impairment indicators and estimation of useful lives (including any changes if necessary). This included management’s monitoring controls over businesses that have had been affected or are expected to be affected by the circumstances above.
Our audit procedures included, among others, making inquiries of management (including personnel in operations) to understand changes in the businesses, reading industry journals and publications to independently identify changes in the regulatory environments or the geographic areas and evaluating whether management has considered identified changes, if any. We considered businesses for which current power prices are significantly less than contractual prices within Power Purchase Agreements (PPAs) that are also near expiration. We also considered the Company’s ability to re-contract certain of its coal generation assets upon the expiration of a PPA, given the most recent legislative or regulatory changes. We evaluated the Company’s analysis of the useful lives of its coal generation assets, considering the existing PPAs and the Company’s ability to use the assets subsequent to the expiration of a PPA, based on any regulatory or market changes. For projects that were still under construction, we compared the Company's actual progress to their budgets, inspected engineering reports when considered appropriate, and considered project overruns. We reviewed disaggregated financial results for deterioration in earnings performance compared to prior periods, negative cash flows from operations, and working capital deficiencies and assessed whether these would represent impairment indicators, when applicable. We also considered and assessed conditions and trends in the industry and the underlying economies and evaluated sale or disposition activities.
Long-Lived Asset Impairment Evaluation of AES Gener
Description of the Matter As disclosed in Footnote 22 to the consolidated financial statements, the Company recognized an asset impairment expense at AES Gener in Chile as a result of the early termination of two PPAs at the Angamos coal-fired plant and the Company’s intention to accelerate the retirement of the Ventanas 1 and Ventanas 2 coal-fired plants. Based on the impairment analyses, the Company determined that the carrying amounts of these asset groups were not recoverable and recognized a $781 million asset impairment expense, which represented the amount by which the carrying value exceeded the estimated fair value of $306 million.
Auditing the Company’s long-lived asset impairment analyses involved significant judgment related to the assessment of the asset groups and estimation of the related fair value. The assessment of the asset groups required considerable judgment as varying facts and circumstances could justify different grouping of assets for impairment review. Auditing the Company’s estimates of the fair value of asset groups in AES Gener involved a high degree of subjectivity given the lack of observable inputs to estimate the fair value. Key inputs that had a significant impact on the valuation included the prospective financial information (including the retirement dates of the plants) and the discount rate, which are forward-looking and based upon expectations about future economic and market conditions.
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How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s long-lived asset impairment process. For example, we tested controls over management’s review of the valuation model, the significant assumptions used to develop the estimates, and the completeness and accuracy of the data used in the valuations.
Our audit procedures included, among others, obtaining an understanding of how the plants are managed at AES Gener given the regulatory changes, evaluating management’s assessment of the lowest level of identifiable cash flows, assessing the appropriateness of methodologies, testing the significant assumptions discussed above and testing the completeness and accuracy of the underlying data used by the Company in its analyses. We compared the significant assumptions used by management to current industry and economic trends, latest regulations as well as historical results. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the asset groups that would result from changes in the assumptions. We also involved valuation specialists to assist in our evaluation of the overall methodology and the discount rate used in the fair value estimate.
/s/ Ernst & Young LLP
We have served as the Company's auditor since 2008.
Tysons, Virginia
February 24, 2021
Consolidated Balance Sheets
December 31, 2020 and 2019
2020 2019
(in millions, except share and per share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,089 $ 1,029
Restricted cash 297 336
Short-term investments 335 400
Accounts receivable, net of allowance for doubtful accounts of $13 and $20, respectively
1,300 1,479
Inventory 461 487
Prepaid expenses 102 80
Other current assets, net of allowance of $0
726 802
Current held-for-sale assets 1,104 618
Total current assets 5,414 5,231
NONCURRENT ASSETS
Property, Plant and Equipment:
Land 417 447
Electric generation, distribution assets and other 26,707 25,383
Accumulated depreciation (8,472) (8,505)
Construction in progress 4,174 5,249
Property, plant and equipment, net 22,826 22,574
Other Assets:
Investments in and advances to affiliates 835 966
Debt service reserves and other deposits 441 207
Goodwill 1,061 1,059
Other intangible assets, net of accumulated amortization of $330 and $307, respectively
827 469
Deferred income taxes 288 156
Loan receivable, net of allowance of $0
- 1,351
Other noncurrent assets, net of allowance of $21 and $0, respectively
1,660 1,635
Noncurrent held-for-sale assets 1,251 -
Total other assets 6,363 5,843
TOTAL ASSETS $ 34,603 $ 33,648
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,156 $ 1,311
Accrued interest 191 201
Accrued non-income taxes 257 253
Deferred income 438 34
Accrued and other liabilities 1,223 987
Non-recourse debt, including $336 and $337, respectively, related to variable interest entities
1,430 1,868
Current held-for-sale liabilities 667 442
Total current liabilities 5,362 5,096
NONCURRENT LIABILITIES
Recourse debt 3,446 3,391
Non-recourse debt, including $3,918 and $3,872, respectively, related to variable interest entities
15,005 14,914
Deferred income taxes 1,100 1,213
Other noncurrent liabilities 3,241 2,917
Noncurrent held-for-sale liabilities 857 -
Total noncurrent liabilities 23,649 22,435
Commitments and Contingencies (see Notes 12 and 13)
Redeemable stock of subsidiaries 872 888
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 818,398,654 issued and 665,370,128 outstanding at December 31, 2020 and 817,843,916 issued and 663,952,656 outstanding at December 31, 2019)
8 8
Additional paid-in capital 7,561 7,776
Accumulated deficit (680) (692)
Accumulated other comprehensive loss (2,397) (2,229)
Treasury stock, at cost (153,028,526 and 153,891,260 shares at December 31, 2020 and December 31, 2019, respectively)
(1,858) (1,867)
Total AES Corporation stockholders’ equity 2,634 2,996
NONCONTROLLING INTERESTS 2,086 2,233
Total equity 4,720 5,229
TOTAL LIABILITIES AND EQUITY $ 34,603 $ 33,648
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Operations
Years ended December 31, 2020, 2019, and 2018
2020 2019 2018
(in millions, except per share amounts)
Revenue:
Regulated $ 2,661 $ 3,028 $ 2,939
Non-Regulated 6,999 7,161 7,797
Total revenue 9,660 10,189 10,736
Cost of Sales:
Regulated (2,235) (2,484) (2,473)
Non-Regulated (4,732) (5,356) (5,690)
Total cost of sales (6,967) (7,840) (8,163)
Operating margin 2,693 2,349 2,573
General and administrative expenses (165) (196) (192)
Interest expense (1,038) (1,050) (1,056)
Interest income 268 318 310
Loss on extinguishment of debt (186) (169) (188)
Other expense (53) (80) (58)
Other income 75 145 72
Gain (loss) on disposal and sale of business interests (95) 28 984
Asset impairment expense (864) (185) (208)
Foreign currency transaction gains (losses) 55 (67) (72)
Other non-operating expense (202) (92) (147)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES 488 1,001 2,018
Income tax expense (216) (352) (708)
Net equity in earnings (losses) of affiliates (123) (172) 39
INCOME FROM CONTINUING OPERATIONS 149 477 1,349
Loss from operations of discontinued businesses, net of income tax expense of $0, $0, and $2, respectively
- - (9)
Gain from disposal of discontinued businesses, net of income tax expense of $0, $0, and $44, respectively
3 1 225
NET INCOME 152 478 1,565
Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries (106) (175) (364)
Less: Loss from discontinued operations attributable to noncontrolling interests - - 2
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION $ 46 $ 303 $ 1,203
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax $ 43 $ 302 $ 985
Income from discontinued operations, net of tax 3 1 218
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION $ 46 $ 303 $ 1,203
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax $ 0.06 $ 0.46 $ 1.49
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax 0.01 - 0.33
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS $ 0.07 $ 0.46 $ 1.82
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax $ 0.06 $ 0.45 $ 1.48
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax 0.01 - 0.33
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS $ 0.07 $ 0.45 $ 1.81
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income (Loss)
Years ended December 31, 2020, 2019, and 2018
2020 2019 2018
(in millions)
NET INCOME $ 152 $ 478 $ 1,565
Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax (expense) benefit of $(8), $1, and $2, respectively
(52) (33) (161)
Reclassification to earnings, net of $0 income tax for all periods
192 23 (21)
Total foreign currency translation adjustments 140 (10) (182)
Derivative activity:
Change in derivative fair value, net of income tax benefit of $110, $74, and $27, respectively
(368) (265) (67)
Reclassification to earnings, net of income tax expense of $17, $12, and $24, respectively
74 42 93
Total change in fair value of derivatives (294) (223) 26
Pension activity:
Change in pension adjustments due to prior service cost, net of income tax benefit of $0, $0, and $1, respectively
1 1 (2)
Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax benefit of $4, $10, and $1, respectively
(14) (23) (1)
Reclassification to earnings, net of income tax expense of $0, $13, and $2, respectively
- 28 8
Total pension adjustments (13) 6 5
OTHER COMPREHENSIVE LOSS (167) (227) (151)
COMPREHENSIVE INCOME (LOSS) (15) 251 1,414
Less: Comprehensive loss (income) attributable to noncontrolling interests and redeemable stock of subsidiaries 4 (102) (425)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION $ (11) $ 149 $ 989
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Changes in Equity
Years ended December 31, 2020, 2019, and 2018
THE AES CORPORATION STOCKHOLDERS
Common Stock Treasury Stock Additional
Paid-In
Capital
Accumulated
Deficit
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
(in millions) Shares Amount Shares Amount
Balance at December 31, 2017 816.3 $ 8 155.9 $ (1,892) $ 8,501 $ (2,276) $ (1,876) $ 2,380
Net income - - - - - 1,203 - 360
Total foreign currency translation adjustment, net of income tax - - - - - - (235) 53
Total change in derivative fair value, net of income tax - - - - - - 14 10
Total pension adjustments, net of income tax - - - - - - 7 (2)
Total other comprehensive income (loss) - - - - - - (214) 61
Cumulative effect of a change in accounting principle (1)
- - - - - 68 19 81
Fair value adjustment (2)
- - - - (4) - - -
Disposition of business interests (3)
- - - - - - - (250)
Distributions to noncontrolling interests - - - - - - - (343)
Contributions from noncontrolling interests - - - - - - - 9
Dividends declared on AES common stock ($0.53/share)
- - - - (348) - - -
Issuance and exercise of stock-based compensation benefit plans, net of income tax 0.9 - (1.0) 14 8 - - -
Sales to noncontrolling interests - - - - (3) - - 98
Balance at December 31, 2018 817.2 $ 8 154.9 $ (1,878) $ 8,154 $ (1,005) $ (2,071) $ 2,396
Net income - - - - - 303 - 182
Total foreign currency translation adjustment, net of income tax - - - - - - - (10)
Total change in derivative fair value, net of income tax - - - - - - (166) (57)
Total pension adjustments, net of income tax - - - - - - 12 (6)
Total other comprehensive loss - - - - - - (154) (73)
Cumulative effect of a change in accounting principle (1)
- - - - - 10 (4) -
Fair value adjustment (2)
- - - - (6) - - -
Distributions to noncontrolling interests - - - - - - - (415)
Contributions from noncontrolling interests - - - - - - - 7
Dividends declared on AES common stock ($0.5528/share)
- - - - (367) - - -
Issuance and exercise of stock-based compensation benefit plans, net of income tax 0.6 - (1.0) 11 - - - -
Sales to noncontrolling interests - - - - (5) - - 136
Balance at December 31, 2019 817.8 $ 8 153.9 $ (1,867) $ 7,776 $ (692) $ (2,229) $ 2,233
Net income - - - - - 46 - 98
Total foreign currency translation adjustment, net of income tax - - - - - - 192 (52)
Total change in derivative fair value, net of income tax - - - - - - (237) (29)
Total pension adjustments, net of income tax - - - - - - (12) (1)
Total other comprehensive loss - - - - - - (57) (82)
Cumulative effect of a change in accounting principle (1)
- - - - - (34) - (16)
Fair value adjustment (2)
- - - - (4) - - -
Distributions to noncontrolling interests - - - - - - - (419)
Dividends declared on AES common stock ($0.5804/share)
- - - - (386) - - -
Issuance and exercise of stock-based compensation benefit plans, net of income tax 0.6 - (0.9) 9 4 - - -
Sales to noncontrolling interests - - - - 260 - 9 210
Acquisitions of noncontrolling interests - - - - (89) - (121) (49)
Issuance of preferred shares in subsidiaries - - - - - - 1 111
Balance at December 31, 2020 818.4 $ 8 153.0 $ (1,858) $ 7,561 $ (680) $ (2,397) $ 2,086
(1) See Note 1-General and Summary of Significant Accounting Policies for further information.
(2) Adjustment to record the redeemable stock of Colon at fair value.
(3) See Note 25-Held-for-Sale and Dispositions for further information.
See Accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Cash Flows
Years ended December 31, 2020, 2019, and 2018
2020 2019 2018
OPERATING ACTIVITIES: (in millions)
Net income $ 152 $ 478 $ 1,565
Adjustments to net income:
Depreciation and amortization 1,068 1,045 1,003
Loss (gain) on disposal and sale of business interests 95 (28) (984)
Impairment expense 1,066 277 355
Deferred income taxes (233) (8) 313
Provisions for (reversals of) contingencies (186) 3 14
Loss on extinguishment of debt 186 169 188
Loss (gain) on sale and disposal of assets (19) 54 27
Net gain from disposal and impairments of discontinued businesses - - (269)
Loss of affiliates, net of dividends 128 194 48
Other 208 321 269
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable 48 73 (206)
(Increase) decrease in inventory (20) 28 (36)
(Increase) decrease in prepaid expenses and other current assets 13 42 (22)
(Increase) decrease in other assets (134) (20) (32)
Increase (decrease) in accounts payable and other current liabilities (186) (6) 62
Increase (decrease) in income tax payables, net and other tax payables 59 (83) (7)
Increase (decrease) in deferred income 431 28 (12)
Increase (decrease) in other liabilities 79 (101) 67
Net cash provided by operating activities 2,755 2,466 2,343
INVESTING ACTIVITIES:
Capital expenditures (1,900) (2,405) (2,121)
Acquisitions of business interests, net of cash and restricted cash acquired (136) (192) (66)
Proceeds from the sale of business interests, net of cash and restricted cash sold 169 178 2,020
Sale of short-term investments 627 666 1,302
Purchase of short-term investments (653) (770) (1,411)
Contributions and loans to equity affiliates (332) (324) (145)
Insurance proceeds 9 150 17
Other investing (79) (24) (101)
Net cash used in investing activities (2,295) (2,721) (505)
FINANCING ACTIVITIES:
Borrowings under the revolving credit facilities 2,420 2,026 1,865
Repayments under the revolving credit facilities (2,479) (1,735) (2,238)
Issuance of recourse debt 3,419 - 1,000
Repayments of recourse debt (3,366) (450) (1,933)
Issuance of non-recourse debt 4,680 5,828 1,928
Repayments of non-recourse debt (4,136) (4,831) (1,411)
Payments for financing fees (107) (126) (39)
Distributions to noncontrolling interests (422) (427) (340)
Acquisitions of noncontrolling interests (259) - -
Sales to noncontrolling interests 553 128 95
Issuance of preferred shares in subsidiaries 112 - -
Dividends paid on AES common stock (381) (362) (344)
Payments for financed capital expenditures (60) (146) (275)
Other financing (52) 9 49
Net cash used in financing activities (78) (86) (1,643)
Effect of exchange rate changes on cash, cash equivalents and restricted cash (24) (18) (54)
(Increase) decrease in cash, cash equivalents and restricted cash of held-for-sale businesses (103) (72) 74
Total increase (decrease) in cash, cash equivalents and restricted cash 255 (431) 215
Cash, cash equivalents and restricted cash, beginning 1,572 2,003 1,788
Cash, cash equivalents and restricted cash, ending $ 1,827 $ 1,572 $ 2,003
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized $ 908 $ 946 $ 1,003
Cash payments for income taxes, net of refunds 333 363 370
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Dividends declared but not yet paid 100 95 90
Notes payable issued for the acquisition of the Ventus Wind Complex (see Note 26) 47 - -
Refinancing of non-recourse debt at Mong Duong (see Note 11) - 1,081 -
Contributions to equity affiliates (see Note 8) - 61 20
Partial reinvestment of consideration from the sPower transaction (see Note 8) - 58 -
Exchange of debentures for the acquisition of the Guaimbê Solar Complex (see Note 26) - - 119
Acquisition of the remaining interest in a Distributed Energy equity affiliate (see Note 26) - - 23
Acquisition of intangible assets - - 16
See Accompanying Notes to Consolidated Financial Statements.
127 | Notes to Consolidated Financial Statements | December 31, 2020, 2019 and 2018
Notes to Consolidated Financial Statements
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The AES Corporation is a holding company (the "Parent Company") that, through its subsidiaries and affiliates, (collectively, "AES" or "the Company") operates a geographically diversified portfolio of electricity generation and distribution businesses. Generally, the liabilities of individual operating entities are non-recourse to the Parent Company and are isolated to the operating entities. Most of our operating entities are structured as limited liability entities, which limit the liability of shareholders. The structure is generally the same regardless of whether a subsidiary is consolidated under a voting or variable interest model. The preparation of these consolidated financial statements is in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP").
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements of the Company include the accounts of The AES Corporation and its controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. Intercompany transactions and balances are eliminated in consolidation. Investments in entities where the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.
NONCONTROLLING INTERESTS - Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income on the Consolidated Statements of Operations and Consolidated Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.
Equity securities with redemption features that are not solely within the control of the issuer are classified outside of permanent equity. Generally, initial measurement will be at fair value. Subsequent measurement and classification vary depending on whether the instrument is probable of becoming redeemable. When the equity instrument is not probable of becoming redeemable, subsequent allocation of income and dividends is classified in permanent equity. For those securities where it is probable that the instrument will become redeemable or that are currently redeemable, AES recognizes changes in the fair value at each accounting period against retained earnings or additional paid-in-capital in the absence of retained earnings, subject to the floor of the initial fair value. Further, the allocation of income and dividends, as well as the adjustment to fair value, is classified outside permanent equity. Instruments that are mandatorily redeemable are classified as a liability.
EQUITY METHOD INVESTMENTS - Investments in entities over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and reported in Investments in and advances to affiliates on the Consolidated Balance Sheets. The Company’s proportionate share of the net income or loss of these companies is included in Net equity in earnings (losses) of affiliates on the Consolidated Statements of Operations.
The Company utilizes the cumulative earning approach to determine whether distributions received from equity method investees are returns on investment or returns of investment. The Company discontinues the application of the equity method when an investment is reduced to zero and the Company is not otherwise committed to provide further financial support to the investee. The Company resumes the application of the equity method accounting to the extent that net income is greater than the share of net losses not previously recorded.
Upon acquiring the investment, we determine the fair value of the identifiable assets and assumed liabilities and the basis difference between each fair value and the carrying amount of the corresponding asset or liability in the financial statements of the investee. The AES share of the amortization of the basis difference is recognized in Net equity in earnings (losses) of affiliates in the Consolidated Statements of Operations over the life of the asset or liability.
The Company periodically assesses if impairment indicators exist at our equity method investments. When an impairment is observed, any excess of the carrying amount over its estimated fair value is recognized as impairment
128 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
expense when the loss in value is deemed other-than-temporary and included in Other non-operating expense in the Consolidated Statements of Operations.
BUSINESS INTERESTS - Acquisitions and disposals of business interests are generally transactions pertaining to operational legal entities, which may be accounted for as a consolidated business, an asset, or an equity method investment. Losses on expected sales of business interests are limited to the impairment of long-lived assets as of the date of execution of the sales agreement, which are recognized in Asset impairment expense in the Consolidated Statements of Operations. Any additional gains/(losses) on sales, which are primarily due to reclassification of cumulative translation adjustments, are recognized in Gain (loss) on disposal and sale of business interests in the Consolidated Statements of Operations upon completion of the sale.
ALLOCATION OF EARNINGS - Certain of the Company's businesses are subject to profit-sharing arrangements where the allocation of cash distributions and the sharing of tax benefits are not based on fixed ownership percentages. These arrangements exist for certain U.S. renewable generation partnerships to designate different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership. For these businesses, the Company uses the hypothetical liquidation at book value (“HLBV”) method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions.
The HLBV method is used both to allocate the equity earnings attributable to AES when the Company accounts for the renewable business as an equity method investment and to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.
USE OF ESTIMATES - U.S. GAAP requires the Company to make estimates and assumptions that affect the asset and liability balances reported as of the date of the consolidated financial statements, as well as the revenues and expenses recognized during the reporting period. Actual results could differ from those estimates. Items subject to such estimates and assumptions include: the carrying amount and estimated useful lives of long-lived assets; asset retirement obligations; impairment of goodwill, long-lived assets and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of regulatory assets; regulatory liabilities; the fair value of financial instruments; the fair value of assets and liabilities acquired as business combinations or as asset acquisitions by variable interest entities; contingent consideration arising from business combinations or asset acquisitions by variable interest entities; the measurement of equity method investments or noncontrolling interest using the HLBV method for certain renewable generation partnerships; pension liabilities; the incremental borrowing rates used in the determination of lease liabilities; the determination of lease and non-lease components in certain generation contracts; environmental liabilities; and potential litigation claims and settlements.
HELD-FOR-SALE DISPOSAL GROUPS- A disposal group classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the disposal group exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long-lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the disposal group subsequently exceeds the carrying amount while the disposal group is still held-for-sale, any impairment expense previously recognized will be reversed up to the lesser of the previously recognized expense or the subsequent excess.
Assets and liabilities related to a disposal group classified as held-for-sale are segregated in the current balance sheet in the period in which the disposal group is classified as held-for-sale. Assets and liabilities of held-for-sale disposal groups are classified as current when they are expected to be disposed of within twelve months. Transactions between the held-for-sale disposal group and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 25-Held-for-Sale and Dispositions for further information.
129 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
DISCONTINUED OPERATIONS - Discontinued operations reporting occurs only when the disposal of a business or a group of businesses represents a strategic shift that has (or will have) a major effect on the Company's operations and financial results. The Company reports financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the Consolidated Statements of Operations and Consolidated Balance Sheets are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Consolidated Statements of Cash Flows.
Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value less cost to sell, including gains or losses associated with noncontrolling interests upon completion of the disposal transaction. Adjustments related to components previously reported as discontinued operations under prior accounting guidance are presented as discontinued operations in the current period even if the disposed-of component to which the adjustments are related would not meet the criteria for presentation as a discontinued operation under current guidance. See Note 24-Discontinued Operations for further information.
FAIR VALUE - Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly, hypothetical transaction between market participants at the measurement date, or exit price. The Company applies the fair value measurement accounting guidance to financial assets and liabilities in determining the fair value of investments in marketable debt and equity securities, included in the Consolidated Balance Sheet line items Short-term investments and Other noncurrent assets; derivative assets, included in Other current assets and Other noncurrent assets; and, derivative liabilities, included in Accrued and other liabilities (current) and Other noncurrent liabilities. The Company applies the fair value measurement guidance to nonfinancial assets and liabilities upon the acquisition of a business or an asset acquisition by a variable interest entity, or in conjunction with the measurement of an asset retirement obligation or a potential impairment loss on an asset group, equity method investments, or goodwill.
When determining the fair value measurements for assets and liabilities required to be reflected at their fair values, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the assets or liabilities, such as inherent risk, transfer restrictions and risk of nonperformance. The Company is prohibited from including transaction costs and any adjustments for blockage factors in determining fair value.
In determining fair value measurements, the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs. Assets and liabilities are categorized within a fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:
•Level 1: Quoted prices in active markets for identical assets or liabilities;
•Level 2: Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; or
•Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair values of the assets or liabilities.
Any transfers between all levels within the fair value hierarchy levels are recognized at the end of the reporting period.
CASH AND CASH EQUIVALENTS - The Company considers unrestricted cash on hand, cash balances not restricted as to withdrawal or usage, deposits in banks, certificates of deposit and short-term marketable securities with original maturities of three months or less to be cash and cash equivalents.
RESTRICTED CASH AND DEBT SERVICE RESERVES - Cash balances restricted as to withdrawal or usage, primarily via contract, are considered restricted cash.
130 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows (in millions):
December 31, 2020 December 31, 2019
Cash and cash equivalents $ 1,089 $ 1,029
Restricted cash 297 336
Debt service reserves and other deposits 441 207
Cash, Cash Equivalents and Restricted Cash $ 1,827 $ 1,572
INVESTMENTS IN MARKETABLE SECURITIES - The Company's marketable investments are primarily unsecured debentures, certificates of deposit, government debt securities and money market funds.
Short-term investments consist of marketable equity securities and debt securities with original maturities in excess of three months with remaining maturities of less than one year. Marketable debt securities where the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at amortized cost, net of any allowance for credit losses in accordance with ASC 326. Remaining marketable debt securities are classified as available-for-sale or trading and are carried at fair value.
Unrealized gains or losses on available-for-sale debt securities that are not credit-related are reflected in AOCL, a separate component of equity, and the Consolidated Statements of Operations, respectively. Any credit-related impairments are recognized as an allowance with a corresponding impact recognized as a credit loss in Other Expense. Unrealized gains or losses on equity investments are reported in Other income. Interest and dividends on investments are reported in Interest income and Other income, respectively. Gains and losses on sales of investments are determined using the specific identification method.
ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS - Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable, considering factors such as historical collection experience, the age of accounts receivable and other currently available evidence supporting collectability, and records an allowance for doubtful accounts in accordance with ASC 326 for the estimated uncollectible amount as appropriate. Credit losses on accounts and notes receivable are generally recognized in Cost of Sales. Certain of our businesses charge interest on accounts receivable. Interest income is recognized on an accrual basis. When collection of such interest is not reasonably assured, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectible.
INVENTORY - Inventory primarily consists of fuel and other raw materials used to generate power, and operational spare parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost or net realizable value. Cost is the sum of the purchase price and expenditures incurred to bring the inventory to its existing location. Inventory is primarily valued using the average cost method. Generally, if it is expected fuel inventory will not be recovered through revenue earned from power generation, an impairment is recognized to reflect the fuel at net realizable value. The carrying amount of spare parts and supplies is typically reduced only in instances where the items are considered obsolete.
LONG-LIVED ASSETS - Long-lived assets include property, plant and equipment, assets under finance leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).
Property, plant and equipment - Property, plant and equipment are stated at cost, net of accumulated depreciation. The cost of renewals and improvements that extend the useful life of property, plant and equipment are capitalized.
Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the construction project is deemed probable, or expensed at the time construction completion is determined to no longer be probable. The continued capitalization of such costs is subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Construction-in-progress balances are transferred to electric generation and distribution assets when an asset group is ready for its intended use. Government subsidies, liquidated damages recovered for construction delays, and income tax credits are recorded as a reduction to property, plant and equipment and reflected in cash flows from investing activities. Maintenance and repairs are charged to expense as incurred.
131 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Depreciation, after consideration of salvage value and asset retirement obligations, is computed using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. Capital spare parts, including rotable spare parts, are included in electric generation and distribution assets. If the spare part is considered a component, it is depreciated over its useful life after the part is placed in service. If the spare part is deemed part of a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.
Certain of the Company's subsidiaries operate under concession contracts. Certain estimates are utilized to determine depreciation expense for the subsidiaries, including the useful lives of the property, plant and equipment and the amounts to be recovered at the end of the concession contract. The amounts to be recovered under these concession contracts are based on estimates that are inherently uncertain and actual amounts recovered may differ from those estimates. These concession contracts are not within the scope of ASC 853-Service Concession Arrangements.
Intangible Assets Subject to Amortization - Finite-lived intangible assets are amortized over their useful lives which range from 1 - 50 years and are included in the Consolidated Balance Sheet line item Other intangible assets. The Company accounts for purchased emission allowances as intangible assets and records an expense when they are utilized or sold. Granted emission allowances are valued at zero.
Impairment of Long-lived Assets - When circumstances indicate the carrying amount of long-lived assets in a held-for-use asset group may not be recoverable, the Company evaluates the assets for potential impairment using internal projections of undiscounted cash flows resulting from the use and eventual disposal of the assets. Events or changes in circumstances that may necessitate a recoverability evaluation include, but are not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, or an expectation it is more likely than not that the asset will be disposed of before the end of its previously estimated useful life. If the carrying amount of the assets exceeds the undiscounted cash flows, an impairment expense is recognized for the amount by which the carrying amount of the asset group exceeds its fair value (subject to the carrying amount not being reduced below fair value for any individual long-lived asset that is determinable without undue cost and effort). An impairment expense for certain assets may be reduced by the establishment of a regulatory asset if recovery through approved rates is probable.
DEBT ISSUANCE COSTS - Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows used in financing activities.
GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS - The Company evaluates goodwill and indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. The Company's annual impairment testing date is October 1st.
Goodwill - Goodwill represents the excess of the purchase price of the business acquisition over the fair value of identifiable net assets acquired. Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the synergies of the acquisition. Generally, each AES business with a goodwill balance constitutes a reporting unit as they are not similar to other businesses in a segment nor are they reported to segment management together with other businesses.
Goodwill is evaluated for impairment either under the qualitative assessment option or the quantitative test option to determine the fair value of the reporting unit. If goodwill is determined to be impaired, an impairment loss measured at the amount by which the reporting unit’s carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.
Indefinite-Lived Intangible Assets - The Company's indefinite-lived intangible assets primarily include land-use rights and water rights. Indefinite-lived intangible assets are evaluated for impairment either under the qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense.
132 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES - Accounts payable consists of amounts due to trade creditors related to the Company's core business operations. These payables include amounts owed to vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and employee-related costs, including payroll, and benefits.
REGULATORY ASSETS AND LIABILITIES - The Company recognizes assets and liabilities that result from regulated ratemaking processes. Regulatory assets generally represent incurred costs which have been deferred due to the probable future recovery via customer rates. Generally, returns earned on regulatory assets are reflected in the Consolidated Statements of Operations within Interest Income. Regulatory liabilities generally represent obligations to refund customers. Management continually assesses whether regulatory assets are probable of future recovery and regulatory liabilities are probable of future payment by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities, and the status of any pending or potential deregulation legislation. If future recovery of costs previously deferred ceases to be probable, the related regulatory assets are written off and recognized in income from continuing operations.
PENSION AND OTHER POSTRETIREMENT PLANS - The Company recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in actuarial gains or losses recognized in AOCL, except for those plans at certain of the Company's regulated utilities that can recover portions of their pension and postretirement obligations through future rates. All plan assets are recorded at fair value. AES follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
INCOME TAXES - Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax basis. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company's tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
The Company has elected to treat GILTI as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.
The Company applies the flow-through method to account for its investment tax credits.
ASSET RETIREMENT OBLIGATIONS - The Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
FOREIGN CURRENCY TRANSLATION - A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the U.S. dollar translate their assets and liabilities into U.S. dollars at the current exchange rates in effect at the end of the fiscal period. Adjustments arising from the translation of the balance sheet of such subsidiaries are included in AOCL. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. dollars at the average exchange rates for the period. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in AOCL. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income. Accumulated foreign currency translation adjustments are reclassified from AOCL to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. The accumulated adjustments are included in
133 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
carrying amounts in impairment assessments where the Company has committed to a plan that will cause the accumulated adjustments to be reclassified to earnings.
REVENUE RECOGNITION - Revenue is earned from the sale of electricity from our utilities and the production and sale of electricity and capacity from our generation facilities. Revenue is recognized upon the transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Utilities - Our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. The majority of our utility contracts have a single performance obligation, as the promises to transfer energy, capacity, and other distribution and/or transmission services are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. Utility revenue is classified as regulated on the Consolidated Statements of Operations.
In exchange for the right to sell or distribute electricity in a service territory, our utility businesses are subject to government regulation. This regulation sets the framework for the prices (“tariffs”) that our utilities are allowed to charge customers for electricity. Since tariffs are determined by the regulator, the price that our utilities have the right to bill corresponds directly with the value to the customer of the utility's performance completed in each period. The Company also has some month-to-month contracts. Revenue under these contracts is recognized using an output method measured by the MWh delivered each month, which best depicts the transfer of goods or services to the customer, at the approved tariff.
The Company has businesses where it sells and purchases power to and from ISOs and RTOs. Our utility businesses generally purchase power to satisfy the demand of customers that is not contracted through separate PPAs. In these instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. In limited situations, a utility customer may choose to receive generation services from a third-party provider, in which case the Company may serve as a billing agent for the provider and recognize revenue on a net basis.
Generation - Most of our generation fleet sells electricity under contracts to customers such as utilities, industrial users, and other intermediaries. Our generation contracts, based on specific facts and circumstances, can have one or more performance obligations as the promise to transfer energy, capacity, and other services may or may not be distinct depending on the nature of the market and terms of the contract. As the performance obligations are generally satisfied over time and use the same method to measure progress, the performance obligations meet the criteria to be considered a series. In measuring progress toward satisfaction of a performance obligation, the Company applies the "right to invoice" practical expedient when available, and recognizes revenue in the amount to which the Company has a right to consideration from a customer that corresponds directly with the value of the performance completed to date. Revenue from generation businesses is classified as non-regulated on the Consolidated Statements of Operations.
For contracts determined to have multiple performance obligations, we allocate revenue to each performance obligation based on its relative standalone selling price using a market or expected cost plus margin approach. Additionally, the Company allocates variable consideration to one or more, but not all, distinct goods or services that form part of a single performance obligation when (1) the variable consideration relates specifically to the efforts to transfer the distinct good or service and (2) the variable consideration depicts the amount to which the Company expects to be entitled in exchange for transferring the promised good or service to the customer.
Revenue from generation contracts is recognized using an output method, as energy and capacity delivered best depicts the transfer of goods or services to the customer. Performance obligations including energy or ancillary services (such as operations and maintenance and dispatch services) are generally measured by the MWh delivered. Capacity, which is a stand-ready obligation to deliver energy when required by the customer, is measured using MWs. In certain contracts, if plant availability exceeds a contractual target, the Company may receive a performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent a form of variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal.
In assessing whether variable quantities are considered variable consideration or an option to acquire additional goods and services, the Company evaluates the nature of the promise and the legally enforceable rights
134 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
in the contract. In some contracts, such as requirement contracts, the legally enforceable rights merely give the customer a right to purchase additional goods and services which are distinct. In these contracts, the customer's action results in a new obligation, and the variable quantities are considered an option.
When energy or capacity is sold or purchased in the spot market or to ISOs, the Company assesses the facts and circumstances to determine gross versus net presentation of spot revenues and purchases. Generally, the nature of the performance obligation is to sell surplus energy or capacity above contractual commitments, or to purchase energy or capacity to satisfy deficits. Generally, on an hourly basis, a generator is either a net seller or a net buyer in terms of the amount of energy or capacity transacted with the ISO. In these situations, the Company recognizes revenue for the hours where the generator is a net seller and cost of sales for the hours where the generator is a net buyer.
Certain generation contracts contain operating leases where capacity payments are generally considered lease elements. In such cases, the allocation between the lease and non-lease elements is made at the inception of the lease following the guidance in ASC 842.
The transaction price allocated to a construction performance obligation is recognized as revenue over time as construction activity occurs, with revenue being fully recognized upon completion of construction. These contracts may include a difference in timing between revenue recognition and the collection of cash receipts, which may be collected over the term of the entire arrangement. The timing difference could result in a significant financing component for the construction performance obligation if determined to be a material component of the transaction price. The Company accounts for a significant financing component under the effective interest rate method, recognizing a long-term receivable for the expected future payments related to the construction performance obligation in the Loan Receivable line item on the Consolidated Balance Sheets. As payments are collected from the customer over the term of the contract, consideration related to the construction performance obligation is bifurcated between the principal repayment of the long-term receivable and the related interest income, recognized in the Consolidated Statements of Operations.
Contract Balances - The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. Accounts receivable represent unconditional rights to consideration and consist of both billed amounts and unbilled amounts typically resulting from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. We bill both generation and utilities customers on a contractually agreed-upon schedule, typically at periodic intervals (e.g., monthly). The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month.
Our contract liabilities consist of deferred revenue which is classified as current or noncurrent based on the timing of when we expect to recognize revenue. The current portion of our contract liabilities is reported in Accrued and other liabilities and the noncurrent portion is reported in Other noncurrent liabilities on the Consolidated Balance Sheets.
Remaining Performance Obligations - The transaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the reporting period. The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the amount disclosed in Note 20-Revenue excludes contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled. As such, consideration for energy is excluded from the amount disclosed as the variable consideration relates to the amount of energy delivered and reflects the value the Company expects to receive for the energy transferred. Estimates of revenue expected to be recognized in future periods also exclude unexercised customer options to purchase additional goods or services that do not represent material rights to the customer.
LEASES - The Company has operating and finance leases for energy production facilities, land, office space, transmission lines, vehicles and other operating equipment in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.
135 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the subsidiaries’ incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its unsecured borrowings, which are then adjusted for the appropriate lease term and currency. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes the option to extend or terminate the lease if it is reasonably certain that the option will be exercised.
The Company has operating leases for certain generation contracts that contain provisions to provide capacity to a customer, which is a stand-ready obligation to deliver energy when required by the customer in which the Company is the lessor. Capacity payments are generally considered lease elements as they cover the majority of available output from a facility. The allocation of contract payments between the lease and non-lease elements is made at the inception of the lease. Fixed lease payments from such contracts are recognized as lease revenue on a straight-line basis over the lease term, whereas variable lease payments are recognized when earned.
The Company has sales-type leases for BESS in which the Company is the lessor. These arrangements allow customers the ability to determine when to charge and discharge the BESS, representing the transfer of control and constitutes the arrangement as a sales-type lease. Upon commencement of the lease, the book value of the leased asset is removed from the balance sheet and a net investment in sales-type lease is recognized based on the present value of fixed payments under the contract and the residual value of the underlying asset.
SHARE-BASED COMPENSATION - The Company grants share-based compensation in the form of stock options, restricted stock units, performance stock units, and performance cash units. The expense is based on the grant-date fair value of the equity or liability instrument issued and is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. The Company uses a Black-Scholes option pricing model to estimate the fair value of stock options granted to its employees.
GENERAL AND ADMINISTRATIVE EXPENSES - General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. Additionally, all costs associated with corporate business development efforts are classified as general and administrative expenses.
DERIVATIVES AND HEDGING ACTIVITIES - Under the accounting standards for derivatives and hedging, the Company recognizes all contracts that meet the definition of a derivative, except those designated as normal purchase or normal sale at inception, as either assets or liabilities in the Consolidated Balance Sheets and measures those instruments at fair value. See Note 5-Fair Value and Fair value in this section for additional discussion regarding the determination of fair value.
PPAs and fuel supply agreements are evaluated to assess if they contain either a derivative or an embedded derivative requiring separate valuation and accounting. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could be net settled and meet the definition of a derivative.
The Company typically designates its derivative instruments as cash flow hedges if they meet the criteria specified in ASC 815, Derivatives and Hedging. The Company enters into interest rate swap agreements in order to hedge the variability of expected future cash interest payments. Foreign currency contracts are used to reduce risks arising from the change in fair value of certain foreign currency denominated assets and liabilities. The objective of these practices is to minimize the impact of foreign currency fluctuations on operating results. The Company also enters into commodity contracts to economically hedge price variability inherent in electricity sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot electricity prices and stabilize estimated revenue streams. The Company does not use derivative instruments for speculative purposes.
For our hedges, changes in fair value are deferred in AOCL and are recognized into earnings as the hedged transactions affect earnings. If a derivative is no longer highly effective, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, AES estimates the future cash flows of the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions.
136 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Changes in the fair value of derivatives not designated and qualifying as cash flow hedges are immediately recognized in earnings. Regardless of when gains or losses on derivatives are recognized in earnings, they are generally classified as interest expense for interest rate and cross-currency derivatives, foreign currency transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity and other derivatives. Cash flows arising from derivatives are included in the Consolidated Statements of Cash Flows as an operating activity given the nature of the underlying risk being economically hedged and the lack of significant financing elements, except that cash flows on designated and qualifying hedges of variable-rate interest during construction are classified as an investing activity. The Company has elected not to offset net derivative positions in the financial statements.
CREDIT LOSSES - In accordance with ASC 326, the Company records an allowance for current expected credit losses (“CECL”) for accounts and notes receivable, financing receivables, contract assets, net investments in leases recognized as a lessor, held-to-maturity debt securities, financial guarantees related to the non-payment of a financial obligation, and off-balance sheet credit exposures not accounted for as insurance. The CECL allowance is based on the asset's amortized cost and reflects management's expected risk of credit losses over the remaining contractual life of the asset. CECL allowances are estimated using relevant information about the collectibility of cash flows and consider information about past events, current conditions, and reasonable and supportable forecasts of future economic conditions. See New Accounting Pronouncements below for further information regarding the impact on the Company's financial statements upon adoption of ASC 326.
NEW ACCOUNTING PRONOUNCEMENTS - The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s consolidated financial statements.
New Accounting Standards Adopted
ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption
2016-13, 2018-19, 2019-04, 2019-05, 2019-10, 2019-11, 2020-02, 2020-03, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments See discussion of the ASU below.
January 1, 2020 See impact upon adoption of the standard below.
2016-02, 2018-01, 2018-10, 2018-11, 2018-20, 2019-01, Leases (Topic 842) See discussion of the ASU below. January 1, 2019 See impact upon adoption of the standard below.
2016-02, 2018-01, 2018-10, 2018-11, 2018-20, 2019-01, Leases (Topic 842) ASC 842 was adopted by sPower on January 1, 2020. sPower was not required to adopt ASC 842 using the public adoption date, as sPower is an equity method investee that meets the definition of a public business entity only by virtue of the inclusion of its summarized financial information in the Company’s SEC filings. January 1, 2020 The adoption of this standard resulted in a $4 million decrease to accumulated deficit attributable to the AES Corporation stockholders’ equity.
ASC 326 - Financial Instruments - Credit Losses
On January 1, 2020, the Company adopted ASC 326 Financial Instruments - Credit Losses and its subsequent corresponding updates (“ASC 326”). The new standard updates the impairment model for financial assets measured at amortized cost, known as the Current Expected Credit Loss (“CECL”) model. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a new forward-looking "expected loss" model that generally results in the earlier recognition of an allowance for credit losses. For available-for-sale debt securities with unrealized losses, entities 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 balance sheet with a corresponding adjustment to earnings in the income statement.
The Company applied the modified retrospective method of adoption for ASC 326. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The cumulative effect of the adoption of ASC 326 on our January 1, 2020 Condensed Consolidated Balance Sheet was as follows (in millions):
137 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Condensed Consolidated Balance Sheet Balance at
December 31, 2019
Adjustments Due to ASC 326 Balance at
January 1, 2020
Assets
Accounts receivable, net of allowance for doubtful accounts of $20
$ 1,479 $ - $ 1,479
Other current assets (1)
802 (2) 800
Deferred income taxes 156 9 165
Loan receivable, net of allowance of $32 (2)
1,351 (32) 1,319
Other noncurrent assets (3)
1,635 (30) 1,605
Liabilities and Equity
Accumulated deficit $ (692) $ (39) $ (731)
Noncontrolling interests 2,233 (16) 2,217
_________________________
(1)Other current assets include the short-term portion of the Mong Duong loan receivable, which was reclassified to Current held-for-sale assets on the Consolidated Balance Sheet as of December 31, 2020.
(2)Loan receivable at Mong Duong was reclassified to Noncurrent held-for-sale assets on the Consolidated Balance Sheet as of December 31, 2020.
(3)Other noncurrent assets include Argentina financing receivables.
Mong Duong - The Mong Duong II power plant in Vietnam is the primary driver of changes in credit reserves under the new standard. This plant is operated under a build, operate, and transfer (“BOT”) contract and will be transferred to the Vietnamese government after the completion of a 25-year PPA. A loan receivable was recognized in 2018 upon the adoption of ASC 606 in order to account for the future expected payments for the construction performance obligation portion of the BOT contract. As the payments for the construction performance obligation occur over a 25-year term, a significant financing element was determined to exist which is accounted for under the effective interest rate method. Historically, the Company has not incurred any losses on this arrangement, of which no directly comparable assets exist in the market. In order to determine expected credit losses under ASC 326 arising from this $1.4 billion loan receivable as of January 1, 2020, the Company considered average historical default and recovery rates on similarly rated sovereign bonds, which formed an initial basis for developing a probability of default, net of expected recoveries, to be applied as a key credit quality indicator for this arrangement. A resulting estimated loss rate of 2.4% was applied to the weighted-average remaining life of the loan receivable, after adjustments for certain asset-specific characteristics, including the Company’s status as a large foreign direct investor in Vietnam, Mong Duong’s status as critical energy infrastructure in Vietnam, and cash flows from the operations of the plant, which are under the Company’s control until the end of the BOT contract. As a result of this analysis, the Company recognized an opening CECL reserve of $34 million as an adjustment to Accumulated deficit and Noncontrolling interests as of January 1, 2020.
Argentina - Exposure to CAMMESA, the administrator of the wholesale energy market in Argentina, is the driver of credit reserves in Argentina. As discussed in Note 7-Financing Receivables, the Company has credit exposures through the FONINVEMEM Agreements, other agreements related to resolutions passed by the Argentine government in which AES Argentina will receive compensation for investments in new generation plants and technologies, as well as regular accounts receivable balances. The timing of collections depends on corresponding agreements and collectability of these receivables are assessed on an ongoing basis.
Collection of the principal and interest on these receivables is subject to various business risks and uncertainties, including, but not limited to, the continued operation of power plants which generate cash for payments of these receivables, regulatory changes that could impact the timing and amount of collections, and economic conditions in Argentina. The Company monitors these risks, including the credit ratings of the Argentine government, on a quarterly basis to assess the collectability of these receivables. Historically, the Company has not incurred any credit-related losses on these receivables. In order to determine expected credit losses under ASC 326, the Company considered historical default probabilities utilizing similarly rated sovereign bonds and historic recovery rates for Argentine government bond defaults. This information formed an initial basis for developing a probability of default, net of expected recoveries, to be applied as a key credit quality indicator across the underlying financing receivables. A resulting estimated weighted average loss rate of 41.2% was applied to the remaining balance of these receivables, after adjustments for certain asset-specific characteristics, including AES Argentina’s role in providing critical energy infrastructure to Argentina, our history of collections on these receivables, and the average term that the receivables are expected to be outstanding. As a result of this analysis, the Company recognized an opening CECL reserve of $29 million as an adjustment to Accumulated deficit as of January 1, 2020.
Other financial assets - Application of ASC 326 to the Company’s $1.5 billion of trade accounts receivable and $326 million of available-for-sale debt securities at January 1, 2020 did not result in any material adjustments, primarily due to the short-term duration and high turnover of these financial assets. Additionally, a large portion of
138 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
our trade accounts receivables and amounts reserved for doubtful accounts under legacy GAAP arise from arrangements accounted for as an operating lease under ASC 842, which are excluded from the scope of ASC 326.
As discussed in Note 7-Financing Receivables, AES Gener recorded $33 million of noncurrent receivables at December 31, 2019 pertaining to revenues recognized on regulated energy contracts that were impacted by the Stabilization Fund created by the Chilean government in October 2019. The Company expects to collect these noncurrent receivables through the execution of sale agreements with third parties. However, given the investment grade rating of Chile and the history of zero credit losses for regulated customers, management determined that no incremental CECL reserves were required to be recognized as of January 1, 2020.
The following table represents the rollforward of the allowance for credit losses from January 1, 2020 to December 31, 2020 (in millions):
Rollforward of CECL Reserves by Portfolio Segment Reserve at January 1, 2020 Current Period Provision Write-offs charged against allowance Recoveries Collected Foreign Exchange Reserve at December 31, 2020
Accounts Receivable (1)
$ 4 $ 11 $ (9) $ 3 $ - $ 9
Mong Duong Loan Receivable (2)
34 - - (2) - 32
Argentina Receivables 29 1 - (1) (9) 20
Other 1 - - - - 1
Total CECL Reserves $ 68 $ 12 $ (9) $ - $ (9) $ 62
_____________________________
(1)Excludes operating lease receivable allowances and contractual dispute allowances of $16 million and $4 million as of January 1, 2020 and December 31, 2020, respectively. Those reserves are not in scope under ASC 326.
(2)Mong Duong Loan Receivable credit losses allowance was reclassified to held-for-sale assets on the Consolidated Balance Sheet as of December 31, 2020.
ASC 842 - Leases
On January 1, 2019, the Company adopted ASC 842 Leases and its subsequent corresponding updates (“ASC 842”). Under this standard, lessees are required to recognize assets and liabilities for most leases on the balance sheet, and recognize expenses in a manner similar to the prior accounting method. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance eliminates previous real estate-specific provisions.
Under ASC 842, fewer of our contracts contain a lease. However, due to the elimination of the real estate-specific guidance and changes to certain lessor classification criteria, more leases qualify as sales-type leases and direct financing leases. Under these two models, a lessor derecognizes the asset and recognizes a lease receivable. According to ASC 842, the net investment in the lease includes the fair value of residual interest in the asset after the contract period as well as the present value of the fixed lease payments, but does not include any variable payments under the lease. Therefore, the net investment in the lease could be significantly different than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized net investment in the lease and the carrying amount of the underlying asset is recognized as a gain/loss at lease commencement.
During the course of adopting ASC 842, the Company applied various practical expedients including:
•The package of practical expedients (applied to all leases) that allowed lessees and lessors not to reassess:
a.whether any expired or existing contracts are or contain leases,
b.lease classification for any expired or existing leases, and
c.whether initial direct costs for any expired or existing leases qualify for capitalization under ASC 842.
•The transition practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements, and
•The transition practical expedient for lessees that allowed businesses to not separate lease and non-lease components. The Company applied the practical expedient to all classes of underlying assets when valuing right-of-use assets and lease liabilities. Contracts where the Company is the lessor were separated between the lease and non-lease components.
139 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The Company applied the modified retrospective method of adoption and elected to continue to apply the guidance in ASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The cumulative effect of the adoption of ASC 842 on our January 1, 2019 Consolidated Balance Sheet was as follows (in millions):
Consolidated Balance Sheet Balance at December 31, 2018 Adjustments Due to ASC 842 Balance at January 1, 2019
Assets
Other noncurrent assets $ 1,514 $ 253 $ 1,767
Liabilities
Accrued and other liabilities 962 27 989
Other noncurrent liabilities 2,723 226 2,949
The primary impact of adoption was due to the recognition of a right-of-use-asset and lease liability for an operating land lease in Panama associated with the Colon LNG power plant and regasification terminal.
New Accounting Pronouncements Issued But Not Yet Effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company’s consolidated financial statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company’s consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name Description Date of Adoption Effect on the financial statements upon adoption
2020-06, Debt - Debt with conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Equity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Equity’s Own Equity The amendments in this update affect entities that issue convertible instruments and/or contracts indexed to and potentially settled in an entity’s own equity. The new ASU eliminates the beneficial conversion and cash conversion accounting models for convertible instruments. It also amends the accounting for certain contracts in an entity’s own equity that are currently accounted for as derivatives because of specific settlement provisions. In addition, the new guidance modifies how particular convertible instruments and certain contracts that may be settled in cash or shares impact the diluted EPS computation. For fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2020-04 and 2021-01, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting The amendments in these updates provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference to LIBOR or another reference rate expected to be discontinued by reference rate reform, and clarify that certain optional expedients and exceptions in Topic 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. These amendments are effective for a limited period of time (March 12, 2020 - December 31, 2022). Effective for all entities as of March 12, 2020 through December 31, 2022. The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2. INVENTORY
Inventory is valued primarily using the average-cost method. The following table summarizes the Company's inventory balances as of the dates indicated (in millions):
December 31, 2020 2019
Fuel and other raw materials $ 223 $ 230
Spare parts and supplies 238 257
Total $ 461 $ 487
3. PROPERTY, PLANT AND EQUIPMENT
The following table summarizes the components of the electric generation and distribution assets and other property, plant and equipment (in millions) with their estimated useful lives (in years). The amounts are stated net of all prior asset impairment losses recognized.
140 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Estimated Useful Life December 31,
(in years) 2020 2019
Electric generation and distribution facilities 5-40
$ 24,239 $ 22,869
Other buildings 5-51
1,507 1,612
Furniture, fixtures and equipment 3-30
333 319
Other 5-39
628 583
Total electric generation and distribution assets and other 26,707 25,383
Accumulated depreciation (8,472) (8,505)
Net electric generation and distribution assets and other $ 18,235 $ 16,878
The following table summarizes depreciation expense (including the amortization of assets recorded under finance leases in 2020 and 2019 or capital leases in 2018, and the amortization of asset retirement obligations) and interest capitalized during development and construction on qualifying assets for the periods indicated (in millions):
Years Ended December 31, 2020 2019 2018
Depreciation expense $ 1,004 $ 977 $ 960
Interest capitalized during development and construction 307 238 199
Property, plant and equipment, net of accumulated depreciation, of $10 billion was mortgaged, pledged or subject to liens as of December 31, 2020 and 2019, including assets classified as held-for-sale.
The following table summarizes regulated and non-regulated generation and distribution property, plant and equipment and accumulated depreciation as of the dates indicated (in millions):
December 31, 2020 2019
Regulated generation and distribution assets and other, gross $ 8,858 $ 8,570
Regulated accumulated depreciation (3,329) (3,029)
Regulated generation and distribution assets and other, net 5,529 5,541
Non-regulated generation and distribution assets and other, gross 17,849 16,813
Non-regulated accumulated depreciation (5,143) (5,476)
Non-regulated generation and distribution assets and other, net 12,706 11,337
Net electric generation and distribution assets and other $ 18,235 $ 16,878
4. ASSET RETIREMENT OBLIGATIONS
The following table presents amounts recognized related to asset retirement obligations for the periods indicated (in millions):
2020 2019
Balance at January 1 $ 428 $ 415
Additional liabilities incurred 42 19
Liabilities settled (20) (12)
Accretion expense 22 21
Change in estimated cash flows 3 58
Sale of plants (13) (71)
Other - (2)
Balance at December 31 $ 462 $ 428
The Company's asset retirement obligations include active ash landfills, water treatment basins and the removal or dismantlement of certain plants and equipment. The Company uses the cost approach to determine the initial value of ARO liabilities, which is estimated by discounting expected cash outflows to their present value using market-based rates at the initial recording of the liabilities. Cash outflows are based on the approximate future disposal costs as determined by market information, historical information or other management estimates. Subsequent downward revisions of ARO liabilities are discounted using the market-based rates that existed when the liability was initially recognized. These inputs to the fair value of the ARO liabilities are considered Level 3 inputs under the fair value hierarchy.
During the year ended December 31, 2020, the Company increased the asset retirement obligations and corresponding assets at Chile and Hawaii, by $17 million and $12 million, respectively, and decreased the asset retirement obligation at DPL by $13 million. The increase at Chile is mostly due to the initial recognition of the ARO at Planta Solar II. The increase at Hawaii reflects the shortened useful life of the coal plant resulting from the passage of Senate Bill 2629, which prohibits issuing or renewing permits for coal power plants after December 31,
141 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
2022 and calls for ceasing all coal burning for electricity generation by that date. The decrease at DPL is attributable to the sale of the Hutchings facility in December 2020.
During the year ended December 31, 2019, the Company increased the asset retirement obligation and corresponding asset at IPL by $75 million and decreased the asset retirement obligation at DPL by $87 million. The increase at IPL reflects an increase to estimated ash pond closure costs, including groundwater remediation as required by the EPA under the Resource Conservation and Recovery Act. The decrease at DPL was attributable to a revision of the estimated liabilities resulting from the retirement of the Stuart and Killen facilities, and their subsequent transfer in December 2019.
5. FAIR VALUE
The fair value of current financial assets and liabilities, debt service reserves, and other deposits approximate their reported carrying amounts. The estimated fair values of the Company's assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Valuation Techniques - The fair value measurement accounting guidance describes three main approaches to measuring the fair value of assets and liabilities: (1) market approach, (2) income approach, and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of the return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill, and intangible assets (e.g., sales concessions, land use rights and water rights, etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, the value estimated under the income approach is often the most representative of fair value.
Investments - The Company's investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are either measured at fair value using quoted market prices or based on comparisons to market data obtained for similar assets. Debt securities primarily consist of unsecured debentures and certificates of deposit held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the market interest rates in Brazil. Debt securities are measured at fair value based on comparisons to market data obtained for similar assets.
Derivatives - Derivatives are measured at fair value using quoted market prices or the income approach utilizing volatilities, spot and forward benchmark interest rates (such as LIBOR and EURIBOR), foreign exchange rates, credit data, and commodity prices, as applicable. When significant inputs are not observable, the Company uses relevant techniques to determine the inputs, such as regression analysis or prices for similarly traded instruments available in the market.
The Company's methodology to fair value its derivatives is to start with any observable inputs; however, in certain instances the published forward rates or prices may not extend through the remaining term of the contract, and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. Specifically, where there is limited forward curve data with respect to foreign exchange contracts beyond the traded points, the Company utilizes the interest rate differential approach to construct the remaining portion of the forward curve. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable, requiring the use of proxy yield curves of similar credit quality.
To determine the fair value of a derivative, cash flows are discounted using the relevant spot benchmark interest rate. The Company then makes a credit valuation adjustment ("CVA"), as applicable, by further discounting the cash flows for nonperformance or credit risk based on the observable or estimated debt spread of the Company's subsidiary or its counterparty and the tenor of the respective derivative instrument. The CVA for potential
142 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
future scenarios in which the derivative is in an asset position is based on the counterparty's credit ratings, credit default swap spreads, and debt spreads, as available. The CVA for potential future scenarios in which the derivative is in a liability position is based on the Parent Company's or the subsidiary's current debt spread. In the absence of readily obtainable credit information, the Parent Company's or the subsidiary's estimated credit rating (based on applying a standard industry model to historical financial information and then considering other relevant information) and spreads of comparably rated entities or the respective country's debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.
The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are classified as Level 3 when the use of unobservable inputs is significant. When the use of unobservable inputs is insignificant, assets and liabilities are classified as Level 2. Transfers between Level 3 and Level 2 result from changes in significance of unobservable inputs used to calculate the CVA.
Debt - Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated based upon interest rates and other features of the loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow ("DCF") analyses. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date. The fair value was determined using available market information as of December 31, 2020. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to December 31, 2020.
Nonrecurring measurements - For nonrecurring measurements derived using the income approach, fair value is generally determined using valuation models based on the principles of DCF. The income approach is most often used in the impairment evaluation of long-lived tangible assets, equity method investments, goodwill, and intangible assets. Where the use of market observable data is limited or not available for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations. Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management in the valuation process.
For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to identify sale transactions of identical or similar assets. This approach is used in impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.
For nonrecurring measurements derived using the cost approach, fair value is typically based upon a replacement cost approach. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach.
Fair Value Considerations - In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty, and the risk of the Company's or its counterparty's nonperformance. The conditions and criteria used to assess these factors are:
Sources of market assumptions - The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Reuters). To determine fair value where market data is not readily available, management uses comparable market sources and empirical evidence to develop its own estimates of market assumptions.
Market liquidity - The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company's current trading volume, and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of assets traded without significantly affecting the market price. Another factor the Company considers when determining whether a market is active or inactive is the presence of government or regulatory controls over pricing that could make it difficult to establish a market-based price when entering into a transaction.
Nonperformance risk - Nonperformance risk refers to the risk that an obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited
143 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
to, the Company's or its counterparty's credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available, and the nature of master netting arrangements. The Company is party to various interest rate swaps and options, foreign currency options and forwards, and derivatives and embedded derivatives, which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.
Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from quoted market data to mark the investments to fair value.
Recurring Measurements - The following table presents, by level within the fair value hierarchy as described in Note 1-General and Summary of Significant Accounting Policies, the Company's financial assets and liabilities that were measured at fair value on a recurring basis as of the dates indicated (in millions). For the Company's investments in marketable debt securities, the security classes presented were determined based on the nature and risk of the security and are consistent with how the Company manages, monitors, and measures its marketable securities:
December 31, 2020 December 31, 2019
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
DEBT SECURITIES:
Available-for-sale:
Unsecured debentures $ - $ 21 $ - $ 21 $ - $ - $ - $ -
Certificates of deposit - 238 - 238 - 326 - 326
Total debt securities - 259 - 259 - 326 - 326
EQUITY SECURITIES:
Mutual funds 28 51 - 79 22 61 - 83
Total equity securities 28 51 - 79 22 61 - 83
DERIVATIVES:
Interest rate derivatives - 13 - 13 - 31 - 31
Cross-currency derivatives - 5 - 5 - - - -
Foreign currency derivatives - 15 146 161 - 17 93 110
Commodity derivatives - 8 2 10 - 28 2 30
Total derivatives - assets - 41 148 189 - 76 95 171
TOTAL ASSETS $ 28 $ 351 $ 148 $ 527 $ 22 $ 463 $ 95 $ 580
Liabilities
DERIVATIVES:
Interest rate derivatives $ - $ 374 $ 236 $ 610 $ - $ 144 $ 184 $ 328
Cross-currency derivatives - 2 2 4 - 10 11 21
Foreign currency derivatives - 43 - 43 - 44 - 44
Commodity derivatives - 22 - 22 - 29 2 31
Total derivatives - liabilities - 441 238 679 - 227 197 424
TOTAL LIABILITIES $ - $ 441 $ 238 $ 679 $ - $ 227 $ 197 $ 424
As of December 31, 2020, all AFS debt securities had stated maturities within one year. For the years ended December 31, 2019, and 2018, no other-than-temporary impairment of marketable securities were recognized in earnings or Other Comprehensive Income (Loss) and as of January 1, 2020, credit-related impairments are recognized in earnings under ASC 326. See Note 1-General and Summary of Significant Accounting Policies for further information. Gains and losses on the sale of investments are determined using the specific-identification method. The following table presents gross proceeds from sale of AFS securities for the periods indicated (in millions):
Year Ended December 31, 2020 2019 2018
Gross proceeds from sale of AFS securities $ 582 $ 663 $ 1,403
The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2020 and 2019 (presented net by type of derivative in millions). Transfers between Level 3 and Level 2 principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.
144 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Year Ended December 31, 2020 Interest Rate Cross Currency Foreign Currency Commodity Total
Balance at January 1 $ (184) $ (11) $ 94 $ (1) $ (102)
Total realized and unrealized gains (losses):
Included in earnings 3 (2) 67 2 70
Included in other comprehensive income - derivative activity (84) (10) 23 - (71)
Settlements 34 21 (39) 1 17
Transfers of assets/(liabilities), net into Level 3 (6) - - - (6)
Transfers of (assets)/liabilities, net out of Level 3 1 - 1 - 2
Balance at December 31 $ (236) $ (2) $ 146 $ 2 $ (90)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $ - $ (2) $ 35 $ 2 $ 35
Year Ended December 31, 2019 Interest Rate Cross Currency Foreign Currency Commodity Total
Balance at January 1 $ (140) $ - $ 199 $ 4 $ 63
Total realized and unrealized gains (losses):
Included in earnings (1) - (65) (2) (68)
Included in other comprehensive income - derivative activity (97) - (17) - (114)
Included in regulatory (assets) liabilities - - - (5) (5)
Settlements 8 - (23) 2 (13)
Transfers of assets/(liabilities), net into Level 3 (2) (11) - - (13)
Transfers of (assets)/liabilities, net out of Level 3 48 - - - 48
Balance at December 31 $ (184) $ (11) $ 94 $ (1) $ (102)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $ - $ - $ (67) $ (2) $ (69)
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) as of December 31, 2020 (in millions, except range amounts):
Type of Derivative Fair Value Unobservable Input Amount or Range
(Weighted Average)
Interest rate $ (236) Subsidiaries’ credit spreads 0.6% - 3.6% (3.5%)
Cross-currency (2) Subsidiaries’ credit spreads 3.6% - 3.6% (3.6%)
Foreign currency:
Argentine peso 146 Argentine peso to USD currency exchange rate after one year 86 - 1,027 (405)
Commodity:
Other 2
Total $ (90)
For interest rate derivatives and foreign currency derivatives, increases (decreases) in the estimates of the Company's own credit spreads would decrease (increase) the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the estimate of the above exchange rate would increase (decrease) the value of the derivative.
Nonrecurring Measurements
The Company measures fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the then-latest available carrying amount. The following table summarizes our major categories of assets measured at fair value on a nonrecurring basis and their level within the fair value hierarchy (in millions):
Year Ended December 31, 2020 Measurement Date Carrying Amount (1)
Fair Value Pre-tax
Loss
Assets Level 1 Level 2 Level 3
Long-lived assets held and used:
AES Gener (2)
8/1/2020 $ 1,087 $ - $ - $ 306 $ 781
Hawaii (2)
8/31/2020 114 - - 76 38
Estrella del Mar I (2)
9/30/2020 44 - - 14 30
Equity method investments:
OPGC (3)
03/31/2020 195 - - 152 43
OPGC (3)
06/30/2020 272 - 104 - 158
145 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Year Ended December 31, 2019 Measurement Date Carrying Amount (1)
Fair Value Pre-tax
Loss
Assets Level 1 Level 2 Level 3
Dispositions and held-for-sale businesses: (4)
Kilroot and Ballylumford 04/12/2019 $ 232 $ - $ 118 $ - $ 115
Long-lived assets held and used:
Hawaii (2)
12/31/2019 163 - - 103 60
Equity method investments:
OPGC (3)
12/31/2019 304 - - 212 92
_____________________________
(1)Represents the carrying values at the dates of initial measurement, before fair value adjustment.
(2)See Note 22-Asset Impairment Expense for further information.
(3)See Note 8-Investments In and Advances to Affiliates for further information.
(4)Per the Company's policy, pre-tax loss is limited to the impairment of long-lived assets. Any additional loss will be recognized on completion of the sale. See Note 22-Asset Impairment Expense and Note 25-Held-for-Sale and Dispositions for further information.
The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets held and used measured on a nonrecurring basis during the year ended December 31, 2020 (in millions, except range amounts):
December 31, 2020 Fair Value Valuation Technique Unobservable Input Range (Weighted Average)
Long-lived assets held and used:
AES Gener $ 306 Discounted cash flow Annual revenue growth (90)% to 10% (-2%)
Variable margin (94)% to 24% (-3%)
Weighted-average cost of capital 7% to 10%
Hawaii 76 Discounted cash flow Monthly revenue growth (12)% to 13% (0%)
Pre-tax operating margin 24% to 35% (29%)
Weighted-average cost of capital 10% to 13%
Estrella del Mar I 14 Comparable market transactions Sale price per kilowatt (USD) $160 to $520 ($315)
Age of unit when sold (years) 15 to 25 (18)
Equity method investments:
OPGC (1)
152 Expected present value Annual dividend growth (25)% to 40% (2%)
Weighted-average cost of equity 12 %
Total $ 548
_____________________________
(1)Fair value measurement performed as of March 31, 2020, which included the Level 3 inputs shown above. The fair value measurement performed at June 30, 2020 included only Level 2 inputs; therefore, it is not included in this table.
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
The following table presents (in millions) the carrying amount, fair value, and fair value hierarchy of the Company's financial assets and liabilities that are not measured at fair value in the Consolidated Balance Sheets as of the periods indicated, but for which fair value is disclosed:
December 31, 2020
Carrying
Amount
Fair Value
Total Level 1 Level 2 Level 3
Assets: Accounts receivable - noncurrent (1)
$ 97 $ 197 $ - $ - $ 197
Liabilities: Non-recourse debt 16,354 18,403 5 15,301 3,097
Recourse debt 3,446 3,677 - 3,677 -
December 31, 2019
Carrying
Amount
Fair Value
Total Level 1 Level 2 Level 3
Assets: Accounts receivable - noncurrent (1)
$ 98 $ 145 $ - $ - $ 145
Liabilities: Non-recourse debt 16,712 16,579 - 15,804 775
Recourse debt 3,396 3,529 - 3,529 -
_____________________________
(1)These amounts primarily relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and amounts related to green blend and extend agreements in Chile and are included in Other noncurrent assets in the accompanying Consolidated Balance Sheets. The fair value and carrying amount of the Argentina receivables exclude VAT of $4 million and $11 million as of December 31, 2020 and 2019, respectively. See Note 7-Financing Receivables for further information.
146 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Volume of Activity - The following table presents the Company's maximum notional (in millions) over the remaining contractual period by type of derivative as of December 31, 2020, regardless of whether they are in qualifying cash flow hedging relationships, and the dates through which the maturities for each type of derivative range:
Interest Rate and Foreign Currency Derivatives Maximum Notional Translated to USD Latest Maturity
Interest Rate (LIBOR and EURIBOR) $ 4,772 2047
Cross-currency swaps (Chilean Unidad de Fomento and Brazilian Reais) 246 2028
Foreign Currency:
Argentine peso 56 2026
Chilean peso 318 2022
Colombian peso 190 2023
Euro 149 2023
Others, primarily with weighted average remaining maturities of a year or less 31 2022
Commodity Derivatives Maximum Notional Latest Maturity
Natural Gas (in MMBtu) 23 2021
Power (in MWhs) 6 2024
Coal (in Tons or Metric Tonnes) 7 2027
Accounting and Reporting - Assets and Liabilities - The following tables present the fair value of assets and liabilities related to the Company's derivative instruments as of the periods indicated (in millions):
Fair Value December 31, 2020 December 31, 2019
Assets Designated Not Designated Total Designated Not Designated Total
Interest rate derivatives $ 13 $ - $ 13 $ 31 $ - $ 31
Cross-currency derivatives 5 - 5 - - -
Foreign currency derivatives 40 121 161 31 79 110
Commodity derivatives 2 8 10 - 30 30
Total assets $ 60 $ 129 $ 189 $ 62 $ 109 $ 171
Liabilities
Interest rate derivatives $ 506 $ 104 $ 610 $ 323 $ 5 $ 328
Cross-currency derivatives 4 - 4 21 - 21
Foreign currency derivatives 8 35 43 22 22 44
Commodity derivatives - 22 22 2 29 31
Total liabilities $ 518 $ 161 $ 679 $ 368 $ 56 $ 424
December 31, 2020 December 31, 2019
Fair Value Assets Liabilities Assets Liabilities
Current $ 51 $ 236 $ 72 $ 126
Noncurrent 138 443 99 298
Total $ 189 $ 679 $ 171 $ 424
Credit Risk-Related Contingent Features (1)
December 31, 2020 December 31, 2019
Present value of liabilities subject to collateralization $ 6 $ -
Cash collateral held by third parties or in escrow 6 -
_____________________________
(1) Based on the credit rating of certain subsidiaries
147 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
As of December 31, 2019, all derivative instruments subject to credit risk-related contingent features were in an asset position.
Earnings and Other Comprehensive Income (Loss) - The following table presents the pre-tax gains (losses) recognized in AOCL and earnings related to all derivative instruments for the periods indicated (in millions):
Years Ended December 31,
2020 2019 2018
Cash flow hedges
Gains (losses) recognized in AOCL
Interest rate derivatives $ (511) $ (290) $ (16)
Cross-currency derivatives 3 (26) (26)
Foreign currency derivatives 25 (23) (52)
Commodity derivatives 5 - -
Total $ (478) $ (339) $ (94)
Gains (losses) reclassified from AOCL to earnings
Interest rate derivatives $ (75) $ (28) $ (52)
Cross-currency derivatives (5) (12) (43)
Foreign currency derivatives (9) (13) (16)
Commodity derivatives (2) (1) (6)
Total $ (91) $ (54) $ (117)
Loss reclassified from AOCL to earnings due to discontinuance of hedge accounting (1)
$ - $ (2) $ -
Gain (losses) recognized in earnings related to
Ineffective portion of cash flow hedges $ - $ - $ (7)
Not designated as hedging instruments:
Interest rate derivatives (1) - -
Foreign currency derivatives 68 (46) 148
Commodity derivatives and other (68) (6) 25
Total $ (1) $ (52) $ 173
_____________________________
(1) Cash flow hedge was discontinued on a cross-currency swap in 2019 because the underlying debt was prepaid.
AOCL is expected to decrease pre-tax income from continuing operations for the twelve months ended December 31, 2021 by $98 million, primarily due to interest rate derivatives.
7. FINANCING RECEIVABLES
Receivables with contractual maturities of greater than one year are considered financing receivables. The following table presents financing receivables by country as of the dates indicated (in millions). As the Company applied the modified retrospective method of adoption for ASC 326 effective January 1, 2020, CECL reserves are included in the receivable balance as of December 31, 2020. See Note 1-General and Summary of Significant Accounting Policies for further information.
December 31, 2020 December 31, 2019
December 31, Gross Receivable Allowance Net Receivable Receivable
Argentina
$ 48 $ 9 $ 39 $ 64
Chile 31 - 31 33
Other
31 - 31 12
Total $ 110 $ 9 $ 101 $ 109
Argentina
Collection of the principal and interest on these receivables is subject to various business risks and uncertainties, including, but not limited to, the continued operation of power plants which generate cash for payments of these receivables, regulatory changes that could impact the timing and amount of collections, and economic conditions in Argentina. The Company monitors these risks, including the credit ratings of the Argentine government, on a quarterly basis to assess the collectability of these receivables. The Company accrues interest on these receivables once the recognition criteria have been met. The Company's collection estimates are based on assumptions that it believes to be reasonable, but are inherently uncertain. Actual future cash flows could differ from these estimates. The decrease in Argentina financing receivables was primarily due to planned collections and unfavorable FX impacts.
FONINVEMEM Agreements - As a result of energy market reforms in 2004 and 2010, AES Argentina entered into three agreements with the Argentine government, referred to as the FONINVEMEM Agreements, to contribute a
148 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
portion of their accounts receivable into a fund for financing the construction of combined cycle and gas-fired plants. These receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations.
The FONINVEMEM receivables are denominated in Argentine pesos, but indexed to USD, which represents a foreign currency derivative. Due to differences between spot rates, used to remeasure the receivables, and discounted forward rates, used to value the foreign currency derivative, these two items will not perfectly offset over the life of the receivable. Once settled, the foreign currency derivative will offset the accumulated unrealized foreign currency losses resulting from the devaluation of the FONINVEMEM receivable. As of December 31, 2020 and 2019, the amount of the foreign currency-related derivative assets associated with the FONINVEMEM financing receivables that were excluded from the table above had a fair value of $146 million and $94 million, respectively.
The receivables under the FONINVEMEM Agreements have been actively collected since the related plants commenced operations in 2010 and 2016. In assessing the collectability of the receivables under these agreements, the Company also considers historic collection evidence in accordance with the agreements.
Other Agreements - Other agreements primarily consist of resolutions passed by the Argentine government in which AES Argentina will receive compensation for investments in new generation plants and technologies. The timing of collections depend on corresponding agreements and collectability of these receivables are assessed on an ongoing basis.
Chile
AES Gener has recorded receivables pertaining to revenues recognized on regulated energy contracts that were impacted by the Stabilization Fund created by the Chilean government in October 2019, in conjunction with the Tariff Stabilization Law. Historically, the government updated the prices for these contracts every six months to reflect the indexation the contracts have to exchange rates and commodities prices. The Stabilization Fund does not allow the pass-through of these contractual indexation updates to customers beyond the pricing in effect at July 1, 2019, until new lower-cost renewable contracts are incorporated into pricing in 2023. Consequently, costs incurred in excess of the July 1, 2019 price will be accumulated and borne by generators.
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. As a result of the agreement, as of December 31, 2020, $77 million of current receivables and $8 million of noncurrent receivables were recorded in Accounts receivable and Other noncurrent assets, respectively, pertaining to the Stabilization Fund. Additionally, $23 million of payment deferrals granted to mining customers as part of our green blend and extend agreements were recorded as financing receivables included in Other noncurrent assets at December 31, 2020.
8. INVESTMENTS IN AND ADVANCES TO AFFILIATES
The following table summarizes the relevant effective equity ownership interest and carrying values for the Company's investments accounted for under the equity method as of the periods indicated:
December 31, 2020 2019 2020 2019
Affiliate Country Carrying Value (in millions) Ownership Interest %
sPower (1)
United States $ 551 $ 442 50 % 50 %
Uplight United States 85 91 32 % 32 %
Mesa La Paz Mexico 60 66 50 % 50 %
Energía Natural Dominicana Enadom (2)
Dominican Republic 49 48 43 % 43 %
OPGC India - 212 49 % 49 %
Guacolda (3)
Chile - 74 34 % 33 %
Barry (4)
United Kingdom - - 100 % 100 %
Other affiliates (5)
Various 90 33
Total $ 835 $ 966
_____________________________
(1)In January 2021, the sPower and AES Distributed Energy development platforms were merged to form AES Clean Energy Development. See Note 31-Subsequent Events for further information.
(2)The Company's ownership in Energía Natural Dominicana Enadom is held through AES Andres, an 85%-owned consolidated subsidiary. AES Andres owns 50% of Energía Natural Dominicana Enadom, resulting in an AES effective ownership of 43%.
(3)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 of 34%.
(4)Represents a VIE in which the Company holds a variable interest, but is not the primary beneficiary.
(5)Includes Bosforo, Fluence, and Tucano equity method investments, and others, as well as a $67 million loan facility granted from Colon to an equity method affiliate in 2020.
149 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
OPGC - In December 2019, an other-than-temporary impairment was identified at OPGC primarily due to the estimated market value of the Company's investment and other negative developments impacting future expected cash flows at the investee. A calculation of the fair value of the Company’s investment in OPGC was required to evaluate whether there was a loss in the carrying value of the investment. Based on management’s estimate of fair value of $212 million, the Company recognized an other-than-temporary impairment of $92 million in Other non-operating expense in December 2019. In March 2020, management’s updated estimate of fair value was $152 million and the Company recognized an additional other-than-temporary impairment of $43 million due to the economic slowdown.
In June 2020, the Company agreed to sell its entire 49% stake in OPGC resulting in an additional other-than-temporary impairment of $158 million. Total other-than-temporary impairment for the year ended December 31, 2020 was $201 million, recognized in Other non-operating expense. In December 2020, the Company completed the sale for $135 million, resulting in a pre-tax gain on sale of $23 million, primarily due to the write-off of cumulative translation adjustments. Prior to its sale, the OPGC equity method investment was reported in the Eurasia SBU reportable segment.
Fluence - 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. The Fluence equity method investment is reported as part of Corporate and Other.
Guacolda - In October 2019, Guacolda management reviewed the recoverability of the Guacolda asset group and determined the undiscounted cash flows did not exceed the carrying amount. Guacolda recognized a long-lived asset impairment at the investee level, which negatively impacted the Company's Net equity in earnings (losses) of affiliates by $158 million.
In September 2020, Guacolda management identified additional impairment indicators primarily as a result of inability to re-contract Guacolda’s generation after expiration of its existing PPAs driven by lower energy prices in Chile and reduced forecasted cash flows resulting from decarbonization initiatives of the Chilean Government. Guacolda recognized a long-lived asset impairment at the investee level, which negatively impacted the Company's Net equity in earnings (losses) of affiliates by $127 million. As a result, the Company’s basis in its investment in Guacolda was reduced to zero and the equity method of accounting was suspended. As of December 31, 2020, the Company has not recognized $99 million of equity method losses which were in excess of the Company’s carrying amount. The Guacolda equity method investment is reported in the South America SBU reportable segment.
Energía Natural Dominicana Enadom - In September 2019, AES Andres established a joint venture with Energas Group for the purpose of selling natural gas and related terminal services, storage, regasification, and transportation to customers in the Dominican Republic. Gas Natural del Este (subsequently renamed Energía Natural Dominicana Enadom), a wholly-owned subsidiary of the joint venture, acquired the Eastern Pipeline development project from AES Andres for total consideration of $55 million, resulting in a gain of $2 million. The transaction was considered a contribution of a nonfinancial asset in exchange for a noncontrolling interest in the joint venture. As the Company does not control the joint venture, it is accounted for as an equity method investment and is reported in the MCAC SBU reportable segment.
Uplight - In July 2019, Simple Energy merged with Tendril, a previously unrelated party, to form Uplight, a new company that offers a comprehensive platform for utility customer engagement. As part of this merger, the Company contributed its ownership interest in Simple Energy and $53 million of cash in exchange for an ownership interest in the merged company. This transaction resulted in a gain on sale of $12 million and a total investment in Uplight of $98 million. As the Company does not control Uplight, it is accounted for as an equity method investment and is reported as part of Corporate and Other.
sPower - In April 2019, the Company closed on the sale of approximately 48% of its interest in a portfolio of sPower’s operating assets for $173 million, subject to customary purchase price adjustments, of which $58 million was used to pay down debt at sPower. This sale resulted in a pre-tax gain on sale of business interests of $28 million. After the sale, the Company’s ownership interest in this portfolio of sPower’s operating assets decreased from 50% to approximately 26%. The sPower equity method investment is reported in the US and Utilities SBU reportable segment.
Barry - The Company holds a 100% ownership interest in AES Barry Ltd. ("Barry"), a dormant entity in the U.K. that disposed of its generation and other operating assets. Due to a debt agreement, no material financial or
150 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
operating decisions can be made without the banks' consent, and the Company does not control Barry. As of December 31, 2020 and 2019, other long-term liabilities included $46 million and $44 million related to this debt agreement.
Summarized Financial Information - The following tables summarize financial information of the Company's 50%-or-less-owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method (in millions):
50%-or-less Owned Affiliates Majority-Owned Unconsolidated Subsidiaries
Years ended December 31, 2020 2019 2018 2020 2019 2018
Revenue $ 1,880 $ 1,122 $ 962 $ 1 $ 49 $ 40
Operating margin (loss) 213 124 135 (3) (5) 3
Net income (loss) (538) (724) 14 (4) (7) (3)
December 31, 2020 2019 2020 2019
Current assets $ 1,017 $ 831 $ 159 $ 166
Noncurrent assets 6,230 7,220 886 982
Current liabilities 1,294 1,271 121 141
Noncurrent liabilities 3,671 3,966 981 1,052
Stockholders' equity 2,282 2,814 (57) (45)
At December 31, 2020, retained earnings included $120 million related to the undistributed losses of the Company's 50%-or-less owned affiliates. Distributions received from these affiliates were $14 million, $23 million, and $83 million for the years ended December 31, 2020, 2019, and 2018, respectively. As of December 31, 2020, the underlying equity in the net assets of our equity affiliates exceeded the aggregate carrying amount of our investments in equity affiliates by $150 million.
9. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill - The following table summarizes the carrying amount of goodwill by reportable segment for the years ended December 31, 2020 and 2019 (in millions):
US and Utilities South America MCAC Eurasia Total
Balance as of December 31, 2019
Goodwill $ 2,786 $ 868 $ 16 $ - $ 3,670
Accumulated impairment losses (2,611) - - - (2,611)
Net balance 175 868 16 - 1,059
Balance as of December 31, 2020
Goodwill 2,788 868 16 - 3,672
Accumulated impairment losses (2,611) - - - (2,611)
Net balance $ 177 $ 868 $ 16 $ - $ 1,061
Other Intangible Assets - The following table summarizes the balances comprising Other intangible assets in the accompanying Consolidated Balance Sheets (in millions) as of the periods indicated:
December 31, 2020 December 31, 2019
Gross Balance Accumulated Amortization Net Balance Gross Balance Accumulated Amortization Net Balance
Subject to Amortization
Internal-use software $ 386 $ (255) $ 131 $ 367 $ (228) $ 139
Contracts 157 (38) 119 134 (29) 105
Project development rights (1)
203 (5) 198 100 (1) 99
Emissions allowances (2)
64 - 64 24 - 24
Concession rights 201 (18) 183 39 (35) 4
Other (3)
59 (14) 45 43 (14) 29
Subtotal 1,070 (330) 740 707 (307) 400
Indefinite-Lived Intangible Assets
Land use rights 39 - 39 21 - 21
Water rights 20 - 20 20 - 20
Transmission rights 22 - 22 23 - 23
Other 6 - 6 5 - 5
Subtotal 87 - 87 69 - 69
Total $ 1,157 $ (330) $ 827 $ 776 $ (307) $ 469
_____________________________
(1)Includes emission offset fee to the Air Quality Management District (AQMD) in order to transfer emission offsets from retired legacy Southland units to the new CCGT.
151 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
(2)Acquired or purchased emissions allowances are finite-lived intangible assets that are expensed when utilized and included in net income for the year.
(3)Includes management rights, renewable energy credits and incentives, and other individually insignificant intangible assets.
The following tables summarize other intangible assets acquired during the periods indicated (in millions):
December 31, 2020 Amount Subject to Amortization/Indefinite-Lived Weighted Average Amortization Period (in years) Amortization Method
Internal-use software $ 35 Subject to Amortization 4 Straight-line
Contracts 28 Subject to Amortization 20 Straight-line
Project development rights 109 Subject to Amortization 30 Straight-line
Emissions allowances 56 Subject to Amortization Various As utilized
Transmission rights 20 Indefinite-Lived N/A N/A
Concession rights (1)
184 Subject to Amortization 12 Straight-line
Other 22 Various N/A N/A
Total $ 454
December 31, 2019 Amount Subject to Amortization/Indefinite-Lived Weighted Average Amortization Period (in years) Amortization
Method
Internal-use software $ 61 Subject to Amortization 5 Straight-line
Contracts 2 Subject to Amortization 35 Straight-line
Project development rights 8 Subject to Amortization 29 Straight-line
Emissions allowances 22 Subject to Amortization Various As utilized
Transmission rights 23 Indefinite-Lived N/A N/A
Other 5 Various N/A N/A
Total $ 121
_____________________________
(1)Represents the fair value assigned to the extension of the Tietê hydroelectric plants' concession agreement with ANEEL, expected to be finalized in the first quarter of 2021. See Note 13-Contingencies for further information.
The following table summarizes the estimated amortization expense by intangible asset category for 2021 through 2025:
(in millions) 2021 2022 2023 2024 2025
Internal-use software $ 36 $ 30 $ 25 $ 23 $ 21
Contracts 9 9 9 6 6
Concession rights 16 16 17 16 16
Other 9 9 8 8 7
Total $ 70 $ 64 $ 59 $ 53 $ 50
Intangible asset amortization expense was $54 million, $45 million and $47 million for the years ended December 31, 2020, 2019 and 2018, respectively.
152 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
10. REGULATORY ASSETS AND LIABILITIES
The Company has recorded regulatory assets and liabilities (in millions) that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:
December 31, 2020 2019 Recovery/Refund Period
Regulatory assets
Current regulatory assets:
El Salvador energy pass through costs recovery $ 40 $ 56 Quarterly
Other 73 57 1 year
Total current regulatory assets 113 113
Noncurrent regulatory assets:
IPL and DPL defined benefit pension obligations (1)
244 262 Various
IPL environmental costs 81 85 Various
IPL Petersburg Unit 1 retirement costs 75 - Over life of assets
IPL deferred Midwest ISO costs 61 75 6 years
Other 126 108 Various
Total noncurrent regulatory assets 587 530
Total regulatory assets $ 700 $ 643
Regulatory liabilities
Current regulatory liabilities:
Overcollection of costs to be passed back to customers $ 47 $ 80 1 year
Other 1 1 Various
Total current regulatory liabilities 48 81
Noncurrent regulatory liabilities:
IPL and DPL accrued costs of removal and AROs 863 863 Over life of assets
IPL and DPL income taxes payable to customers through rates 174 209 Various
Other 21 18 Various
Total noncurrent regulatory liabilities 1,058 1,090
Total regulatory liabilities $ 1,106 $ 1,171
_____________________________
(1)Past expenditures on which the Company earns a rate of return.
Our regulatory assets and current regulatory liabilities primarily consist of under or overcollection of costs that are generally non-controllable, such as purchased electricity, energy transmission, fuel costs, and other sector costs. These costs are recoverable or refundable as defined by the laws and regulations in our markets. Our regulatory assets also include defined pension and postretirement benefit obligations equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Additionally, our regulatory assets include the expected carrying value of IPL's Petersburg Unit 1 at its anticipated retirement date, which will be amortized over the life of the asset beginning on the date of retirement. Other current and noncurrent regulatory assets primarily consist of:
•Undercollections on rate riders such as wholesale margin sharing and MISO costs at IPL and energy efficiency and storm costs at DPL;
•Unamortized premiums reacquired or redeemed on long-term debt at IPL and DPL, which are amortized over the lives of the original issuances; and
•OVEC costs at DPL.
Our noncurrent regulatory liabilities primarily consist of obligations for removal costs which do not have an associated legal retirement obligation. Our noncurrent regulatory liabilities also include deferred income taxes related to differences in income recognition between tax laws and accounting methods, which will be passed through to our regulated customers via a decrease in future retail rates.
In the accompanying Consolidated Balance Sheets, current regulatory assets and liabilities are reflected in Other current assets and Accrued and other liabilities, respectively, and noncurrent regulatory assets and liabilities are reflected in Other noncurrent assets and Other noncurrent liabilities, respectively. All of the regulatory assets and liabilities as of December 31, 2020 and December 31, 2019 are related to the US and Utilities SBU.
153 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
11. DEBT
NON-RECOURSE DEBT - The following table summarizes the carrying amount and terms of non-recourse debt at our subsidiaries as of the periods indicated (in millions):
NON-RECOURSE DEBT Weighted Average Interest Rate Maturity December 31,
2020 2019
Variable Rate:
Bank loans 3.93% 2021 - 2050 $ 3,494 $ 3,389
Notes and bonds 3.11% 2023 - 2030 800 1,056
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1)
1.67% 2023 - 2033 457 460
Fixed Rate:
Bank loans 4.72% 2021 - 2040 2,965 2,900
Notes and bonds 5.20% 2021 - 2079 8,907 8,098
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1)
3.41% 2021 - 2023 34 1,110
Other 4.20% 2061 18 17
Unamortized (discount) premium & debt issuance (costs), net (321) (318)
Subtotal $ 16,354 $ 16,712
Less: Current maturities (2)
(1,426) (1,865)
Noncurrent maturities (2)
$ 14,928 $ 14,847
_____________________________
(1) Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
(2) Excludes $4 million and $3 million (current) and $77 million and $67 million (noncurrent) finance lease liabilities included in the respective non-recourse debt line items on the Consolidated Balance Sheet as of December 31, 2020 and 2019, respectively. See Note 14-Leases for further information.
The interest rate on variable rate debt represents the total of a variable component that is based on changes in an interest rate index and of a fixed component. The Company has interest rate swaps and option agreements that economically fix the variable component of the interest rates on the portion of the variable rate debt being hedged in an aggregate notional principal amount of approximately $2 billion on non-recourse debt outstanding at December 31, 2020.
Non-recourse debt as of December 31, 2020 is scheduled to reach maturity as shown below (in millions):
December 31, Annual Maturities
2021 $ 1,439
2022 516
2023 1,017
2024 1,307
2025 996
Thereafter 11,400
Unamortized (discount) premium & debt issuance (costs), net (321)
Total $ 16,354
As of December 31, 2020, AES subsidiaries with facilities under construction had a total of approximately $215 million of committed but unused credit facilities available to fund construction and other related costs. Excluding these facilities under construction, AES subsidiaries had approximately $868 million in various unused committed credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used for borrowings, letters of credit, or a combination of these uses.
154 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Significant transactions - During the year ended December 31, 2020, the Company's subsidiaries had the following significant debt transactions:
Subsidiary Transaction Period Issuances Repayments Gain (Loss) on Extinguishment of Debt
Southland (1)
Q1, Q2, Q4 $ 283 $ (125) $ (1)
AES Brasil Q2, Q3, Q4 375 (1) -
Gener Q1, Q2 90 (8) -
DPL (2)
Q2, Q3 555 (520) (34)
IPALCO Q2 475 (470) (2)
Mong Duong Q2 150 - -
Panama (3)
Q3 1,485 (1,228) (16)
Cochrane Q3 485 (445) (1)
Angamos Q3 - (309) (5)
_____________________________
(1)Issuances relate to the June 2017 long-term non-recourse debt financing to fund the Southland repowering construction projects.
(2)Includes transactions at DPL and its subsidiary, DP&L.
(3)Repayments relate to existing obligations at AES Panama, Changuinola, and Colon.
Panama - In August 2020, AES Panama issued $1.4 billion aggregate principal of 4.375% senior secured notes and a $105 million term loan due in 2030 and 2023, respectively. The proceeds from the issuance were used to prepay $447 million, $171 million, and $610 million of outstanding indebtedness at AES Panama, Changuinola, and Colon, respectively. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $16 million.
Cochrane - In November 2019, Cochrane issued $430 million aggregate principal of 5.50% senior unsecured notes due in 2027 and entered into a $445 million 6.25% senior secured facility agreement due in 2034. The net proceeds from the issuance and draw down were used to prepay the outstanding principal of $833 million under its variable rate notes due in 2030. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $24 million.
In July 2020, Cochrane issued $485 million aggregate principal of 6.25% senior secured notes due in 2034. The net proceeds from the issuance were used to prepay the outstanding principal of $445 million plus accrued interest on its senior secured facility agreement executed in 2019.
DPL - In April 2019, DPL issued $400 million aggregate principal of 4.35% senior unsecured notes due in 2029. The net proceeds from the issuance were used to redeem $400 million of the $780 million aggregate principal outstanding of its 7.25% senior unsecured notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $43 million.
In June 2020, DPL issued $415 million aggregate principal of 4.125% senior secured notes due in 2025. In July 2020, the net proceeds from the issuance were used to prepay the outstanding principal of $380 million of its 7.25% senior unsecured notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $34 million.
IPALCO - In April 2020, IPALCO issued $475 million aggregate principal of 4.25% senior secured notes due in 2030. The net proceeds from the issuance were used to prepay the outstanding principal of $405 million of its 3.45% senior unsecured notes and a $65 million term loan both due in July 2020. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $2 million.
Gener - In March 2019, Gener issued $550 million aggregate principal of 7.125% senior unsecured notes due in 2079. The net proceeds from the issuance were used to purchase via tender offer the outstanding principal of $450 million of its 8.375% senior unsecured notes due in 2073.
In October 2019, Gener issued $450 million aggregate principal of 6.35% senior unsecured notes due in 2079. The net proceeds from the issuance were used to fund the acquisition of Los Cururos, purchase via tender offer $73 million and $55 million aggregate principal of its senior unsecured notes due in 2021 and 2025, respectively, and prepay the remaining outstanding principal of $119 million of its senior unsecured notes due in 2021. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $29 million.
Mong Duong - In August 2019, Mong Duong refinanced $1.1 billion aggregate principal of its existing senior secured notes due in 2029 with variable interest rates ranging from LIBOR + 2.25% to LIBOR + 4.15% in exchange for a fixed rate loan with a newly formed SPV, accounted for as an equity affiliate, due in 2029 with interest rates
155 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
that vary from 4.41% to 7.18%. This refinancing was a non-cash transaction as the SPV acquired all of the outstanding rights and obligations of the original Mong Duong lenders. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $31 million. As of December 31, 2020, Mong Duong met the held-for-sale criteria and the outstanding debt balances were reclassified to held-for-sale liabilities on the Consolidated Balance Sheet.
DP&L - In June 2019, DP&L issued $425 million aggregate principal of 3.95% First Mortgage Bonds due in 2049. The net proceeds from the issuance were used to prepay the outstanding principal of $435 million under its variable rate $445 million credit agreement due in 2022.
Non-Recourse Debt Covenants, Restrictions and Defaults - The terms of the Company's non-recourse debt include certain financial and nonfinancial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include, but are not limited to, maintenance of certain reserves and financial ratios, minimum levels of working capital and limitations on incurring additional indebtedness.
As of December 31, 2020 and 2019, approximately $587 million and $372 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these amounts were included within Restricted cash and Debt service reserves and other deposits in the accompanying Consolidated Balance Sheets.
Various lender and governmental provisions restrict the ability of certain of the Company's subsidiaries to transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to approximately $1.7 billion at December 31, 2020.
The following table summarizes the Company's subsidiary non-recourse debt in default (in millions) as of December 31, 2020. Due to the defaults, these amounts are included in the current portion of non-recourse debt:
Primary Nature
of Default December 31, 2020
Subsidiary Debt in Default Net Assets
AES Puerto Rico Covenant $ 238 $ 171
AES Ilumina (Puerto Rico) Covenant 31 19
AES Jordan Solar Covenant 7 1
Total $ 276
The above defaults are not payment defaults. In Puerto Rico, the subsidiary non-recourse debt defaults were triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents due to the bankruptcy of the offtaker.
The AES Corporation's recourse debt agreements include cross-default clauses that will trigger if a subsidiary or group of subsidiaries for which the non-recourse debt is in default provides 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of December 31, 2020, the Company had no defaults which resulted in or were at risk of triggering a cross-default under the recourse debt of the Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its revolving credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the then-prevailing rate. Payment defaults and bankruptcy defaults would preclude the making of any restricted payments.
156 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
RECOURSE DEBT - The following table summarizes the carrying amount and terms of recourse debt of the Company as of the periods indicated (in millions):
Interest Rate Final Maturity December 31, 2020 December 31, 2019
Senior Unsecured Note 4.00% 2021 - 500
Senior Secured Term Loan LIBOR + 1.75% 2022 - 18
Senior Unsecured Note 4.875% 2023 - 613
Senior Unsecured Note 4.50% 2023 - 500
Drawings on revolving credit facility LIBOR + 1.75% 2024 70 180
Senior Unsecured Note 5.50% 2024 - 63
Senior Unsecured Note 5.50% 2025 - 544
Senior Unsecured Note 3.30% 2025 900 -
Senior Unsecured Note 6.00% 2026 - 500
Senior Unsecured Note 1.375% 2026 800 -
Senior Unsecured Note 5.125% 2027 - 500
Senior Unsecured Note 3.95% 2030 700 -
Senior Unsecured Note 2.45% 2031 1,000 -
Other (1)
CDI + 7.00% 2026 18 -
Unamortized (discount) premium & debt issuance (costs), net (41) (22)
Subtotal $ 3,447 $ 3,396
Less: Current maturities (1) (5)
Noncurrent maturities $ 3,446 $ 3,391
_____________________________
(1)Represents project-level limited recourse debt at AES Holdings Brasil Ltda.
The following table summarizes the principal amounts due under our recourse debt for the next five years and thereafter (in millions):
December 31, Net Principal Amounts Due
2021 $ 1
2022 3
2023 3
2024 74
2025 903
Thereafter 2,504
Unamortized (discount) premium & debt issuance (costs), net (41)
Total recourse debt $ 3,447
During the first quarter of 2020, the Company drew $840 million on revolving lines of credit at the Parent Company, of which approximately $250 million was used to enhance our liquidity position due to the uncertain economic conditions surrounding the COVID-19 pandemic, and the remaining $590 million was used for other general corporate purposes. During the remainder of 2020, the Parent Company drew an additional $755 million and repaid $1.5 billion on these revolving lines of credit. The entire $250 million related to the COVID-19 pandemic was repaid during the second quarter of 2020. As of December 31, 2020, we had approximately $70 million of outstanding indebtedness on the Parent Company credit facility at a weighted average interest rate of 1.86%.
In May 2020, the Company issued $900 million aggregate principal of 3.30% senior unsecured notes due in 2025 and $700 million of 3.95% senior unsecured notes due in 2030. The Company used the net proceeds from these issuances to purchase via tender offer a portion of the 4.00%, 4.50%, and 4.875% senior notes due in 2021, 2023, and 2023, respectively. Subsequent to the tender offers, the Company redeemed the remaining balance of its 4.00% and 4.875% senior notes due in 2021 and 2023, respectively, and $7 million of the remaining 4.50% senior notes due in 2023. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $37 million.
In December 2020, the Company issued $800 million aggregate principal of 1.375% senior unsecured notes due in 2026 and $1 billion aggregate principal of 2.45% senior unsecured notes due in 2031. The Company used the net proceeds from these issuances to purchase via tender offer the remaining balance of its 5.50%, 6.00%, and 5.125% senior notes due 2025, 2026, and 2027, respectively. Subsequent to the tender offers, the Company redeemed the remaining balance of its 4.50% and 5.50% notes due 2023 and 2024, respectively. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $108 million.
In September 2019, the Company prepaid $343 million aggregate principal of its LIBOR + 1.75% existing senior secured term loan due in 2022 and $100 million of its 4.875% senior unsecured notes due in 2023. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $5 million.
157 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Recourse Debt Covenants and Guarantees - The Company's obligations under the revolving credit facility and indentures governing the senior notes due 2025 and 2030 are currently unsecured following the achievement of two investment grade ratings and the release of security in accordance with the terms of the facility and the notes. If the Company’s credit rating falls below "Investment Grade" from at least two of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility and indenture dated May 15, 2020 (BBB-, or in the case of Moody’s Investor Services, Inc. Baa3), then the obligations under the revolving credit facility and the indentures governing the senior notes due 2025 and 2030 become, subject to certain exceptions, secured by (i) all of the capital stock of domestic subsidiaries owned directly by the Company or certain subsidiaries and 65% of the capital stock of certain foreign subsidiaries owned directly by the Company and certain subsidiaries,and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements.
The revolving credit facility is subject to mandatory prepayment under certain circumstances, including the sale of certain assets. In such a situation, a portion of the net cash proceeds from the sale must be applied pro rata to repay loans outstanding under the revolving credit facility and certain other indebtedness, if any, subject to customary reinvestment rights.
The revolving credit facility contains customary covenants and restrictions on the Company's ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.
The revolving credit facility also contains financial covenants, evaluated quarterly, requiring the Company to maintain a minimum ratio of adjusted operating cash flow to interest charges on recourse debt of 2.5 times and a maximum ratio of recourse debt to adjusted operating cash flow of 5.75 times.
The terms of the Company's senior notes contain certain customary covenants, including limitations on the Company's ability to incur liens or enter into sale and leaseback transactions.
12. COMMITMENTS
The Company enters into long-term contracts for construction projects, maintenance and service, transmission of electricity, operations services and purchases of electricity and fuel. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances. The following table shows the future minimum commitments for continuing operations under these contracts as of December 31, 2020 for 2021 through 2025 and thereafter as well as actual purchases under these contracts for the years ended December 31, 2020, 2019, and 2018 (in millions):
Actual purchases during the year ended December 31, Electricity Purchase Contracts Fuel Purchase Contracts Other Purchase Contracts
2018 $ 827 $ 1,838 $ 1,671
2019 1,597 1,824 1,684
2020 756 1,573 1,506
Future commitments for the year ending December 31,
2021 $ 700 $ 1,370 $ 1,904
2022 500 815 636
2023 447 609 605
2024 434 495 570
2025 434 457 526
Thereafter 5,037 1,445 1,816
Total $ 7,552 $ 5,191 $ 6,057
13. CONTINGENCIES
Guarantees and Letters of Credit - In connection with certain project financings, acquisitions and dispositions, power purchases, and other agreements, the Parent Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, the Parent Company has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish
158 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
their intended business purposes. Most of the contingent obligations relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to no more than 15 years.
The following table summarizes the Parent Company's contingent contractual obligations as of December 31, 2020. Amounts presented in the following table represent the Parent Company's current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. There were 5 obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses.
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
Surety bond 1 1 $1
Total $ 1,546 112
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 of letters of credit.
Environmental - The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. For the periods ended December 31, 2020 and 2019, the Company recognized liabilities of $5 million and $4 million for projected environmental remediation costs, respectively. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Moreover, where no liability has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of December 31, 2020. In aggregate, the Company estimates the range of potential losses related to environmental matters, where estimable, to be up to $12 million. The amounts considered reasonably possible do not include amounts accrued as discussed above.
Litigation - The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has recognized aggregate liabilities for all claims of approximately $28 million and $55 million as of December 31, 2020 and 2019, respectively. These amounts are reported on the Consolidated Balance Sheets within Accrued and other liabilities and Other noncurrent liabilities. A significant portion of these accrued liabilities relate to regulatory matters and commercial disputes in international jurisdictions. There can be no assurance that these accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
Where no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2020. The material contingencies where a loss is reasonably possible primarily include disputes with offtakers, suppliers and EPC contractors; alleged breaches of contract; alleged violation of laws and regulations; income tax and non-income tax matters with tax authorities; and regulatory matters. In aggregate, the Company estimates the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between $245 million and $933 million. The amounts considered reasonably possible do not include the amounts accrued, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.
Tietê GSF Settlement - In December 2020, ANEEL published a regulation establishing the terms and conditions for compensation to Tietê for the non-hydrological risk charged to hydro generators through the incorrect application of the GSF mechanism from 2013 until 2018. In accordance with the regulation, this compensation will be 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
159 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
recognition as a definite-lived intangible asset, which will be amortized from the date of the agreement 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, which has been determined to be fair value. Both the concession extension period and its equivalent asset value are subject to a final agreement between ANEEL and AES.
14. LEASES
LESSEE - Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in millions):
Consolidated Balance Sheet Classification December 31, 2020 December 31, 2019
Assets
Right-of-use assets - finance leases Electric generation, distribution assets and other $ 74 $ 67
Right-of-use assets - operating leases Other noncurrent assets 275 248
Total right-of-use assets $ 349 $ 315
Liabilities
Finance lease liabilities (current) Non-recourse debt (current liabilities) $ 4 $ 3
Finance lease liabilities (noncurrent) Non-recourse debt (noncurrent liabilities) 77 67
Total finance lease liabilities 81 70
Operating lease liabilities (current) Accrued and other liabilities 17 16
Operating lease liabilities (noncurrent) Other noncurrent liabilities 293 261
Total operating lease liabilities 310 277
Total lease liabilities $ 391 $ 347
The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:
Lease Term and Discount Rate December 31, 2020 December 31, 2019
Weighted-average remaining lease term - finance leases 31 years 32 years
Weighted-average remaining lease term - operating leases 23 years 23 years
Weighted-average discount rate - finance leases 4.11 % 4.99 %
Weighted-average discount rate - operating leases 6.81 % 6.99 %
The following table summarizes the components of lease expense recognized in Cost of Sales on the Consolidated Statements of Operations for the years ended (in millions):
Twelve Months Ended December 31,
Components of Lease Cost
2020 2019
Operating lease cost $ 36 $ 46
Finance lease cost:
Amortization of right-of-use assets 3 2
Interest on lease liabilities 4 2
Short-term lease costs 13 38
Variable lease cost - 1
Total lease cost $ 56 $ 89
Operating cash outflows from operating leases included in the measurement of lease liabilities were $41 million and $48 million for the twelve months ended December 31, 2020 and 2019, respectively, and operating cash outflows from finance leases were $2 million for the twelve months ended December 31, 2020. Right-of-use assets obtained in exchange for new operating lease liabilities were $37 million for the twelve months ended December 31, 2020.
160 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The following table shows the future lease payments under operating and finance leases for continuing operations together with the present value of the net lease payments as of December 31, 2020 for 2021 through 2025 and thereafter (in millions):
Maturity of Lease Liabilities
Finance Leases Operating Leases
2021 $ 5 $ 29
2022 5 29
2023 5 28
2024 4 27
2025 4 25
Thereafter 134 507
Total 157 645
Less: Imputed interest (76) (335)
Present value of lease payments $ 81 $ 310
LESSOR - The Company has operating leases for certain generation contracts that contain provisions to provide capacity to a customer, which is a stand-ready obligation to deliver energy when required by the customer. Capacity payments are generally considered lease elements as they cover the majority of available output from a facility. The allocation of contract payments between the lease and non-lease elements is made at the inception of the lease. Lease payments from such contracts are recognized as lease revenue on a straight-line basis over the lease term, whereas variable lease payments are recognized when earned.
The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in millions):
Twelve Months Ended December 31,
Lease Income 2020 2019
Total Lease Revenue $ 580 $ 600
Less: Variable Lease Payments 66 70
Total Non-Variable Lease Revenue $ 514 $ 530
The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, Plant and Equipment for the periods indicated (in millions):
Twelve Months Ended December 31,
Lease Income 2020 2019
Gross Assets $ 3,103 $ 2,909
Accumulated Depreciation 1,011 707
Net Assets $ 2,092 $ 2,202
The option to extend or terminate a lease is based on customary early termination provisions in the contract, such as payment defaults, bankruptcy, and lack of performance on energy delivery. The Company has not recognized any early terminations as of December 31, 2020. Certain leases may provide for variable lease payments based on usage or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments.
The following table shows the future lease receipts as of December 31, 2020 for 2021 through 2025 and thereafter (in millions):
Future Cash Receipts for
Sales-Type Leases Operating Leases
2021 $ 2 $ 489
2022 2 475
2023 3 411
2024 3 412
2025 3 412
Thereafter 39 1,034
Total 52 $ 3,233
Less: Imputed interest (24)
Present value of total lease receipts $ 28
Battery Storage Lease Arrangements - The Company is constructing and operating projects that pair BESS with solar energy systems, which allows the project more flexibility on when to provide energy to the grid. The Company will enter into PPAs for the full output of the facility that allow customers the ability to determine when to charge and discharge the BESS. These arrangements include both lease and non-lease elements under ASC 842, with the BESS component constituting a sales-type lease. Upon commencement of the lease, the book value of the
161 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
leased asset is removed from the balance sheet and a net investment in sales-type lease is recognized based on the present value of fixed payments under the contract and the residual value of the underlying asset. Due to the variable nature of lease payments under these contracts, the Company recorded losses at commencement of sales-type leases of $36 million for the year ended December 31, 2019. These amounts are recognized in Other expense in the Consolidated Statement of Operations. See Note 21-Other Income and Expense for further information. The Company recognized lease income on sales-type leases through variable payments of $5 million and interest income of $2 million for the year ended December 31, 2020.
15. BENEFIT PLANS
Defined Contribution Plan - The Company sponsors four defined contribution plans ("the DC Plans"). Two plans cover U.S. non-union employees; one for Parent Company and certain US and Utilities SBU business employees, and one for DPL employees. The remaining two plans include union and non-union employees at IPL and union employees at DPL. The DC Plans are qualified under section 401 of the Internal Revenue Code. Most U.S. employees of the Company are eligible to participate in the appropriate plan except for those employees who are covered by a collective bargaining agreement, unless such agreement specifically provides that the employee is considered an eligible employee under a plan. Within the DC Plans, the Company provides matching contributions in addition to other non-matching contributions. Participants are fully vested in their own contributions. The Company's contributions vest over various time periods ranging from immediate up to five years. For the years ended December 31, 2020, 2019 and 2018, costs for defined contribution plans were approximately $21 million, $19 million and $21 million, respectively.
Defined Benefit Plans - Certain of the Company's subsidiaries have defined benefit pension plans covering substantially all of their respective employees ("the DB Plans"). Pension benefits are based on years of credited service, age of the participant, and average earnings. Of the 28 active DB Plans as of December 31, 2020, five are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.
The following table reconciles the Company's funded status, both domestic and foreign, as of the periods indicated (in millions):
2020 2019
U.S. Foreign U.S. Foreign
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Benefit obligation as of January 1 $ 1,242 $ 224 $ 1,118 $ 417
Service cost 12 6 11 8
Interest cost 35 14 44 19
Employee contributions - - - -
Plan amendments 1 - - -
Plan curtailments - (6) - -
Plan settlements - - - -
Benefits paid (81) (9) (65) (9)
Plan combinations - - - -
Divestitures - - - (244)
Actuarial (gain) loss 122 19 134 37
Effect of foreign currency exchange rate changes - (30) - (4)
Benefit obligation as of December 31 $ 1,331 $ 218 $ 1,242 $ 224
CHANGE IN PLAN ASSETS:
Fair value of plan assets as of January 1 $ 1,154 $ 129 $ 1,026 $ 410
Actual return on plan assets 168 13 185 19
Employer contributions 8 5 8 5
Employee contributions - - - -
Plan settlements - - - -
Benefits paid (81) (9) (65) (9)
Divestitures - - - (296)
Effect of foreign currency exchange rate changes - (26) - -
Fair value of plan assets as of December 31 $ 1,249 $ 112 $ 1,154 $ 129
RECONCILIATION OF FUNDED STATUS
Funded status as of December 31 $ (82) $ (106) $ (88) $ (95)
162 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the funded status of the DB Plans, both domestic and foreign, as of the periods indicated (in millions):
December 31, 2020 2019
Amounts Recognized on the Consolidated Balance Sheets U.S. Foreign U.S. Foreign
Noncurrent assets $ 9 $ - $ - $ -
Accrued benefit liability-current - (8) - (7)
Accrued benefit liability-noncurrent (91) (98) (88) (88)
Net amount recognized at end of year $ (82) $ (106) $ (88) $ (95)
The following table summarizes the Company's U.S. and foreign accumulated benefit obligation as of the periods indicated (in millions):
December 31, 2020 2019
U.S. Foreign U.S. Foreign
Accumulated Benefit Obligation $ 1,306 $ 199 $ 1,224 $ 188
Information for pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation $ 494 $ 218 $ 1,242 $ 197
Accumulated benefit obligation 481 199 1,224 178
Fair value of plan assets 403 112 1,154 114
Information for pension plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation $ 494 $ 218 $ 1,242 $ 224
Fair value of plan assets 403 112 1,154 129
The following table summarizes the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of the periods indicated:
December 31, 2020 2019
U.S. Foreign U.S. Foreign
Benefit Obligation: Discount rate 2.45 % 7.53 % 3.32 % 7.58 %
Rate of compensation increase 2.75 % 5.69 % 3.33 % 6.11 %
Periodic Benefit Cost: Discount rate 3.32 % 7.58 % (1)
4.35 % 5.62 % (1)
Expected long-term rate of return on plan assets 5.24 % 7.18 % 5.08 % 4.10 %
Rate of compensation increase 2.86 % 6.13 % 3.34 % 4.78 %
_____________________________
(1)Includes an inflation factor that is used to calculate future periodic benefit cost, but is not used to calculate the benefit obligation.
The Company establishes its estimated long-term return on plan assets considering various factors, which include the targeted asset allocation percentages, historic returns, and expected future returns.
The measurement of pension obligations, costs, and liabilities is dependent on a variety of assumptions. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions.
The assumptions used in developing the required estimates include the following key factors: discount rates, salary growth, retirement rates, inflation, expected return on plan assets, and mortality rates. The effects of actual results differing from the Company's assumptions are accumulated and amortized over future periods and, therefore, generally affect the Company's recognized expense in such future periods. Unrecognized gains or losses are amortized using the “corridor approach,” under which the net gain or loss in excess of 10% of the greater of the projected benefit obligation or the market-related value of the assets, if applicable, is amortized.
Sensitivity of the Company's pension funded status to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric and are specific to the base conditions at year-end 2020. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The funded status as of December 31, 2020 is affected by the assumptions as of that date. Pension expense for 2020 is affected by the December 31, 2019 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the following table (in millions):
Increase of 1% in the discount rate $ (9)
Decrease of 1% in the discount rate 6
Increase of 1% in the long-term rate of return on plan assets (12)
Decrease of 1% in the long-term rate of return on plan assets 12
163 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for the years indicated (in millions):
December 31, 2020 2019 2018
Components of Net Periodic Benefit Cost: U.S. Foreign U.S. Foreign U.S. Foreign
Service cost $ 12 $ 6 $ 11 $ 8 $ 15 $ 12
Interest cost 35 14 44 19 40 22
Expected return on plan assets (58) (7) (52) (14) (64) (17)
Amortization of prior service cost 5 - 5 - 5 -
Amortization of net loss 14 2 15 1 18 3
Curtailment loss recognized - - - - 1 -
Settlement loss recognized - - - - - 4
Total pension cost $ 8 $ 15 $ 23 $ 14 $ 15 $ 24
The following table summarizes the amounts reflected in AOCL, including AOCL attributable to noncontrolling interests, on the Consolidated Balance Sheet as of December 31, 2020, that have not yet been recognized as components of net periodic benefit cost (in millions):
December 31, 2020 Accumulated Other Comprehensive Income (Loss)
U.S. Foreign
Prior service cost $ (3) $ 1
Unrecognized net actuarial loss (34) (69)
Total $ (37) $ (68)
The following table summarizes the Company's target allocation for 2020 and pension plan asset allocation, both domestic and foreign, as of the periods indicated:
Percentage of Plan Assets as of December 31,
Target Allocations 2020 2019
Asset Category U.S. Foreign U.S. Foreign U.S. Foreign
Equity securities 41% 13% 43.79 % 14.85 % 32.22 % 15.37 %
Debt securities 57% 82% 55.87 % 82.30 % 67.17 % 81.67 %
Real estate 2% 2% - % 1.12 % 0.22 % 1.16 %
Other -% 3% 0.34 % 1.73 % 0.39 % 1.80 %
Total pension assets 100.00 % 100.00 % 100.00 % 100.00 %
The U.S. DB Plans seek to achieve the following long-term investment objectives:
•maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;
•long-term rate of return in excess of the annualized inflation rate;
•long-term rate of return, net of relevant fees, that meets or exceeds the assumed actuarial rate; and
•long-term competitive rate of return on investments, net of expenses, that equals or exceeds various benchmark rates.
The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage risk through portfolio diversification and takes into account the above-stated objectives, in conjunction with current funding levels, cash flow conditions, and economic and industry trends. The following table summarizes the Company's U.S. DB Plan assets by category of investment and level within the fair value hierarchy as of the periods indicated (in millions):
December 31, 2020 December 31, 2019
U.S. Plans Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Equity securities: (2)
Mutual funds $ - $ 547 $ - $ 547 $ - $ 372 $ - $ 372
Debt securities: (2)
Mutual funds (1)
- 698 - 698 - 775 - 775
Real estate: (2)
Real estate - - - - - 3 - 3
Other: Cash and cash equivalents 4 - - 4 4 - - 4
Total plan assets $ 4 $ 1,245 $ - $ 1,249 $ 4 $ 1,150 $ - $ 1,154
_____________________________
(1)Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
(2)In 2019, the U.S. plans moved all investments except cash and cash equivalents into collective trusts; therefore, the balances under the equity securities, debt securities, and real estate categories shown above represent investments through collective trusts. The plans have chosen collective trusts for which the underlying investments are mutual funds, mutual funds for which debt securities are the primary underlying investment, or real estate in alignment with the target asset allocation.
164 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The investment strategy of the foreign DB Plans seeks to maximize return on investment while minimizing risk. The assumed asset allocation has less exposure to equities in order to closely match market conditions and near term forecasts. The following table summarizes the Company's foreign DB plan assets by category of investment and level within the fair value hierarchy as of the periods indicated (in millions):
December 31, 2020 December 31, 2019
Foreign Plans Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Equity securities: Mutual funds $ 16 $ - $ - $ 16 $ 19 $ - $ - $ 19
Private equity - - 1 1 - - 1 1
Debt securities: Government debt securities - - - - - - - -
Mutual funds (1)
18 74 - 92 17 88 - 105
Real estate: Real estate - - 1 1 - - 2 2
Other: Cash and cash equivalents - - - - - - - -
Other assets 1 - 1 2 1 - 1 2
Total plan assets $ 35 $ 74 $ 3 $ 112 $ 37 $ 88 $ 4 $ 129
_____________________________
(1)Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
The following table summarizes the estimated cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign (in millions):
U.S. Foreign
Expected employer contribution in 2021 $ 8 $ 15
Expected benefit payments for fiscal year ending:
2021 70 15
2022 71 13
2023 71 14
2024 71 16
2025 72 17
2026 - 2030 354 105
16. REDEEMABLE STOCK OF SUBSIDIARIES
The following table is a reconciliation of changes in redeemable stock of subsidiaries (in millions):
December 31, 2020 2019
Balance at the beginning of the period $ 888 $ 879
Contributions from holders of redeemable stock of subsidiaries - 10
Net income (loss) attributable to redeemable stock of subsidiaries 8 (7)
Fair value adjustment
4 6
Other comprehensive loss attributable to redeemable stock of subsidiaries (28) -
Balance at the end of the period $ 872 $ 888
The following table summarizes the Company's redeemable stock of subsidiaries balances as of the periods indicated (in millions):
December 31, 2020 2019
IPALCO common stock $ 618 $ 618
Colon quotas (1)
194 210
IPL preferred stock 60 60
Total redeemable stock of subsidiaries $ 872 $ 888
_____________________________
(1)Characteristics of quotas are similar to common stock.
Colon - Our partner in Colon made capital contributions of $10 million during the year ended December 31, 2019. No contributions were made in 2020. Any subsequent adjustments to allocate earnings and dividends to our partner, or measure the investment at fair value, will be classified as temporary equity each reporting period as it is probable that the shares will become redeemable.
IPL - IPL had $60 million of cumulative preferred stock outstanding at December 31, 2020 and 2019, which represents five series of preferred stock. The total annual dividend requirements were approximately $3 million at December 31, 2020 and 2019. Certain series of the preferred stock were redeemable solely at the option of the issuer at prices between $100 and $118 per share. Holders of the preferred stock are entitled to elect a majority of IPL's board of directors if IPL has not paid dividends to its preferred stockholders for four consecutive quarters. Based on the preferred stockholders' ability to elect a majority of IPL's board of directors in this circumstance, the
165 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock is considered temporary equity.
17. EQUITY
Equity Transactions with Noncontrolling Interests
Southland Energy - In November 2020, the Company completed the sale of 35% of its ownership interest in the Southland Energy assets for $424 million, which decreased the Company's economic interest to 65%. However, under the terms of the purchase and sale agreement, the Company is entitled to all earnings or losses until March 1, 2021, and any distributions related thereto. This transaction resulted in a $275 million increase in Parent Company Stockholder's Equity due to an increase in additional paid-in-capital of $266 million, net of tax and transaction costs, and the reclassification of accumulated other comprehensive losses from AOCL to NCI of $9 million. As the Company maintained control after the sale, Southland Energy continues to be consolidated by the Company within the US and Utilities SBU reportable segment.
Cochrane - In September 2020, AES Gener completed the sale of a portion of its stake in Cochrane. The transaction included the issuance of preferred shares and the sale of 5% of its stake in the subsidiary for $113 million, which decreased the Company’s economic interest in Cochrane to 38%. The preferred shareholders have the preferential right to receive an annual amount equal to $12 million, from any dividends or distributions of capital, until reaching the original investment of $113 million plus a specified rate of return. In November 2020, Cochrane distributed $12 million to the preferred shareholders. As the Company maintained control after the sale, Cochrane continues to be consolidated by the Company within the South America SBU reportable segment.
AES Brasil - In August 2020, AES Holdings Brasil Ltda. ("AHB") completed the acquisition of an additional 18.5% ownership in AES Brasil for $240 million. During the fourth quarter of 2020, through multiple transactions, AHB acquired another 1.3% ownership in AES Brasil for $16 million. In aggregate, these transactions increased the Company’s economic interest in AES Brasil to 44.1% and resulted in a $214 million decrease in Parent Company Stockholders’ Equity due to a decrease in additional paid-in-capital of $94 million and the reclassification of accumulated other comprehensive losses from NCI to AOCL of $120 million. AES Brasil is reported in the South America SBU reportable segment.
Distributed Energy - In 2020, 2019 and 2018, Distributed Energy, through multiple transactions, sold noncontrolling interests in multiple project companies to tax equity partners. These transactions resulted in a $144 million, $133 million, and $98 million increase to noncontrolling interest in 2020, 2019, and 2018 respectively. Distributed Energy is reported in the US and Utilities SBU reportable segment.
The following table summarizes the net income attributable to The AES Corporation and all transfers (to) from noncontrolling interests for the periods indicated (in millions):
December 31,
2020 2019 2018
Net income attributable to The AES Corporation $ 46 $ 303 $ 1,203
Transfers from noncontrolling interest:
Increase (decrease) in The AES Corporation's paid-in capital for sale of subsidiary shares 260 (5) (3)
Increase (decrease) in The AES Corporation's paid-in-capital for purchase of subsidiary shares (89) - -
Net transfers (to) from noncontrolling interest 171 (5) (3)
Change from net income attributable to The AES Corporation and transfers (to) from noncontrolling interests $ 217 $ 298 $ 1,200
166 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Accumulated Other Comprehensive Loss - The changes in AOCL by component, net of tax and noncontrolling interests, for the periods indicated were as follows (in millions):
Foreign currency translation adjustment, net Derivative gains (losses), net Unfunded pension obligations, net Total
Balance at December 31, 2018 $ (1,721) $ (300) $ (50) $ (2,071)
Other comprehensive loss before reclassifications (23) (202) (15) (240)
Amount reclassified to earnings 23 36 27 86
Other comprehensive income (loss) - (166) 12 (154)
Cumulative effect of a change in accounting principle - (4) - (4)
Balance at December 31, 2019 $ (1,721) $ (470) $ (38) $ (2,229)
Other comprehensive loss before reclassifications - (309) (12) (321)
Amount reclassified to earnings 192 72 - 264
Other comprehensive income (loss) 192 (237) (12) (57)
Reclassification from NCI due to share sales and repurchases (115) 8 (4) (111)
Balance at December 31, 2020 $ (1,644) $ (699) $ (54) $ (2,397)
Reclassifications out of AOCL are presented in the following table. Amounts for the periods indicated are in millions and those in parenthesis indicate debits to the Consolidated Statements of Operations:
Details About December 31,
AOCL Components Affected Line Item in the Consolidated Statements of Operations 2020 2019 2018
Foreign currency translation adjustments, net
Gain (loss) on disposal and sale of business interests $ (192) $ (23) $ 19
Net gain from disposal of discontinued operations - - 2
Net income (loss) attributable to The AES Corporation $ (192) $ (23) $ 21
Derivative gains (losses), net
Non-regulated revenue $ (1) $ (1) $ (6)
Non-regulated cost of sales (3) (12) (3)
Interest expense (60) (26) (49)
Gain (loss) on disposal and sale of business interests - 1 -
Asset impairment expense (10) - -
Foreign currency transaction gains (losses) (7) (12) (59)
Income (loss) from continuing operations before taxes and equity in earnings of affiliates (81) (50) (117)
Income tax benefit (expense) 17 13 24
Net equity in earnings (losses) of affiliates (10) (5) -
Income (loss) from continuing operations (74) (42) (93)
Less: Net loss (income) attributable to noncontrolling interests and redeemable stock of subsidiaries 2 6 15
Net income (loss) attributable to The AES Corporation $ (72) $ (36) $ (78)
Amortization of defined benefit pension actuarial losses, net
Regulated cost of sales $ (1) $ - $ -
Non-regulated cost of sales 1 - -
Other expense - (2) (6)
Gain (loss) on disposal and sale of business interests - (26) -
Income (loss) from continuing operations before taxes and equity in earnings of affiliates - (28) (6)
Income tax benefit (expense) - - 2
Income (loss) from continuing operations - (28) (4)
Net gain (loss) from disposal of discontinued operations - - (2)
Net income (loss) - (28) (6)
Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries - 1 (1)
Net income (loss) attributable to The AES Corporation $ - $ (27) $ (7)
Total reclassifications for the period, net of income tax and noncontrolling interests $ (264) $ (86) $ (64)
Common Stock Dividends - The Parent Company paid dividends of $0.1433 per outstanding share to its common stockholders during the first, second, third and fourth quarters of 2020 for dividends declared in December 2019, February 2020, July 2020, and October 2020, respectively.
On December 4, 2020, the Board of Directors declared a quarterly common stock dividend of $0.1505 per share payable on February 12, 2021 to shareholders of record at the close of business on January 29, 2021.
Stock Repurchase Program - No shares were repurchased in 2020. 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
167 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
commissions). As of December 31, 2020, $264 million remained available for repurchase under the Stock Repurchase Program.
The common stock repurchased has been classified as treasury stock and accounted for using the cost method. A total of 153,028,526 and 153,891,260 shares were held as treasury stock at December 31, 2020 and December 31, 2019, respectively. Restricted stock units under the Company's employee benefit plans are issued from treasury stock. The Company has not retired any common stock repurchased since it began the Stock Repurchase Program in July 2010.
18. SEGMENTS AND GEOGRAPHIC INFORMATION
The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the businesses internally and is mainly organized by geographic regions which provides a socio-political-economic understanding of our business. The management reporting structure is organized by four SBUs led by our President and Chief Executive Officer: US and Utilities, South America, MCAC, and Eurasia SBUs. Using the accounting guidance on segment reporting, the Company determined that its four operating segments are aligned with its four reportable segments corresponding to its SBUs.
Corporate and Other - Included in "Corporate and Other" are the results of the AES self-insurance company and certain equity affiliates, corporate overhead costs which are not directly associated with the operations of our four reportable segments, and certain intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.
The Company uses Adjusted PTC as its primary segment performance measure. Adjusted PTC, a non-GAAP measure, is defined by the Company as pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; (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. The Company has concluded Adjusted PTC better reflects the underlying business performance of the Company and is the most relevant measure considered in the Company's internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the Company's results.
Revenue and Adjusted PTC are presented before inter-segment eliminations, which includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees, and the write-off of intercompany balances, as applicable. All intra-segment activity has been eliminated within the segment. Inter-segment activity has been eliminated within the total consolidated results.
The following tables present financial information by segment for the periods indicated (in millions):
Total Revenue
Year Ended December 31, 2020 2019 2018
US and Utilities SBU $ 3,918 $ 4,058 $ 4,230
South America SBU 3,159 3,208 3,533
MCAC SBU 1,766 1,882 1,728
Eurasia SBU 828 1,047 1,255
Corporate and Other 231 46 41
Eliminations (242) (52) (51)
Total Revenue $ 9,660 $ 10,189 $ 10,736
168 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Reconciliation from Income from Continuing Operations before Taxes and Equity in Earnings of Affiliates: Total Adjusted PTC
Year Ended December 31,
2020 2019 2018
Income from continuing operations before taxes and equity in earnings of affiliates $ 488 $ 1,001 $ 2,018
Add: Net equity in earnings (losses) of affiliates (123) (172) 39
Less: Income from continuing operations before taxes, attributable to noncontrolling interests (192) (277) (509)
Pre-tax contribution 173 552 1,548
Unrealized derivative and equity securities losses (gains) 3 113 33
Unrealized foreign currency losses (gains) (10) 36 51
Disposition/acquisition losses (gains) 112 12 (934)
Impairment losses 928 406 307
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
Total Adjusted PTC
Year Ended December 31, 2020 2019 2018
US and Utilities SBU $ 505 $ 569 $ 511
South America SBU 534 504 519
MCAC SBU 287 367 300
Eurasia SBU 177 159 222
Corporate and Other (256) (347) (346)
Eliminations - (12) (21)
Total Adjusted PTC $ 1,247 $ 1,240 $ 1,185
Total Assets Depreciation and Amortization Capital Expenditures
Year Ended December 31, 2020 2019 2018 2020 2019 2018 2020 2019 2018
US and Utilities SBU $ 14,464 $ 13,334 $ 12,286 $ 534 $ 465 $ 449 $ 1,099 $ 1,484 $ 1,373
South America SBU 11,329 11,314 10,941 294 315 300 650 692 662
MCAC SBU 4,847 4,770 4,462 164 183 141 183 344 302
Eurasia SBU 3,621 3,990 4,538 63 67 99 9 30 51
Corporate and Other 342 240 294 13 15 14 19 1 8
Total $ 34,603 $ 33,648 $ 32,521 $ 1,068 $ 1,045 $ 1,003 $ 1,960 $ 2,551 $ 2,396
Interest Income Interest Expense
Year Ended December 31, 2020 2019 2018 2020 2019 2018
US and Utilities SBU $ 17 $ 18 $ 10 $ 371 $ 301 $ 287
South America SBU 64 95 92 237 285 283
MCAC SBU 14 22 20 157 142 124
Eurasia SBU 171 180 186 113 127 145
Corporate and Other 2 3 2 160 195 217
Total $ 268 $ 318 $ 310 $ 1,038 $ 1,050 $ 1,056
Investments in and Advances to Affiliates Net Equity in Earnings (Losses) of Affiliates
Year Ended December 31, 2020 2019 2018 2020 2019 2018
US and Utilities SBU $ 568 $ 465 $ 538 $ (8) $ 11 $ 35
South America SBU 13 77 213 (80) (129) 15
MCAC SBU 168 107 5 (11) (13) (7)
Eurasia SBU 1 215 293 4 (9) 14
Corporate and Other 85 102 65 (28) (32) (18)
Total $ 835 $ 966 $ 1,114 $ (123) $ (172) $ 39
169 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The following table presents information, by country, about the Company's consolidated operations for each of the three years ended December 31, 2020, 2019, and 2018, and as of December 31, 2020 and 2019 (in millions). Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
Total Revenue Long-Lived Assets (1)
Year Ended December 31, 2020 2019 2018 2020 2019
United States (2)
$ 3,243 $ 3,230 $ 3,462 $ 10,360 $ 9,762
Non-U.S.:
Chile 2,092 1,839 2,087 5,831 5,982
Dominican Republic 896 877 884 843 1,006
El Salvador 666 824 768 361 351
Panama 519 601 438 1,939 1,945
Bulgaria 444 459 426 1,149 1,106
Brazil 401 525 527 1,091 1,266
Colombia 358 472 428 355 340
Mexico 349 402 399 623 649
Argentina 308 373 487 484 393
Vietnam (3)
285 343 245 - 2
Jordan (4)
96 95 95 44 -
United Kingdom (5)
- 147 390 - -
Philippines (6)
- - 93 - -
Other Non-U.S. 3 2 7 23 20
Total Non-U.S. 6,417 6,959 7,274 12,743 13,060
Total $ 9,660 $ 10,189 $ 10,736 $ 23,103 $ 22,822
_____________________________
(1) For purposes of this disclosure, long-lived assets implies hard assets that cannot be readily removed, and thus excludes intangibles. Long-lived assets disclosed above include amounts recorded in Property, plant and equipment, net and right-of-use assets for operating leases recorded in Other noncurrent assets on the Consolidated Balance Sheets.
(2) Includes Puerto Rico revenues of $298 million, $294 million, and $257 million for the years ended December 31, 2020, 2019, and 2018, respectively, and long-lived assets of $533 million and $538 million as of December 31, 2020 and 2019, respectively.
(3) The Mong Duong 2 power project is operated under a BOT contract. Future expected payments for the construction performance obligation are recognized in Loan receivable on the Consolidated Balance Sheets as of December 31, 2019. Mong Duong assets were classified as held-for-sale as of December 31, 2020. See Notes 20-Revenue and 25-Held-For-Sale and Dispositions for further information.
(4) The long-lived assets in Jordan were classified as held-for-sale as of December 31, 2019. As of June 30, 2020, Jordan solar assets were reclassified back to held-and-used. See Note 25-Held-For-Sale and Dispositions for further information.
(5) The Kilroot and Ballylumford long-lived assets were deconsolidated upon completion of the sale in June 2019. See Note 25-Held-For-Sale and Dispositions for further information.
(6) The Masinloc long-lived assets were deconsolidated upon completion of the sale in March 2018. See Note 25-Held-For-Sale and Dispositions for further information.
19. SHARE-BASED COMPENSATION
RESTRICTED STOCK
Restricted Stock Units - The Company issues RSUs under its long-term compensation plan. The RSUs are generally granted based upon a percentage of the participant's base salary. The units have a three-year vesting schedule and vest in one-third increments over the three-year period. In all circumstances, RSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the RSU in cash or other assets of AES.
For the years ended December 31, 2020, 2019, and 2018, RSUs issued had a grant date fair value equal to the closing price of the Company's stock on the grant date. The Company does not discount the grant date fair values to reflect any post-vesting restrictions. RSUs granted to employees during the years ended December 31, 2020, 2019, and 2018 had grant date fair values per RSU of $20.75, $17.53, and $10.55, respectively.
The following table summarizes the components of the Company's stock-based compensation related to its employee RSUs recognized in the Company's consolidated financial statements (in millions):
December 31, 2020 2019 2018
RSU expense before income tax $ 10 $ 10 $ 11
Tax benefit (2) (1) (2)
RSU expense, net of tax $ 8 $ 9 $ 9
Total value of RSUs converted (1)
$ 11 $ 12 $ 10
Total fair value of RSUs vested $ 10 $ 10 $ 16
_____________________________
(1)Amount represents fair market value on the date of conversion.
170 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Cash was not used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2020, 2019, and 2018. As of December 31, 2020, total unrecognized compensation cost related to RSUs of $12 million is expected to be recognized over a weighted average period of approximately 1.8 years. There were no modifications to RSU awards during the year ended December 31, 2020.
A summary of the activity of RSUs for the year ended December 31, 2020 follows (RSUs in thousands):
RSUs Weighted Average Grant Date Fair Values Weighted Average Remaining Vesting Term
Nonvested at December 31, 2019 1,484 $ 13.73
Vested (806) 12.95
Forfeited and expired (47) 15.71
Granted 579 20.75
Nonvested at December 31, 2020 1,210 $ 17.53 1.4
Vested and expected to vest at December 31, 2020 1,104 $ 17.35
The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2020, AES has estimated a weighted average forfeiture rate of 7.23% for RSUs granted in 2020. This estimate will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company expects to expense $11 million on a straight-line basis over a three-year period.
The following table summarizes the RSUs that vested and were converted during the periods indicated (RSUs in thousands):
Year Ended December 31, 2020 2019 2018
RSUs vested during the year 806 996 1,428
RSUs converted during the year, net of shares withheld for taxes 547 666 950
Shares withheld for taxes 259 329 478
OTHER SHARE BASED COMPENSATION
The Company has three other share-based award programs. The Company has recorded expenses of $21 million, $22 million, and $20 million for 2020, 2019, and 2018, respectively, related to these programs.
Stock options - AES grants options to purchase shares of common stock under stock option plans to non-employee directors. Under the terms of the plans, the Company may issue options to purchase shares of the Company's common stock at a price equal to 100% of the market price at the date the option is granted. Stock options issued in 2018, 2019, and 2020 have a three-year vesting schedule and vest in one-third increments over the three-year period. The stock options have a contractual term of 10 years. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.
Performance Stock Units - In 2018, 2019, and 2020, the Company issued PSUs to officers under its long-term compensation plan. PSUs are stock units which include performance conditions. Performance conditions are based on the Company's Proportional Free Cash Flow targets for 2018 and 2019. For 2020, performance conditions are based on the Company’s Parent Free Cash Flow target. The performance conditions determine the vesting and final share equivalent per PSU and can result in earning an award payout range of 0% to 200%, depending on the achievement. The Company believes it is probable that the performance condition will be met and will continue to be evaluated throughout the performance period. In all circumstances, PSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the stock units in cash or other assets of AES.
Performance Cash Units - In 2018, 2019, and 2020, the Company issued PCUs to its officers under its long-term compensation plan. The value of the 2018 and 2019 units is dependent on the market condition of total stockholder return on AES common stock as compared to the total stockholder return of the Standard and Poor's 500 Utilities Sector Index, Standard and Poor's 500 Index, and MSCI Emerging Market Index over a three-year measurement period. The value for the 2020 units is dependent on the market condition of total stockholder return on AES common stock as compared to the total stockholder return of the Standard and Poor's 500 Utilities Sector Index, Standard and Poor's 500 Index, and MSCI Emerging Markets Latin America Index over a three-year measurement period. Since PCUs are settled in cash, they qualify for liability accounting and periodic measurement is required.
171 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
20. REVENUE
The following table presents our revenue from contracts with customers and other revenue for the periods indicated (in millions):
Year Ended December 31, 2020
US and Utilities SBU South America SBU MCAC SBU Eurasia SBU Corporate, Other and Eliminations Total
Regulated Revenue
Revenue from contracts with customers $ 2,626 $ - $ - $ - $ - $ 2,626
Other regulated revenue 35 - - - - 35
Total regulated revenue 2,661 - - - - 2,661
Non-Regulated Revenue
Revenue from contracts with customers 1,015 3,151 1,668 594 (10) 6,418
Other non-regulated revenue (1)
242 8 98 234 (1) 581
Total non-regulated revenue 1,257 3,159 $ 1,766 828 (11) 6,999
Total revenue $ 3,918 $ 3,159 $ 1,766 $ 828 $ (11) $ 9,660
Year Ended December 31, 2019
US and Utilities SBU South America SBU MCAC SBU Eurasia SBU Corporate, Other and Eliminations Total
Regulated Revenue
Revenue from contracts with customers $ 2,979 $ - $ - $ - $ - $ 2,979
Other regulated revenue 49 - - - - 49
Total regulated revenue 3,028 - $ - - $ - 3,028
Non-Regulated Revenue
Revenue from contracts with customers 767 3,205 1,788 $ 799 (4) $ 6,555
Other non-regulated revenue (1)
263 3 94 248 (2) 606
Total non-regulated revenue 1,030 $ 3,208 1,882 $ 1,047 (6) $ 7,161
Total revenue $ 4,058 $ 3,208 $ 1,882 $ 1,047 $ (6) $ 10,189
Year Ended December 31, 2018
US and Utilities SBU South America SBU MCAC SBU Eurasia SBU Corporate, Other and Eliminations Total
Regulated Revenue
Revenue from contracts with customers $ 2,885 $ - $ - $ - $ - $ 2,885
Other regulated revenue 54 - - - - 54
Total regulated revenue 2,939 - $ - - $ - 2,939
Non-Regulated Revenue
Revenue from contracts with customers 972 3,529 1,642 $ 943 (11) $ 7,075
Other non-regulated revenue (1)
319 4 86 312 1 722
Total non-regulated revenue 1,291 $ 3,533 1,728 $ 1,255 (10) $ 7,797
Total revenue $ 4,230 $ 3,533 $ 1,728 $ 1,255 $ (10) $ 10,736
_____________________________
(1)Other non-regulated revenue primarily includes lease and derivative revenue not accounted for under ASC 606.
Contract Balances - The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. The contract liabilities from contracts with customers were $531 million and $117 million as of December 31, 2020 and December 31, 2019, respectively.
During the years ended December 31, 2020 and 2019, we recognized revenue of $14 million and $13 million, respectively, that was included in the corresponding contract liability balance at the beginning of the periods.
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, further accelerating AES Gener's decarbonization strategy. As a result of the termination payment, Angamos recognized a contract liability of $655 million, of which $55 million will be derecognized each month through the end of the remaining performance obligation in August 2021. As of December 31, 2020, the remaining contract liability is $383 million.
A significant financing arrangement exists for our Mong Duong plant in Vietnam. The plant was constructed under a BOT contract and will be transferred to the Vietnamese government after the completion of a 25 year PPA. The performance obligation to construct the facility was substantially completed in 2015. Approximately $1.4 billion of contract consideration related to the construction, but not yet collected through the 25 year PPA, was reflected as
172 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
a loan receivable as of December 31, 2019. 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.
Remaining Performance Obligations - The transaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the reporting period. As of December 31, 2020, the aggregate amount of transaction price allocated to remaining performance obligations was $11 million, primarily consisting of fixed consideration for the sale of renewable energy credits in long-term contracts in the U.S. We expect to recognize revenue on approximately one-fifth of the remaining performance obligations in 2021 and 2022, with the remainder recognized thereafter.
21. OTHER INCOME AND EXPENSE
Other income generally includes gains on insurance recoveries in excess of property damage, gains on asset sales and liability extinguishments, favorable judgments on contingencies, allowance for funds used during construction, and other income from miscellaneous transactions. Other expense generally includes losses on asset sales and dispositions, losses on legal contingencies, defined benefit plan non-service costs, and losses from other miscellaneous transactions. The components are summarized as follows (in millions):
Year Ended December 31, 2020 2019 2018
Other Income Gain on sale of assets (1)
$ 46 $ - $ -
Gain on insurance proceeds (2)
- 118 -
Gain on remeasurement of contingent consideration (3)
- - 32
AFUDC (US Utilities) 5 3 8
Other 24 24 32
Total other income $ 75 $ 145 $ 72
Other Expense Loss on sale of receivables (4)
$ 20 $ - $ -
Legal contingencies and settlements 15 2 2
Loss on sale and disposal of assets (5)
7 22 30
Non-service pension and other postretirement costs 2 17 10
Loss on commencement of sales-type leases (6)
- 36 -
Allowance for other receivables - - 7
Other 9 3 9
Total other expense $ 53 $ 80 $ 58
_____________________________
(1)Primarily associated with the gain on sale of Redondo Beach land at Southland. See Note 25-Held-for-Sale and Dispositions for further information.
(2)Associated with recoveries for property damage at the Andres facility in the Dominican Republic from a lightning incident in September 2018 and the upgrade of the tunnel lining at Changuinola.
(3)Related to the amendment of the Oahu purchase agreement. See Note 26-Acquisitions for further information.
(4)Associated with a loss on sale of Stabilization Fund receivables at Gener. See Note 7-Financing Receivables for further information.
(5)Associated with a loss due to the upgrade of the tunnel lining at Changuinola in 2019 and a loss due to damage from a lightning incident at the Andres facility in the Dominican Republic in September 2018.
(6)Related to losses recognized at commencement of sales-type leases at Distributed Energy. See Note 14-Leases for further information.
22. ASSET IMPAIRMENT EXPENSE
Year ended December 31, (in millions) 2020 2019 2018
AES Gener $ 781 $ - $ -
Hawaii 38 60 -
Estrella del Mar I 30 - -
Kilroot and Ballylumford - 115 -
Shady Point - - 157
Nejapa - - 37
Other 15 10 14
Total $ 864 $ 185 $ 208
AES Gener - 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, further accelerating AES Gener’s decarbonization strategy. 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
173 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
not recoverable. As a result, the Company recognized asset impairment expense of $781 million. AES Gener is reported in the South America SBU reportable segment.
Hawaii - During the fourth quarter of 2019, the Company tested the recoverability of its long-lived coal-fired asset in Hawaii. Uncertainty around the ability to contract the asset upon expiration of its existing PPA resulted in management's decision to reassess the economic useful life of the generation facility. A decrease in the useful life was identified as an impairment indicator and the Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant and equipment and intangible assets, was determined to have a fair value of $103 million using the income approach. As a result, the Company recognized asset impairment expense of $60 million as of December 31, 2019.
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. Therefore, management further reassessed the economic useful life of the generation facility and 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 additional asset impairment expense of $38 million during the third quarter of 2020. Hawaii is reported in the US and Utilities SBU reportable segment.
Estrella del Mar I - In August 2020, the Estrella del Mar I power barge was disconnected from the Panama grid and AES Panama is currently evaluating its options for the asset. Upon disconnection, the Company concluded that the barge was no longer part of the AES Panama asset group and performed an impairment analysis. The Company determined that the carrying amount of the asset was not recoverable and recognized asset impairment expense of $30 million. The asset met the held-for-sale criteria as of December 31, 2020. See Note 25-Held-for-Sale and Dispositions for further information. Estrella del Mar I is reported in the MCAC SBU reportable segment.
Kilroot and Ballylumford - In April 2019, the Company entered into an agreement to sell its entire 100% interest in the Kilroot coal and oil-fired plant and energy storage facility and the Ballylumford gas-fired plant in the United Kingdom. Upon meeting the held-for-sale criteria, the Company performed an impairment analysis and determined that the carrying value of the asset group of $232 million was greater than its fair value less costs to sell of $114 million. As a result, the Company recognized asset impairment expense of $115 million. The Company completed the sale of Kilroot and Ballylumford in June 2019. See Note 25-Held-for-Sale and Dispositions for further information. Prior to their sale, Kilroot and Ballylumford were reported in the Eurasia SBU reportable segment.
Shady Point - In December 2018, the Company entered into an agreement to sell Shady Point, a coal-fired generation facility in the U.S. Due first to the uncertainty around future cash flows, and then upon meeting the held-for-sale criteria, the Company performed an impairment analysis of the Shady Point asset group in the second, third and fourth quarters of 2018, resulting in the recognition of total asset impairment expense of $157 million for the year ended December 31, 2018. Using the market approach, the asset group was determined to have a fair value of $30 million as of December 31, 2018. The sale was completed in May 2019. See Note 25-Held-for-Sale and Dispositions for further information. Prior to the sale, Shady Point was reported in the US and Utilities SBU reportable segment.
Nejapa - During the fourth quarter of 2018, the Company tested the recoverability of its long-lived assets at Nejapa, a landfill gas plant in El Salvador. Decreased production as a result of the landfill owner's failure to perform improvements necessary to continue extracting gas from the landfill was identified as an impairment indicator. The Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant, and equipment and intangible assets, was determined to have a fair value of $5 million using the income approach. As a result, the Company recognized asset impairment expense of $37 million as of December 31, 2018. Nejapa is reported in the US and Utilities SBU reportable segment.
174 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
23. INCOME TAXES
Income Tax Provision - The following table summarizes the expense for income taxes on continuing operations for the periods indicated (in millions):
December 31, 2020 2019 2018
Federal: Current $ (8) $ (7) $ 7
Deferred (17) (4) 186
State: Current - (1) 2
Deferred 2 - 5
Foreign: Current 458 368 378
Deferred (219) (4) 130
Total $ 216 $ 352 $ 708
Effective and Statutory Rate Reconciliation - The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to the Company's effective tax rate as a percentage of income from continuing operations before taxes for the periods indicated:
December 31, 2020 2019 2018
Statutory Federal tax rate 21 % 21 % 21 %
State taxes, net of Federal tax benefit (6) % 6 % 2 %
Taxes on foreign earnings 15 % 12 % 9 %
Valuation allowance 16 % (2) % (2) %
Change in tax law 3 % (1) % 6 %
US Investment Tax Credit (8) % - % - %
Other-net 3 % (1) % (1) %
Effective tax rate 44 % 35 % 35 %
For 2020, the 15% taxes on foreign earnings item includes $20 million of tax benefit associated with the Company's equity investment in Guacolda. Included in the 2020 (8)% U.S. investment tax credit is $35 million of benefit associated with the Na Pua Makani wind facility. Not included in the 2020 effective tax rate is $75 million of income tax expense recorded to additional paid-in-capital related to the Company's sale of 35% of its ownership interest in the Southland Energy assets. See Note 17-Equity for details of the sale.
For 2019, the 12% taxes on foreign earnings item includes $19 million of tax benefit associated with the Company's equity investment in Guacolda. Included in the 2019 change in tax law amount of (1)% are the downward adjustments to the U.S. one-time transition tax expense and deferred tax remeasurement benefit resulting from the issuance of the final regulations in 2019, offset by the impact of deferred tax remeasurement expense related to the December 2019 Argentina tax law change.
For 2018, the 6% change in tax law item relates primarily to changes in estimate under SAB 118 of the impacts of adoption of the TCJA. The Company recognized tax expense of $194 million related to revised estimates of the one-time transition tax in accordance with proposed regulations issued by the U.S. Treasury in 2018. The adjustment was due in large part to the approach the proposed regulations adopted to determine the fair value of our interests in publicly traded subsidiaries. The Company also recognized tax benefit of $77 million related to revised estimates of deferred tax remeasurement. Included in the 9% taxes on foreign earnings item is $124 million of U.S. GILTI tax expense related to foreign subsidiaries, including the sale of our interest in Masinloc.
Income Tax Receivables and Payables - The current income taxes receivable and payable are included in Other Current Assets and Accrued and Other Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent income taxes receivable and payable are included in Other Noncurrent Assets and Other Noncurrent Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The following table summarizes the income taxes receivable and payable as of the periods indicated (in millions):
December 31, 2020 2019
Income taxes receivable-current $ 138 $ 131
Income taxes receivable-noncurrent 9 10
Total income taxes receivable $ 147 $ 141
Income taxes payable-current $ 284 $ 172
Income taxes payable-noncurrent - -
Total income taxes payable $ 284 $ 172
Deferred Income Taxes - Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
175 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
income tax purposes and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.
As of December 31, 2020, the Company had federal net operating loss carryforwards for tax return purposes of approximately $2.1 billion, of which approximately $950 million expire in years 2033 to 2036 and $1.2 billion carry forward indefinitely. The Company also had federal general business tax credit carryforwards of approximately $66 million, of which $16 million expire in years 2021 to 2031 and $50 million expire in years 2032 to 2040. Additionally, the Company had state net operating loss carryforwards as of December 31, 2020 of approximately $7.3 billion expiring primarily in years 2021 to 2040. As of December 31, 2020, the Company had foreign net operating loss carryforwards of approximately $2.0 billion that expire at various times beginning in 2021 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $14 million, $13 million of which expire in 2021.
Valuation allowances decreased $190 million during 2020 to $634 million at December 31, 2020. This net decrease was primarily the result of valuation allowance activity due to the liquidation of certain holding companies with net operating losses with full valuation allowances.
Valuation allowances decreased $44 million during 2019 to $824 million at December 31, 2019. This net decrease was primarily the result of valuation allowance activity at certain of our Brazil subsidiaries and U.S. states.
The Company believes that it is more likely than not that the net deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income.
The following table summarizes deferred tax assets and liabilities, as of the periods indicated (in millions):
December 31, 2020 2019
Differences between book and tax basis of property $ (1,308) $ (1,426)
Investment in U.S. tax partnerships (332) (44)
Other taxable temporary differences (403) (287)
Total deferred tax liability (2,043) (1,757)
Operating loss carryforwards 1,156 1,060
Capital loss carryforwards 73 57
Bad debt and other book provisions 87 74
Tax credit carryforwards 78 33
Other deductible temporary differences 471 300
Total gross deferred tax asset 1,865 1,524
Less: Valuation allowance (634) (824)
Total net deferred tax asset 1,231 700
Net deferred tax liability $ (812) $ (1,057)
The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the U.S. Except for the one-time transition tax in the U.S., no taxes have been recorded with respect to our indefinitely reinvested earnings in accordance with the relevant accounting guidance for income taxes. Should the earnings be remitted as dividends, the Company may be subject to additional foreign withholding and state income taxes. Under the TCJA, future distributions from foreign subsidiaries will generally be subject to a federal dividends received deduction in the U.S. As of December 31, 2020, the cumulative amount of U.S. GAAP foreign un-remitted earnings upon which additional income taxes have not been provided is approximately $4 billion. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.
Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The Company's income tax benefits related to the tax status of these operations are estimated to be $33 million, $26 million and $35 million for the years ended December 31, 2020, 2019 and 2018, respectively. The per share effect of these benefits after noncontrolling interests was $0.03, $0.02 and $0.04 for the years ended December 31, 2020, 2019 and 2018, respectively. Included in the Company's income tax benefits is the benefit related to our operations in Vietnam, which is estimated to be $16 million, $13 million and $19 million for the years ended December 31, 2020, 2019 and 2018, respectively. The per share effect of these benefits related to our operations in Vietnam after noncontrolling interest was $0.01, $0.01 and $0.01 for the years ended December 31, 2020, 2019 and 2018, respectively.
176 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The following table shows the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and noncontrolling interests, for the periods indicated (in millions):
December 31, 2020 2019 2018
U.S. $ (135) $ (57) $ (218)
Non-U.S. 623 1,058 2,236
Total $ 488 $ 1,001 $ 2,018
Uncertain Tax Positions - Uncertain tax positions have been classified as noncurrent income tax liabilities unless they are expected to be paid within one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations. The following table shows the total amount of gross accrued income taxes related to interest and penalties included in the Consolidated Balance Sheets for the periods indicated (in millions):
December 31, 2020 2019
Interest related $ 1 $ 2
Penalties related - -
The following table shows the expense/(benefit) related to interest and penalties on unrecognized tax benefits for the periods indicated (in millions):
December 31, 2020 2019 2018
Total benefit for interest related to unrecognized tax benefits $ - $ (2) $ (3)
Total expense for penalties related to unrecognized tax benefits - - -
We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:
Jurisdiction Tax Years Subject to Examination
Argentina 2014-2020
Brazil 2015-2020
Chile 2017-2020
Colombia 2016-2020
Dominican Republic 2015-2020
El Salvador 2017-2020
Netherlands 2014-2020
Panama 2017-2020
United Kingdom 2017-2020
United States (Federal) 2017-2020
As of December 31, 2020, 2019 and 2018, the total amount of unrecognized tax benefits was $458 million, $465 million and $463 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2020, 2019 and 2018 is $439 million, $448 million and $446 million, respectively, of which $33 million for each year would be in the form of tax attributes that would warrant a full valuation allowance. Further, the total amount of unrecognized tax benefit that would benefit the effective tax rate as of 2020 would be reduced by approximately $161 million of tax expense related to remeasurement from 35% to 21%.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2020 is estimated to be between $0 million and $10 million, primarily relating to statute of limitation lapses and tax exam settlements.
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the periods indicated (in millions):
2020 2019 2018
Balance at January 1 $ 465 $ 463 $ 348
Additions for current year tax positions - 6 2
Additions for tax positions of prior years 3 4 146
Reductions for tax positions of prior years (6) (5) (26)
Lapse of statute of limitations (4) (3) (7)
Balance at December 31 $ 458 $ 465 $ 463
177 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe we have appropriately accrued for our uncertain tax benefits. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of current or future examinations may exceed our provision for current unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2020. Our effective tax rate and net income in any given future period could therefore be materially impacted.
24. DISCONTINUED OPERATIONS
Eletropaulo - Due to a portfolio evaluation in the first half of 2016, management decided to pursue a strategic shift to reduce the Company's exposure to the Brazilian distribution market. In December 2017, all criteria were met for Eletropaulo to qualify as a discontinued operation. Therefore, its results of operations and financial position were reported as such in the consolidated financial statements for all periods presented.
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo through a bidding process hosted by the Brazilian securities regulator, CVM. Gross proceeds of $340 million were received at our subsidiary in Brazil, subject to the payment of taxes. Upon disposal of Eletropaulo, the Company recorded a pre-tax gain on sale of $243 million (after-tax $199 million). Prior to its classification as discontinued operations, Eletropaulo was reported in the South America SBU reportable segment.
Borsod - In 2011, Borsod, which held two coal and biomass-fired generation plants in Hungary, filed for liquidation and was deconsolidated with its historical operating results reflected in discontinued operations under prior accounting guidance.
In October 2018, the liquidation was completed and the Company recognized a deferred gain of $26 million, primarily comprised of a $20 million write-off of cumulative translation balances. Prior to its classification as discontinued operations, Borsod was reported in the Eurasia SBU reportable segment.
Excluding the gain on sale of Eletropaulo and the deferred gain on liquidation of Borsod, income from discontinued operations and cash flows from operating and investing activities of discontinued operations were immaterial for the year ended December 31, 2018.
25. HELD-FOR-SALE AND DISPOSITIONS
Held-for-Sale
Mong Duong - In December 2020, the Company entered into an agreement to sell its entire 51% ownership interest in Mong Duong, a coal-fired plant in Vietnam, and 51% equity interest in Mong Duong Finance Holdings B.V, an SPV accounted for as an equity affiliate. The sale is subject to regulatory approval and is expected to close in early 2022. As of December 31, 2020, the Mong Duong plant and SPV were classified as held-for-sale, but did not meet the criteria to be reported as discontinued operations. On a consolidated basis, the carrying value of the plant and SPV held-for-sale as of December 31, 2020 was $472 million. Mong Duong is reported in the Eurasia SBU reportable segment.
Estrella del Mar I - The Estrella del Mar I power barge met the held-for-sale criteria as of December 31, 2020, but did not meet criteria to be reported as discontinued operations. On a consolidated basis, the carrying value of the power barge held-for-sale as of December 31, 2020 was $16 million. Estrella del Mar I is reported in the MCAC SBU reportable segment.
Itabo - In June 2020, the Company entered into an agreement to sell its 43% ownership interest in Itabo, a coal-fired plant and gas turbine in Dominican Republic, for $101 million. In the fourth quarter of 2020, the expected sales price was reduced to $92 million, reflecting dividends distributed by Itabo. In February 2021, the sale was approved by the Superintendence of Electricity and is expected to close in the first quarter of 2021. As of December 31, 2020, Itabo was classified as held-for-sale, but did not meet the criteria to be reported as discontinued operations. On a consolidated basis, the carrying value of the Itabo facility held-for-sale as of December 31, 2020 was $189 million. Itabo is reported in the MCAC SBU reportable segment.
178 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Jordan - In February 2019, the Company entered into an agreement to sell its 36% ownership interest in two generation plants, IPP1 and IPP4, and a solar plant in Jordan. In December 2019, the original sales agreement expired, and in April 2020, one of the potential buyers withdrew from the transaction due to the uncertain economic conditions surrounding the COVID-19 pandemic. As of June 30, 2020, the solar plant no longer met the held-for-sale criteria, while the Company continued with an active process to complete the sale of its controlling interest in IPP1 and IPP4 and believed the sale remained probable. As such, the solar plant was reclassified as held and used as of June 30, 2020.
In November 2020, the Company signed an agreement to sell 26% ownership interest in IPP1 and IPP4 for $58 million. The sale is expected to close in the second quarter of 2021. After completion of the sale, the Company will retain a 10% ownership interest in IPP1 and IPP4, which will be accounted for as an equity method investment. As of December 31, 2020, the generation plants were classified as held-for-sale, but did not meet the criteria to be reported as discontinued operations. On a consolidated basis, the carrying value of the plants held-for-sale as of December 31, 2020 was $154 million. Jordan is reported in the Eurasia SBU reportable segment.
Excluding any impairment charges, pre-tax income attributable to AES of businesses held-for-sale as of December 31, 2020 was as follows (in millions):
Year Ended December 31, 2020 2019 2018
Mong Duong $ 55 $ 34 $ 48
Estrella del Mar I 5 12 17
Itabo 41 30 33
Jordan 20 18 11
Total $ 121 $ 94 $ 109
Dispositions
Uruguaiana - In September 2020, the Company completed the sale of its entire interest in AES Uruguaiana, resulting in a pre-tax loss on sale of $90 million, primarily due to the write-off of cumulative translation adjustments. As part of the sale agreement, the Company has guaranteed payment of certain contingent liabilities and provided indemnifications to the buyer which were estimated to have a fair value of $22 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Uruguaiana was reported in the South America SBU reportable segment.
Kazakhstan Hydroelectric - Affiliates of the Company (the “Affiliates”) previously operated Shulbinsk HPP and Ust-Kamenogorsk HPP (the “HPPs”), two hydroelectric plants in Kazakhstan, under a concession agreement with the Republic of Kazakhstan (“ROK”). In April 2017, the ROK initiated the process to transfer these plants back to the ROK. The ROK indicated that arbitration would be necessary to determine the correct Return Share Transfer Payment ("RST") and, rather than paying the Affiliates, deposited the RST into an escrow account. In exchange, the Affiliates transferred 100% of the shares in the HPPs to the ROK, under protest and with a full reservation of rights. In February 2018, the Affiliates initiated the arbitration process in international court to recover at least $75 million of the RST placed in escrow, based on the September 30, 2017 RST calculation.
In May 2020, the arbitrator issued a final decision in favor of the Affiliates, awarding the Affiliates a net amount of damages of approximately $45 million, which has been collected. AES recorded the remaining $30 million as a loss on sale during the quarter ended June 30, 2020. Prior to their transfer, the Kazakhstan HPPs were reported in the Eurasia SBU reportable segment.
Redondo Beach Land - In March 2020, the Company completed the sale of land held by AES Redondo Beach, a gas-fired generating facility in California. The land’s carrying value was $24 million, resulting in a pre-tax gain on sale of $41 million, reported in Other income on the Condensed Consolidated Statement of Operations. AES Redondo Beach will lease back the land from the purchaser for the remainder of the generation facility’s useful life. Redondo Beach is reported in the US and Utilities SBU reportable segment.
Stuart and Killen - In December 2019, DPL completed the transfer of the co-owned Stuart coal-fired and diesel-fired generating units and the Killen coal-fired generating unit and combustion turbine retired in May 2018, including the associated environmental liabilities. The transfer resulted in cash expenditures of $51 million and a gain on disposal of $20 million. Prior to their transfer, Stuart and Killen were reported in the US and Utilities SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
179 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
Kilroot and Ballylumford - In June 2019, the Company completed the sale of its entire interest in the Kilroot coal and oil-fired plant and energy storage facility and the Ballylumford gas-fired plant in the United Kingdom for $118 million, resulting in a pre-tax loss on sale of $33 million primarily due to the write-off of cumulative translation adjustments and accumulated other comprehensive income balances. The sale did not meet the criteria to be reported as discontinued operations. Prior to the sale, Kilroot and Ballylumford were reported in the Eurasia SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
Shady Point - In May 2019, the Company completed the sale of Shady Point, a U.S. coal-fired generating facility, for $29 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Shady Point was reported in the US and Utilities SBU reportable segment. See Note 22-Asset Impairment Expense for further information.
CTNG - In December 2018, AES Gener completed the sale of CTNG, an entity that holds transmission lines in Chile, for $225 million, resulting in a pre-tax gain on sale of $126 million after post-closing adjustments. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, CTNG was reported in the South America SBU reportable segment.
Electrica Santiago - In May 2018, AES Gener completed the sale of Electrica Santiago for total consideration of $287 million, resulting in a final pre-tax gain on sale of $70 million after post-closing adjustments. Electrica Santiago consisted of four gas and diesel-fired generation plants in Chile. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Electrica Santiago was reported in the South America SBU reportable segment.
Masinloc - In March 2018, the Company completed the sale of its entire 51% equity interest in Masinloc for cash proceeds of $1.05 billion, resulting in a pre-tax gain on sale of $772 million after post-closing adjustments, subject to U.S. income tax. Masinloc consisted of a coal-fired generation plant in operation, a coal-fired generation plant under construction and an energy storage facility all located in the Philippines. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, Masinloc was reported in the Eurasia SBU reportable segment.
DPL peaker assets - In March 2018, DPL completed the sale of six of its combustion turbine and diesel-fired generation facilities and related assets ("DPL peaker assets") for total proceeds of $239 million, resulting in a loss on sale of $2 million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the DPL peaker assets were reported in the US and Utilities SBU reportable segment.
Beckjord facility - In February 2018, DPL transferred its interest in Beckjord, a coal-fired generation facility retired in 2014, including its obligations to remediate the facility and its site. The transfer resulted in cash expenditures of $15 million, inclusive of disposal charges, and a loss on disposal of $12 million. Prior to the transfer, Beckjord was reported in the US and Utilities SBU reportable segment.
Advancion Energy Storage - In January 2018, the Company deconsolidated the AES Advancion energy storage development business and contributed it to the Fluence joint venture, resulting in a gain on sale of $23 million. See Note 8-Investments in and Advances to Affiliates for further discussion. Prior to the transfer, the AES Advancion energy storage development business was reported as part of Corporate and Other.
Excluding any impairment charge or gain/loss on sale, pre-tax income (loss) attributable to AES of disposed businesses was immaterial for the year ended December 31, 2020. The following table summarizes, excluding any impairment charge or gain/loss on sale, the pre-tax income (loss) attributable to AES of disposed businesses for the periods indicated (in millions):
Year Ended December 31, 2019 2018
Kilroot and Ballylumford $ (1) $ 35
Stuart and Killen (1)
52 77
Shady Point (5) 19
Masinloc - 9
Other (2) 14
Total $ 44 $ 154
_____________________________
(1)After the retirement of Stuart and Killen in 2018, the Company entered into contracts to buy back all open capacity years for the plants at prices lower than the PJM capacity revenue prices. As such, the Company continued to earn capacity margin until the plants were transferred in December 2019. Reductions in the asset retirement obligations for ash ponds and landfills at Stuart and Killen in 2018 resulted in a $32 million reduction to cost of sales. See Note 4-Asset Retirement Obligations for further information.
180 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
26. ACQUISITIONS
Ventus Wind Complex - In December 2020, AES Brasil completed the acquisition of the Ventus Wind Complex ("Ventus") for $91 million, including $4 million of expected working capital adjustments. At closing, the Company made an initial cash payment of $44 million. The remainder was recorded as a note payable, which will be substantially satisfied via a second installment payment expected to occur in the second quarter of 2021. The transaction was accounted for as an asset acquisition; therefore, the total amount of consideration, plus transaction costs, was allocated to the individual assets and liabilities assumed based on their relative fair values. Any differences arising from post-closing adjustments will be allocated accordingly. Ventus is reported in the South America SBU reportable segment.
Penonome I - In May 2020, AES Panama completed the acquisition of the Penonome I wind farm from Goldwind International for $80 million. The transaction was accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, was allocated to the individual assets and liabilities assumed based on their relative fair values. Any differences arising from post-closing adjustments will be allocated accordingly. Penonome I is reported in the MCAC SBU reportable segment.
Los Cururos - In November 2019, AES Gener completed the acquisition of the Los Cururos wind farm and transmission lines in Chile from EPM Chile S.A. for total consideration of $143 million, including $5 million in working capital adjustments paid in the first quarter of 2020. The transaction was accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Los Cururos is reported in the South America SBU reportable segment.
Distributed Energy - In December 2018, Distributed Energy acquired the outstanding noncontrolling interest in a partnership holding various solar projects from its tax equity partner for $23 million of consideration in a non-cash transaction through the assumption of debt, increasing the Company's ownership to 100%. The partnership was previously classified as an equity method investment. The transaction was accounted for as an asset acquisition, therefore the Company remeasured the equity investment at fair value and recognized a loss of $5 million in Other expense in the Consolidated Statement of Operations. The fair value of the investment, along with the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Distributed Energy is reported in the US and Utilities SBU reportable segment.
Oahu - In November 2018, AES Oahu amended a 2017 agreement to acquire 100% of Na Pua Makani Power Partners, a partnership designed to develop and hold a wind project in Hawaii. The fair value of the initial consideration was $53 million, of which $48 million was contingent on meeting predefined development milestones. The transaction was accounted for as an acquisition of a variable interest entity that did not meet the definition of a business, therefore the assets acquired and liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration. As a result of the amendment, the Company paid $11 million in 2018 and the contingent consideration was reduced to $5 million, resulting in a $32 million gain on remeasurement of contingent consideration recorded in Other income in the Consolidated Statement of Operations. AES Oahu is reported in the US and Utilities SBU reportable segment.
Guaimbê Solar Complex - In September 2018, AES Brasil completed the acquisition of the Guaimbê Solar Complex (“Guaimbê”) from Cobra do Brasil for $152 million, comprised of the exchange of $119 million of non-convertible debentures in project financing and additional cash consideration of $33 million. The transaction was accounted for as an asset acquisition, therefore the consideration transferred, plus transaction costs, was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. Guaimbê is reported in the South America SBU reportable segment.
27. EARNINGS PER SHARE
Basic and diluted earnings per share are based on the weighted-average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive RSUs and stock options. The effect of such potential common stock is computed using the treasury stock method.
The following table is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the years ended December 31, 2020, 2019 and 2018,
181 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
where income represents the numerator and weighted-average shares represent the denominator.
Year Ended December 31, 2020 2019 2018
(in millions, except per share data) Income Shares $ per Share Income Shares $ per Share Income Shares $ per Share
BASIC EARNINGS PER SHARE
Income (loss) from continuing operations attributable to The AES Corporation common stockholders $ 43 665 $ 0.06 $ 302 664 $ 0.46 $ 985 662 $ 1.49
EFFECT OF DILUTIVE SECURITIES
Stock options - 1 - - - - - - -
Restricted stock units - 2 - - 3 (0.01) - 3 (0.01)
DILUTED EARNINGS PER SHARE $ 43 668 $ 0.06 $ 302 667 $ 0.45 $ 985 665 $ 1.48
The calculation of diluted earnings per share excluded 2 million outstanding stock awards for the year ended December 31, 2018, which would be anti-dilutive. These stock awards could potentially dilute basic earnings per share in the future.
28. RISKS AND UNCERTAINTIES
AES is a diversified power generation and utility company organized into four market-oriented SBUs. See additional discussion of the Company's principal markets in Note 18-Segments and Geographic Information. Within our four SBUs, we have two primary lines of business: generation and utilities. The generation line of business uses a wide range of fuels and technologies to generate electricity such as coal, gas, hydro, wind, solar, and biomass. Our utilities business comprises businesses that transmit, distribute, and in certain circumstances, generate power. In addition, the Company has operations in the renewables area. These efforts include projects primarily in wind, solar, and energy storage.
Operating and Economic Risks - The Company operates in several developing economies where macroeconomic conditions are typically more volatile than developed economies. Deteriorating market conditions and evolving industry expectations to transition away from fossil fuel sources for generation expose the Company to the risk of decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets, and potential changes in the estimated useful lives of our thermal plants. Additionally, credit markets around the globe continue to tighten their standards, which could impact our ability to finance growth projects through access to capital markets. Currently, the Company has an investment grade rating from both Standard & Poor's and Fitch of BBB-, and a below-investment grade rating from Moody's of Ba1. A downgrade in our current investment grade ratings could affect the Company's ability to finance new and/or existing development projects at competitive interest rates. As of December 31, 2020, the Company had $1 billion of unrestricted cash and cash equivalents.
During 2020, 66% of our revenue was generated outside the U.S. and a significant portion of our international operations is conducted in developing countries. We continue to invest in several developing countries to expand our existing platform and operations. International operations, particularly the operation, financing, and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:
•economic, social, and political instability in any particular country or region;
•inability to economically hedge energy prices;
•volatility in commodity prices;
•adverse changes in currency exchange rates;
•government restrictions on converting currencies or repatriating funds;
•unexpected changes in foreign laws, regulatory framework, or in trade, monetary or fiscal policies;
•high inflation and monetary fluctuations;
•restrictions on imports of solar panels, wind turbines, coal, oil, gas, or other raw materials required by our generation businesses to operate;
•threatened or consummated expropriation or nationalization of our assets by foreign governments;
•unwillingness of governments, government agencies, similar organizations, or other counterparties to honor their commitments;
•unwillingness of governments, government agencies, courts, or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to
182 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
counterparties, against such counterparties, whether such counterparties are governments or private parties;
•inability to obtain access to fair and equitable political, regulatory, administrative, and legal systems;
•adverse changes in government tax policy;
•potentially adverse tax consequences of operating in multiple jurisdictions;
•difficulties in enforcing our contractual rights, enforcing judgments, or obtaining a just result in local jurisdictions; and
•inability to obtain financing on expected terms.
Any of these factors, individually or in combination with others, could materially and adversely affect our business, results of operations, and financial condition. In addition, our Latin American operations experience volatility in revenue and earnings which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability, indexation of certain PPAs to fuel prices, and currency fluctuations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.
Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain reasonable increases in tariffs or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analysts' expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our utility businesses where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:
•changes in the determination, definition, or classification of costs to be included as reimbursable or pass-through costs;
•changes in the definition or determination of controllable or noncontrollable costs;
•adverse changes in tax law;
•changes in the definition of events which may or may not qualify as changes in economic equilibrium;
•changes in the timing of tariff increases;
•other changes in the regulatory determinations under the relevant concessions; or
•changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect our results of operations.
COVID-19 Pandemic - The COVID-19 pandemic has severely impacted global economic activity, including electricity and energy consumption, and caused significant volatility in financial markets. For the year ended December 31, 2020, the COVID-19 pandemic has had an impact on demand for electricity and, as a result, on the financial results and operations of the Company. The magnitude and duration of the COVID-19 pandemic is unknown at this time and may have material and adverse effects on our results of operations, financial condition and cash flows in future periods.
Goodwill - The Company considers a reporting unit at risk of impairment when its fair value does not exceed its carrying amount by more than 10%. 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.
183 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
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.
Foreign Currency Risks - AES operates businesses in many foreign countries and such operations could be impacted by significant fluctuations in foreign currency exchange rates. Fluctuations in currency exchange rate between the USD and the following currencies could create significant fluctuations in earnings and cash flows: the Argentine peso, the Brazilian real, the Chilean peso, the Colombian peso, the Dominican Republic peso, the Euro, the Indian rupee, and the Mexican peso.
Argentina - In September 2019, currency controls were established by the Argentine government in order to control the devaluation of the Argentine peso and keep Argentine central bank reserves at acceptable levels. Restrictions on the flow of capital have limited the availability of international credit, and economic conditions in Argentina have further deteriorated, triggering additional devaluation of the Argentine peso and a deterioration of the country’s risk profile.
Concentrations - Due to the geographical diversity of its operations, the Company does not have any significant concentration of customers or sources of fuel supply. Several of the Company's generation businesses rely on PPAs with one or a limited number of customers for the majority of, and in some cases all of, the relevant businesses' output over the term of the PPAs. However, no single customer accounted for 10% or more of total revenue in 2020, 2019 or 2018.
The cash flows and results of operations of our businesses depend on the credit quality of our customers and the continued ability of our customers and suppliers to meet their obligations under PPAs and fuel supply agreements. If a substantial portion of the Company's long-term PPAs and/or fuel supply were modified or terminated, the Company would be adversely affected to the extent that it would be unable to replace such contracts at equally favorable terms.
29. RELATED PARTY TRANSACTIONS
Certain of our businesses in Panama and the Dominican Republic are partially owned by governments either directly or through state-owned institutions. In the ordinary course of business, these businesses enter into energy purchase and sale transactions, and transmission agreements with other state-owned institutions which are controlled by such governments. At two of our generation businesses in Mexico, the offtakers exercise significant influence, but not control, through representation on these businesses' Boards of Directors. These offtakers are also required to hold a nominal ownership interest in such businesses. In Chile, we provide capacity and energy under contractual arrangements to our investment which is accounted for under the equity method of accounting. Additionally, the Company provides certain support and management services to several of its affiliates under various agreements.
The Company's Consolidated Statements of Operations included the following transactions with related parties for the periods indicated (in millions):
Years Ended December 31, 2020 2019 2018
Revenue-Non-Regulated $ 1,506 $ 1,544 $ 1,533
Cost of Sales-Non-Regulated 504 531 342
Interest income 20 21 14
Interest expense 131 74 54
The following table summarizes the balances receivable from and payable to related parties included in the Company's Consolidated Balance Sheets as of the periods indicated (in millions):
December 31, 2020 2019
Receivables from related parties $ 252 $ 370
Accounts and notes payable to related parties (1)
1,765 1,976
_____________________________
(1)Includes $1 billion of debt to Mong Duong Finance Holdings B.V., an SPV accounted for as an equity affiliate as of December 31, 2020 and 2019 (see Note 11-Debt). As of December 31, 2020, the debt balance at the SPV was reclassified to held-for-sale liabilities on the Consolidated Balance Sheet. Also includes $181 million and $415 million of debt to Banco General S.A., a bank in Panama where our minority partner in Colon is part of its board of directors as of December 31, 2020 and 2019, respectively; and $379 million and $287 million of debt to Strabag, our EPC contractor and minority partner in Alto Maipo as of December 31, 2020 and 2019, respectively.
184 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
30. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data - The following tables summarize the unaudited quarterly Condensed Consolidated Statements of Operations for the Company for 2020 and 2019 (amounts in millions, except per share data). Amounts have been restated to reflect discontinued operations in all periods presented and reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods.
Quarter Ended 2020 Mar 31 Jun 30 Sep 30 Dec 31
Revenue $ 2,338 $ 2,217 $ 2,545 $ 2,560
Operating margin 507 524 756 906
Income (loss) from continuing operations, net of tax (1)
229 - (481) 401
Income from discontinued operations, net of tax - 3 - -
Net income (loss) $ 229 $ 3 $ (481) $ 401
Net income (loss) attributable to The AES Corporation $ 144 $ (83) $ (333) $ 318
Basic earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax $ 0.22 $ (0.13) $ (0.50) $ 0.48
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax - 0.01 - -
Net income (loss) attributable to The AES Corporation common stockholders $ 0.22 $ (0.12) $ (0.50) $ 0.48
Diluted earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax $ 0.22 $ (0.13) $ (0.50) $ 0.47
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax - 0.01 - -
Net income (loss) attributable to The AES Corporation common stockholders $ 0.22 $ (0.12) $ (0.50) $ 0.47
Dividends declared per common share $ 0.14 $ - $ 0.14 $ 0.29
Quarter Ended 2019 Mar 31 Jun 30 Sep 30 Dec 31
Revenue
$ 2,650 $ 2,483 $ 2,625 $ 2,431
Operating margin 586 502 701 560
Income (loss) from continuing operations, net of tax (2)
233 66 298 (120)
Income from discontinued operations, net of tax - 1 - -
Net income (loss) $ 233 $ 67 $ 298 $ (120)
Net income (loss) attributable to The AES Corporation $ 154 $ 17 $ 210 $ (78)
Basic earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax $ 0.23 $ 0.02 $ 0.32 $ (0.12)
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax - - - -
Net income (loss) attributable to The AES Corporation common stockholders
$ 0.23 $ 0.02 $ 0.32 $ (0.12)
Diluted earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax $ 0.23 $ 0.02 $ 0.32 $ (0.12)
Income from discontinued operations attributable to The AES Corporation common stockholders, net of tax - - - -
Net income (loss) attributable to The AES Corporation common stockholders
$ 0.23 $ 0.02 $ 0.32 $ (0.12)
Dividends declared per common share
$ 0.14 $ - $ 0.14 $ 0.28
_____________________________
(1)Includes pre-tax impairment expense of $849 million in the third quarter of 2020 (See Note 22-Asset Impairment Expense), other-than-temporary impairment of OPGC of $43 million and $158 million in the first and second quarters of 2020, respectively, and net equity in losses of affiliates, primarily at Guacolda, of $112 million in the third quarter of 2020 (See Note 8-Investments in and Advances to Affiliates).
(2)Includes pre-tax impairment expense of $116 million and $69 million in the second and fourth quarters of 2019, respectively (See Note 22-Asset Impairment Expense), other-than-temporary impairment of OPGC of $92 million, and net equity in losses of affiliates, primarily at Guacolda, of $175 million in the fourth quarter of 2019 (See Note 8-Investments in and Advances to Affiliates).
185 | Notes to Consolidated Financial Statements-(Continued) | December 31, 2020, 2019 and 2018
31. SUBSEQUENT EVENTS
Guacolda - In February 2021, AES Gener entered into an agreement to sell its 50% ownership interest in Guacolda, a coal-fired plant in Chile, for $34 million. The sale is subject to regulatory approval and is expected to close in the first half of 2021. As of December 31, 2020, the carrying value of the investment was zero. Pre-tax loss attributable to AES was $54 million and $88 million for the years ended December 31, 2020 and 2019, respectively. Pre-tax income attributable to AES was $11 million for the year ended December 31, 2018. Guacolda is reported in the South America SBU reportable segment.
AES Clean Energy - 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. Pro forma information has not been presented as the impact of this transaction, individually and in the aggregate, was not material to our consolidated financial results.
Gener - On December 29, 2020, AES Gener commenced a preemptive rights offering for its existing shareholders to subscribe for up to 1,980,000,000 of newly issued shares to fund its renewable growth program. The period ended on February 5, 2021 and Inversiones Cachagua SpA, an AES subsidiary, subscribed for 1,347,200,571 shares at a cost of $205 million, increasing AES' indirect beneficial interest in AES Gener from 67.0% to 67.2%.
186 | 2020 Annual Report

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

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange Act") is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.
The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2020, our disclosure controls and procedures were effective.
Management's Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
•pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•provide reasonable assurance that unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements are prevented or detected timely.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2020. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in 2013. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2020.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2020, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which appears herein.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
187 | 2020 Annual Report
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of The AES Corporation:
Opinion on Internal Control over Financial Reporting
We have audited The AES Corporation’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, The AES Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “financial statements”), and our report dated February 24, 2021, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Tysons, Virginia
February 24, 2021
188 | 2020 Annual Report

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.
189 | 2020 Annual Report
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following information is incorporated by reference from the Registrant's Proxy Statement for the Registrant's 2021 Annual Meeting of Stockholders which the Registrant expects will be filed on or around March 3, 2021 (the "2021 Proxy Statement"):
•information regarding the directors required by this item found under the heading Board of Directors - Biographies;
•information regarding AES' Code of Ethics found under the heading Corporate Governance at AES - Additional Governance Information; and
•information regarding AES' Financial Audit Committee found under the heading Board and Committee Governance - Board Committees - Financial Audit Committee (the “Audit Committee”).
Certain information regarding executive officers required by this Item is presented as a supplementary item in Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this Item, to the extent not included above, will be contained in our 2021 Proxy Statement and is herein incorporated by reference.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 402 of Regulation S-K will be contained in the 2021 Proxy Statement under "Director Compensation" and "Executive Compensation" (excluding the information under the caption “Report of the Compensation Committee”) and is incorporated herein by reference.
The information required by Item 407(e)(5) of Regulation S-K will be contained under the caption “Report of the Compensation Committee Report” of the Proxy Statement. Such information shall not be deemed to be “filed.”

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
(a)Security Ownership of Certain Beneficial Owners and Management.
See the information contained under the heading Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers of the 2021 Proxy Statement, which information is incorporated herein by reference.
(b)Securities Authorized for Issuance under Equity Compensation Plans.
The following table provides information about shares of AES common stock that may be issued under AES' equity compensation plans, as of December 31, 2020:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2020)
(a) (b) (c)
Plan category Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders (1)
7,303,922 (2)
$ 12.56 12,652,436
Equity compensation plans not approved by security holders - - -
Total 7,303,922 $ 12.56 12,652,436
_____________________________
(1)The following equity compensation plans have been approved by The AES Corporation's Stockholders:
(a)The AES Corporation 2003 Long Term Compensation Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an additional 9,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 38,000,000. In 2015, an additional amendment to the Plan to provide an additional 7,750,000 shares was approved by AES' stockholders, bringing the total authorized shares to 45,750,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $12.56 (excluding performance stock units, restricted stock units and director stock units), with 12,652,436 shares available for future issuance.
(b)The AES Corporation Second Amended and Restated Deferred Compensation Plan for directors provided for 2,000,000 shares authorized for issuance. Column (b) excludes the Director stock units granted thereunder. In conjunction with the 2010 amendment to the 2003 Long Term Compensation Plan, ongoing award issuance from this plan was discontinued in 2010 as Director stock units will be issued from the 2003 Long Term Compensation Plan. Any remaining shares under this plan, which are not reserved for
190 | 2020 Annual Report
issuance under outstanding awards, are not available for future issuance and thus the amount of 161,688 shares is not included in Column (c) above.
(2)Includes 3,039,035 (of which 839,278 are vested and 2,199,757 are unvested) shares underlying PSU and RSU awards (assuming 2018 and 2020 PSUs median performance and 2019 PSU maximum performance), 1,599,308 shares underlying Director stock unit awards, and 2,665,579 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 7,303,922 shares.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information regarding related party transactions required by this item will be included in the 2021 Proxy Statement found under the headings Related Person Policies and Procedures and Board and Committee Governance and are incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item 14 will be included in the 2021 Proxy Statement under the headings Information Regarding The Independent Registered Public Accounting Firm, Audit Fees, Audit Related Fees, and Pre-Approval Policies and Procedures and is incorporated herein by reference.
191 | 2020 Annual Report
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE
(a)Financial Statements.
Financial Statements and Schedules: Page
Consolidated Balance Sheets as of December 31, 2020 and 2019
Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Changes in Equity for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
Notes to Consolidated Financial Statements
Schedules
S-2-S-7
(b)Exhibits.
3.1 Sixth Restated Certificate of Incorporation of The AES Corporation is incorporated herein by reference to Exhibit 3.1 of the Company's Form 10-K for the year ended December 31, 2008.
3.2 By-Laws of The AES Corporation, as amended and incorporated herein by reference to Exhibit 3.1 of the Company's Form 8-K filed on December 10, 2019.
4 There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request. Since these documents are not required filings under Item 601 of Regulation S-K, the Company has elected to file certain of these documents as Exhibits 4.(a)-4.(j).
4.(a) Senior Indenture, dated as of December 8, 1998, between The AES Corporation and Wells Fargo Bank, National Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated herein by reference to Exhibit 4.01 of the Company's Form 8-K filed on December 11, 1998 (SEC File No. 001-12291).
4.(b) Ninth Supplemental Indenture, dated as of April 3, 2003, between The AES Corporation and Wells Fargo Bank, National Association (as successor by consolidation to Wells Fargo Bank Minnesota, National Association) is incorporated herein by reference to Exhibit 4.6 of the Company's Form S-4 filed on December 7, 2007.
4.(c) Nineteenth Supplemental Indenture, dated April 6, 2015, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on April 6, 2015.
4.(d) Twentieth Supplemental Indenture, dated May 25, 2016, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 25, 2016.
4.(e) Twenty-First Supplemental Indenture, dated August 28, 2017, between The AES Corporation and Deutsche Bank Trust Company, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on August 28, 2017.
4.(f) Twenty-Second Supplemental Indenture, dated March 15, 2018, between The AES Corporation and Deutsche Bank Trust Company Americas, as Trustee, is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 15, 2018.
4.(g) Twenty-Fourth Supplemental Indenture, dated March 15, 2018, between The AES Corporation and Deutsche Bank Trust Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 21, 2018.
4.(h) Twenty-Fifth Supplemental Indenture, dated June 5, 2020, between THE AES Corporation and Deutsche Bank Trust Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on June 8, 2020.
4.(i) Twenty-Sixth Supplemental Indenture, dated December 4, 2020, between THE AES Corporation and Deutsche Bank Trust Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on December 4, 2020.
4.(j) Twenty-Seventh Supplemental Indenture, dated December 7, 2020, between THE AES Corporation and Deutsche Bank Trust Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on December 7, 2020.
4.(k) Description of the Registrant's Securities (filed herewith).
10.1 The AES Corporation Profit Sharing and Stock Ownership Plan are incorporated herein by reference to Exhibit 4(c)(1) of the Registration Statement on Form S-8 (Registration No. 33-49262) filed on July 2, 1992. (P)
10.2 The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 of the Company's Form 10-K for the year ended December 31, 1995 (SEC File No. 00019281). (P)
10.3 Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 of the Registration Statement on Form S-1 (Registration No. 33-40483). (P)
10.4 Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 of Amendment No. 1 to the Registration Statement on Form S-1 (Registration No. 33-40483). (P)
10.5 Deferred Compensation Plan for Directors, as amended and restated, on February 17, 2012 is incorporated herein by reference to Exhibit 10.5 of the Company's Form 10-K for the year ended December 31, 2012.
10.6 The AES Corporation Stock Option Plan for Outside Directors, as amended and restated, on December 7, 2007 is incorporated herein by reference to Exhibit 10.6 of the Company's Form 10-K for the year ended December 31, 2012.
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10.7 The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.63 of the Company's Form 10-K for the year ended December 31, 1994 (SEC File No. 00019281). (P)
10.7A Amendment to The AES Corporation Supplemental Retirement Plan, dated March 13, 2008 is incorporated herein by reference to Exhibit 10.9.A of the Company's Form 10-K for the year ended December 31, 2007.
10.8 The AES Corporation 2001 Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company's Form 10-K for the year ended December 31, 2000 (SEC File No. 001-12291).
10.9 Second Amended and Restated Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.13 of the Company's Form 10-K for the year ended December 31, 2000 (SEC File No. 001-12291).
10.10 The AES Corporation 2001 Non-Officer Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company's Form 10-K for the year ended December 31, 2002 (SEC File No. 001-12291).
10.10A Amendment to the 2001 Stock Option Plan and 2001 Non-Officer Stock Option Plan, dated March 13, 2008 is incorporated herein by reference to Exhibit 10.12A of the Company's Form 10-K for the year ended December 31, 2007.
10.11 The AES Corporation 2003 Long Term Compensation Plan, as Amended and Restated, dated April 23, 2015, is incorporated herein by reference to Exhibit 99.1 of the Company's Form 8-K filed on April 23, 2015.
10.12 Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Outside Directors) is incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on April 27, 2010.
10.13 Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.13 of the Company's Form 10-K for the year ended December 31, 2015.
10.14 Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.14 of the Company's Form 10-K for the year ended December 31, 2019.
10.15 Form of AES Performance Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.15 of the Company's Form 10-K for the year ended December 31, 2015.
10.16 Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.4 of the Company's Form 10-Q for the quarter ended June 30, 2015.
10.17 Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to Exhibit 10.17 of the Company's Form 10-K for the year ended December 31, 2019.
10.18 The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, dated December 29, 2008 is incorporated herein by reference to Exhibit 10.15 of the Company's Form 10-K for the year ended December 31, 2008.
10.18A Amendment to The AES Corporation Restoration Supplemental Retirement Plan, dated December 9, 2011 is incorporated herein by reference to Exhibit 10.17A of the Company's Form 10-K for the year ended December 31, 2012.
10.19 The AES Corporation International Retirement Plan, as amended and restated on December 29, 2008 is incorporated herein by reference to Exhibit 10.16 of the Company's Form 10-K for the year ended December 31, 2008.
10.19A Amendment to The AES Corporation International Retirement Plan, dated December 9, 2011 is incorporated herein by reference to Exhibit 10.18A of the Company's Form 10-K for the year ended December 31, 2012.
10.20 The AES Corporation Severance Plan, as amended and restated on August 4, 2017 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter ended June 30, 2017.
10.21 The AES Corporation Amended and Restated Executive Severance Plan dated October 5, 2018 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter ended September 30, 2018.
10.22 The AES Corporation Performance Incentive Plan, as Amended and Restated on April 23, 2015 is incorporated herein by reference to Exhibit 99.2 of the Company's Form 8-K filed on April 23, 2015.
10.23 The AES Corporation Deferred Compensation Program For Directors dated February 17, 2012 is incorporated herein by reference to Exhibit 10.22 of the Company's Form 10-K filed on December 31, 2011.
10.24 Mutual Agreement, between Andrés Gluski and The AES Corporation dated October 7, 2011 is incorporated herein by reference to Exhibit 10.2 of the Company's Form 10-Q for the period ended September 30, 2011.
10.25 Form of Retroactive Consent to Provide for Double-Trigger Change-In-Control Transactions is incorporated herein by reference to Exhibit 10.7 of the Company's Form 10-Q for the period ended June 30, 2015.
10.26 Amendment No. 3, dated as of December 20, 2019, to the Sixth Amended and Restated Credit and Reimbursement Agreement, dated as of July 26, 2013 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 23, 2019.
10.26A Seventh Amended and Restated Credit and Reimbursement Agreement dated as of December 20, 2019 among The AES Corporation, a Delaware corporation, the Banks listed on the signature pages thereof, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citibank, N.A., Mizuho Bank Ltd. and Crédit Agricole Corporate and Investment Bank, as Joint Lead Arrangers and Joint Book Runners is incorporated herein by reference to Exhibit 10.1.A of the Company's Form 8-K filed on December 23, 2019.
10.27 Collateral Trust Agreement dated as of December 12, 2002 among The AES Corporation, AES International Holdings II, Ltd., Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, an individual trustee is incorporated herein by reference to Exhibit 4.2 of the Company's Form 8-K filed on December 17, 2002 (SEC File No. 001-12291).
10.28 Security Agreement dated as of December 12, 2002 made by The AES Corporation to Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is incorporated herein by reference to Exhibit 4.3 of the Company's Form 8-K filed on December 17, 2002 (SEC File No. 001-12291).
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10.29 Credit Agreement dated as of May 24, 2017 among The AES Corporation, as borrower, the bank listed therein and Bank of America, N.A., as administrative agent is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on May 24, 2017.
21.1 Subsidiaries of The AES Corporation (filed herewith).
23.1 Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP (filed herewith).
24 Powers of Attorney (filed herewith).
31.1 Rule 13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith).
31.2 Rule 13a-14(a)/15d-14(a) Certification of Gustavo Pimenta (filed herewith).
32.1 Section 1350 Certification of Andrés Gluski (filed herewith).
32.2 Section 1350 Certification of Gustavo Pimenta (filed herewith).
101 The AES Corporation Annual Report on Form 10-K for the year ended December 31, 2020, formatted in Inline XBRL (Inline Extensible Business Reporting Language): (i) the Cover Page, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Operations, (iv) Consolidated Statements of Comprehensive Income (Loss), (v) Consolidated Statements of Changes in Equity, (vi) Consolidated Statements of Cash Flows, and (vii) Notes to Consolidated Financial Statements. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
(c)Schedule
Schedule I-Financial Information of Registrant
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