In this Annual Report the terms “AES,” “the Company,” “us,” or “we” refer to The AES Corporation and all of its subsidiaries and affiliates, collectively. The terms “The AES Corporation” and “Parent Company” refer only to the parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates.
In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.
Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.
plants, but also to meet the growing demand for natural gas in the region.
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◦ | Reduced Parent debt by 22%, to $3.7 billion, compared to December 31, 20177 | 2020 Annual Report |
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◦ | In December 2018, the Company achieved a key investment grade financial metric of 3.95x
Superior Results •Following our efforts to strengthen our balance sheet, our Parent leverage one year earlier than previously planned |
As of December 31, 2018, the Company's backlog of 5,787 MW includes:
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◦ | 3,841 MW under construction and coming on-line through 2021; and |
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◦ | 1,946 MW of renewables signed under long-term PPAs |
In 2018, the Company agreedcredit rating was upgraded to sell approximately 48% of its interest in sPower's operating portfolio
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◦ | Once these sales close, AES' ownership in sPower's operating portfolio will decrease from 50% to approximately 26% |
In 2018, the Company signed long-term agreements to sell 25 TBTU of LNG annually in the Dominican Republic, which will contribute to growth beyond 2020investment grade (BBB-) by S&P
In 2018, Fluence was awarded 286 MW of new projects
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(1)Overview
| Investments in subsidiaries excludes $2.2 billion investment in DPL |
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(2)
| Excludes working capital adjustments and growth activity prior to the close of the acquisition. |
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)— which are led by our SBU Presidents. During the first quarter of 2018, the Andes and Brazil SBUs were merged in order to leverage scale and are now reported together as part of the South America SBU. Further, the Puerto Rico and El Salvador businesses, formerly part of the MCAC SBU, were combined with the US SBU, which is now reported as the US and Utilities SBU. Within our four SBUs, we have two lines of business. The first business line is generation, where we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. The second business line is utilities, where 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.
The following summarizes our businesses within our four SBUs.
Overview
Generation
We currently own and/or operate a generation portfolio of 31,79230,308 MW, including onegeneration from our integrated utility.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.
In contract sales, our generation businessesContracts 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 are intended to reduce exposure to the volatility of fuel and electricity prices by linking the business's revenues and 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.
Capacity Payments in Contract Sales — Most of our contract salesCertain contracts include a capacity paymentpayments that coverscover 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 paymentpayments 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 and Capacity Payments sectionssection 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.
Capacity Payments — 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).
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 have periodic adjustmentsinclude indexation for changes in fuel cost indices.fuels. In those cases, we haveseek to match our fuel supply agreements with shorter terms to match those adjustments.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.
37%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.
31%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 plantplants 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.
29% 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.
3% of the capacity of our generation fleet utilizes pet coke, diesel or oil for fuel. OilWe source oil and diesel are sourced locally at prices linked to international markets, whilemarkets. We largely source pet coke is largely sourced 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 2.42.5 million people in two countries. AES' two utilities in the U.S. also include generation capacity totaling 4,1023,973 MW. Our utility businesses consist of IPL (an integrated utility) and DP&L (transmission and distribution) 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, (distribution).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.
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 and competition.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 directly 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.
Competition — Our fully integrated utility, IPL, and our transmission and distribution regulated utility, DP&L, operate as the sole distributors of electricity within their respective jurisdictions. IPL owns and operates all of the businesses and facilities necessary to generate, transmit and distribute electricity. DP&L owns and operates all of the businesses and facilities necessary to transmit and distribute electricity. Competition in the regulated electricity business is primarily from the on-site generation for industrial customers. IPL is exposed to the volatility in wholesale prices to the extent our generating capacity exceeds the native load served under the regulated tariff and short-term contracts. However, effective with the approval of the 2018 IPL rate order in December, annual wholesale margins earned above or below a certain benchmark are shared with customers, thus mitigating this volatility. See the full discussion under the US and Utilities SBU.
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 by the generation or commercialization agents.
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 platform expansion opportunities,in key growth markets, where we can add on toleverage our global scale and synergies with our existing facilities in our key platform markets where we have a competitive advantage.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 and share buybacks.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, wherewhen 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.
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 provideprovides 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.
US AND UTILITIESand Utilities SBU
Our US and Utilities SBU has 2937 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 11,57411,754 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) | Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation | | Contract Expiration Date | | Customer(s) |
| Bosforo | | El Salvador | | Solar | | 43 |
| | 50 | % | | 2018 | | 2043 | | EEO | |
Bosforo (1) | | 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 | AES Nejapa | | El Salvador | | Landfill Gas | | 6 | | | 100 | % | | 2011 | | 2035 | | CAESS |
| Opico | | Opico | | El Salvador | | Solar | | 4 | | | 100 | % | | 2020 | | 2040 | | CLESA |
| Moncagua | | El Salvador | | Solar | | 3 |
| | 100 | % | | 2015 | | 2035 | | EEO | Moncagua | | El Salvador | | Solar | | 3 | | | 100 | % | | 2015 | | 2035 | | EEO |
| El Salvador Subtotal | | 52 |
| | | | El Salvador Subtotal | | 113 | | |
| Southland—Alamitos | | US-CA | | Gas | | 2,075 |
| | 100 | % | | 1998 | | 2019-2020 | | Southern California Edison | Southland—Alamitos | | US-CA | | Gas | | 1,200 | | | 100 | % | | 1998 | | 2023 | | Various |
AES Clean Energy (sPower OpCo A (1)) | | AES Clean Energy (sPower OpCo A (1)) | | US-Various | | Solar | | 1,101 | | | 26 | % | | 2017-2019 | | 2028-2046 | | Various |
| Southland—Redondo Beach | | US-CA | | Gas | | 1,392 |
| | 100 | % | | 1998 | | 2020 | | EDF Energy, LLC, Clean Power Alliance of Southern California | Southland—Redondo Beach | | US-CA | | Gas | | 876 | | | 100 | % | | 1998 | | 2021 | | Various |
sPower (1) | | US-Various | | Solar | | 1,081 |
| | 50 | % | | 2017-2018 | | 2028-2046 | | Various | |
Southland Energy—Alamitos (2) | | Southland Energy—Alamitos (2) | | US-CA | | Gas | | 650 | | | 65 | % | | 2020 | | 2040 | | Southern California Edison |
Southland Energy—Huntington Beach(2) | | 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 Puerto Rico | | US-PR | | Coal | | 524 | | | 100 | % | | 2002 | | 2027 | | Puerto Rico Electric Power Authority |
AES Clean Energy (AES Distributed Energy) (3) | | 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 | | 474 |
| | 100 | % | | 1998 | | 2019-2020 | | Southern California Edison | Southland—Huntington Beach | | US-CA | | Gas | | 236 | | | 100 | % | | 1998 | | 2023 | | Various |
Shady Point (2) | | US-OK | | Coal | | 360 |
| | 100 | % | | 1991 | |
| |
| |
Buffalo Gap II (3) | | US-TX | | Wind | | 233 |
| | 100 | % | | 2007 | |
| |
| Buffalo Gap II (3) | | US-TX | | Wind | | 228 | | | 100 | % | | 2007 | |
| Hawaii | | US-HI | | Coal | | 206 |
| | 100 | % | | 1992 | | 2022 | | Hawaiian Electric Co. | |
Hawaii (4) | | Hawaii (4) | | US-HI | | Coal | | 206 | | | 100 | % | | 1992 | | 2022 | | Hawaiian Electric Co. |
| Warrior Run | | US-MD | | Coal | | 205 |
| | 100 | % | | 2000 | | 2030 | | First Energy | Warrior Run | | US-MD | | Coal | | 205 | | | 100 | % | | 2000 | | 2030 | | Potomac Edison |
| Prevailing Winds (AES Clean Energy/sPower) | | 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 | |
| |
| Buffalo Gap III (3) | | US-TX | | Wind | | 170 | | | 100 | % | | 2008 | |
sPower (1) | | US-Various | | Wind | | 140 |
| | 50 | % | | 2017 | | 2036 | | Various | |
AES Distributed Energy (AES DE) (3) | | US-Various | | Solar | | 136 |
| | 100 | % | | 2015-2018 | | 2029-2042 | | Utility, Municipality, Education, Non-Profit | |
| Highlander (AES Clean Energy/sPower) | | Highlander (AES Clean Energy/sPower) | | US-VA | | Solar | | 165 | | | 50 | % | | 2020 | | 2035 | | Apple, Akami, Etsy, Microsoft |
AES Clean Energy (sPower OpCo A (1)) | | AES Clean Energy (sPower OpCo A (1)) | | US-Various | | Wind | | 140 | | | 26 | % | | 2017 | | 2036 | | Various |
AES Clean Energy (sPower OpCo B (1)) | | AES Clean Energy (sPower OpCo B (1)) | | US-Various | | Solar | | 126 | | | 50 | % | | 2019 | | 2039-2044 | | Various |
Buffalo Gap I (3) | | US-TX | | Wind | | 117 |
| | 100 | % | | 2006 | | 2021 | | Direct Energy | Buffalo Gap I (3) | | US-TX | | Wind | | 108 | | | 100 | % | | 2006 | | 2021 | | Direct Energy |
Southland Energy—Alamitos Energy Center (2) | | Southland Energy—Alamitos Energy Center (2) | | US-CA | | Energy Storage | | 100 | | | 65 | % | | 2021 | | 2041 | | Southern California Edison |
| East Line Solar (AES Clean Energy/sPower) | | 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 | |
| |
| Laurel Mountain | | US-WV | | Wind | | 98 | | | 100 | % | | 2011 | |
| Mountain View I & II | | US-CA | | Wind | | 65 |
| | 100 | % | | 2008 | | 2021 | | Southern California Edison | 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 | Mountain View IV | | US-CA | | Wind | | 49 | | | 100 | % | | 2012 | | 2032 | | Southern California Edison |
Lawa'i (AES DE) (3) | | US-HI | | Solar | | 20 |
| | 100 | % | | 2018 | | 2043 | | Kaua'i Island Utility Cooperative | |
| | | Energy Storage | | 20 |
| | |
Lawa'i (AES Clean Energy/AES Distributed Energy (3)) | | 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)) | | 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 | | Na Pua Makani | | US-HI | | Wind | | 28 | | | 100 | % | | 2020 | | 2040 | | HECO |
| Ilumina | | US-PR | | Solar | | 24 |
| | 100 | % | | 2012 | | 2032 | | Puerto Rico Electric Power Authority | Ilumina | | US-PR | | Solar | | 24 | | | 100 | % | | 2012 | | 2032 | | Puerto Rico Electric Power Authority |
| Laurel Mountain ES | | US-WV | | Energy Storage | | 16 |
| | 100 | % | | 2011 | |
| |
| Laurel Mountain ES | | US-WV | | Energy Storage | | 16 | | | 100 | % | | 2011 | |
| AES Gilbert (Salt River) | | US-AZ | | Energy Storage | | 10 |
| | 100 | % | | 2019 | | 2039 | | Salt River Project Agricultural Improvement and Power District | |
Southland Energy—AES Gilbert (Salt River) (2) | | 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 | |
| |
| Warrior Run ES | | US-MD | | Energy Storage | | 5 | | | 100 | % | | 2016 | |
| United States Subtotal | | 7,420 |
| | | | United States Subtotal | | 7,668 | | |
| | | 7,472 |
| | | | | 7,781 | | |
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(1)Unconsolidated entity, accounted for as an equity affiliate.
| | | | | |
(1)
| Unconsolidated entity, accounted for as an equity affiliate.13 | 2020 Annual Report |
| |
(2)
| Announced the sale of this business in December 2018. |
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(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. |
(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 |
| | | | | | 309 | | | | | |
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| AES Distributed Energy (AES DE) | | US-Various | | Solar | | 47 |
| | 100 | % | | 1H-2H 2019 |
| | | Energy Storage | | 3 |
| | 100 | % | | 2H 2019 |
| Riverhead (sPower) | | US-NY | | Solar | | 20 |
| | 50 | % | | 1H 2019 |
| Bosforo | | El Salvador | | Solar | | 57 |
| | 50 | % | | 1H 2019 |
| Basin Electric (sPower) | | US-SD | | Wind | | 220 |
| | 50 | % | | 2H 2019 |
| San Pablo (sPower) | | US-CA | | Solar | | 100 |
| | 50 | % | | 2H 2019 |
| Antelope DSR3 (sPower) | | US-CA | | Solar | | 20 |
| | 50 | % | | 2H 2019 |
| Kekaha (AES DE) | | US-HI | | Solar | | 14 |
| | 100 | % | | 2H 2019 |
| | | Energy Storage | | 14 |
| | 100 | % | |
| Southland Repowering | | US-CA | | Gas | | 1,284 |
| | 100 | % | | 1H 2020 |
| Na Pua Makani | | US-HI | | Wind | | 28 |
| | 100 | % | | 1H 2020 |
| Alamitos Energy Center | | US-CA | | Energy Storage | | 100 |
| | 100 | % | | 1H 2021 |
| | | | | | | 1,907 |
| | | | |
Utilities — The following table lists our utilities and their generation facilities.majority of projects under construction have executed long-term PPAs or, as applicable, have been assigned tariffs through a regulatory process.
|
| | | | | | | | | | | | | | | | | | |
| Business | | Location | | Approximate Number of Customers Served as of 12/31/2018 | | GWh Sold in 2018 | | Fuel | | Gross MW | | AES Equity Interest | | Year Acquired or Began Operation |
| CAESS | | El Salvador | | 602,000 |
| | 2,122 |
| | | | | | 75 | % | | 2000 |
| CLESA | | El Salvador | | 404,000 |
| | 931 |
| | | | | | 80 | % | | 1998 |
| DEUSEM | | El Salvador | | 81,000 |
| | 138 |
| | | | | | 74 | % | | 2000 |
| EEO | | El Salvador | | 310,000 |
| | 598 |
| | | | | | 89 | % | | 2000 |
| El Salvador Subtotal | | 1,397,000 |
| | 3,789 |
| | | | | | | | |
DPL (1) | | US-OH | | 525,000 |
| | 7,139 |
| | Coal | | 129 |
| | 100 | % | | 2011 |
IPL (2) | | US-IN | | 498,000 |
| | 15,092 |
| | Coal/Gas/Oil | | 3,973 |
| | 70 | % | | 2001 |
| United States Subtotal | | 1,023,000 |
| | 22,231 |
| | | | 4,102 |
| | | | |
| | | | | 2,420,000 |
| | 26,020 |
| | | | | | | | |
_____________________________
| | | | | |
(1)
| DPL's subsidiary, AES Ohio Generation, LLC, owned an undivided interest in Conesville Unit 4. In October 2018, the co-owner of Conesville Unit 4 announced that the plant will be retired by May 2020. DPL's subsidiary, 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. DPL's GWh sold in 2018 represent DPL's wholesale revenues and DP&L's Standard Service Offer (SSO) utility revenues, which are sales to utility customers who use DP&L to source their electricity through the competitive bid process. Total transmission sales were 14,439 GWh.14 | 2020 Annual Report |
| |
(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. |
The following map illustrates the locations of our US and Utilities facilities:
US and Utilities Businesses
U.S. 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;
•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 (ii)(iii) a rider for the timely recovery of demand side management energy efficiency program costs, incurredand (iv) riders to comply with environmental lawscollect changes in capacity sales and regulations.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, and arebut the overall structure of IPL's rates is subject to review at the same time asof 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 operates on a meritdispatches generation assets in economic order dispatch, 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.
Business Description — IPL 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. IPL has an exclusive right to provide electric service to those customers. IPL's service area covers about 528 square miles with an estimated population of approximately 950,000. IPL owns and operates four generating stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. 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 this location, which provides frequency response. The third station, Eagle Valley, is a newly constructed 671 MW CCGT natural gas plant. IPL took operational control and commenced commercial operations of this CCGT plant in April 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines.
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 Rate Order"). The 2018 Rate Order 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 order also provides customers with approximately $50 million in benefits, including tax reform benefits associated with the TCJA, over a two-year period through a rate adjustment mechanism beginning in March 2019.
Key Financial Drivers —IPL's financial results are driven primarily by retail demand, weather, and outage costs. In addition, IPL's financial results are likely to be driven by many factors, including, but not limited to:
regulatory outcomes;
the passage of new legislation, implementation of regulations or other changes in regulation;
timely recovery of capital expenditures; and
to a lesser extent, wholesale and capacity prices.
Construction and 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. Additionally, IPL is currently evaluating future investments under
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 electric utilitieswas reflected in Indiana can recover costs (includingrates 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 return)cleaner and more diverse generation mix for IURC approved infrastructure improvement plans.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.
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
Regulatory Framework and Market StructureBusiness Description — DPL is an energy holding company whose principal subsidiaries includesubsidiary is DP&L. DP&L, andwhich also does business as AES Ohio, Generation, LLC, bothis a utility company that transmits and distributes electricity to retail customers in a 6,000 square mile area of which operate in Ohio. Electric customers withinWest Central Ohio are permittedand is subject to purchase power under contract from a 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 haveregulatory 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 their state-certified territories.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.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 comply with alternativepower purchased through the competitive bid process, participation in the PJM RTO, severe storm damage, and energy renewables, energy efficiency, and economic development costs.efficiency. DP&L's wholesale 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 Pennsylvania, New Jersey, Maryland, Delaware, D.C., Virginia, Ohio, West Virginia, Kentucky, North
Carolina, Tennessee, Indiana and Illinois.a multi-state region, including Ohio. PJM also runsadministers the day-ahead and real-time energy markets, ancillary services market and forward capacity market for its members.
Business Description — DP&L transmits, distributes and sells electricity to retail customers in a 6,000 square mile area of West Central Ohio. Ohio consumers have the right to choose the electric generation supplier from whom they purchase retail generation service; however, retail transmission and distribution services are still regulated. DP&L has the exclusive right to provide such transmission and distribution services to those customers. Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and governmental customers.
In September 2018, DP&L received an order from the PUCO establishing new base distribution rates, for DP&L (“the order”), 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 reflectsreflected an increase to distribution revenues of $30 million per year. In addition, the order authorizesauthorized DP&L to collect from customers costs related to qualified investments through a Distribution Investment Rider changes("DIR"), changed the Decoupling Rider to reduce variability from the impact of weather and demand, partially resolvesresolved regulatory issues related to the TCJA, and authorizesauthorized DP&L to defer certain vegetation management costs for future collection.
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 two-year extensionterm of its Distribution Modernization Rider ("DMR") through October 2022, infour years, under an aggregate cap of approximately $268 million on the proposed amount of $199 millionsuch 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 eachPhase 2 of the two additional years. The request was made pursuant to the PUCO’s October 2017 ESP order, which approved the DMR and the option forSmart 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 two-year extension. The extension request is set at a level expectednew ESP that does not seek to reduce debt obligations at both DP&L and DPL andimplement certain non-bypassable charges, including those related to position DP&L to make capital expenditures to maintain and modernize its electric grid.
Key Financial Drivers •— DPL's financial results are primarily driven by customer growth. FollowingDP&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 issuanceresidents and businesses of the distribution rate order in September 2018City of Dayton, and the resulting changes to the decoupling rider, DPL's financial results are no longer driven by retail demandpromotion of solar and weather, but will be impacted by customer growthresiliency development within ourDP&L’s service territory.
In addition, DPL's financial results are likelyCertain parties which intervened in the ESP proceedings have filed petitions for rehearing of the recent PUCO ESP order, some of which seek to be driven by many factors, including, but not limited to:eliminate DP&L's RSC from its rates and others to re-implement ESP 3 without
the passageDMR. The ultimate outcome of new legislation, new regulations or otherthese 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 regulation;
timely recovery of transmission and distribution expenditures; and
exiting generation assets currently owned by AES Ohio Generation.customer demand.
Construction and Development Strategy — Planned construction additionsprojects primarily relate to new investments in and upgrades to DPL'sDP&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.
DP&LDPL is projecting to spend an estimated $628$767 million on capital projects forfrom 2021 through 2023, which includes expected spending under DP&L's Smart Grid Plan included in the period 2019 through 2021. We expect to finance this construction with a combination of cashStipulation and Recommendation entered into on hand, short-term financing, long-term debtOctober 23, 2020 (see Regulatory Framework and cash flows from operations.
In December 2018, DP&LMarket Structure above) as well as new transmission projects. The Smart Grid Plan was initially filed a Distribution Modernization Plan with the PUCO in December 2018 proposing to invest $576 million in capital projects over the next 20 years. The principal components of the Distribution Modernization Plan10 years and includes leveraging technologies to modernize and improve the sustainability of the grid, and enhancing customer experience and security. These initiatives willsecurity, 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 in terms of geography, technology and fuel source.portfolio. The principal markets and locations where we are engaged in the generation and supply of electricity (energy and capacity) are the Western Electric Coordinating Council,California Independent System Operator ("CAISO"), PJM, Southwest Power Pool Electric Energy NetworkHawaii, and Hawaii.Puerto Rico. AES Southland, operating in the Western Electric Coordinating Council,CAISO, is our most significant generatinggeneration 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. TheSome plants are generally eligible for availability bonuses on an annual basis if they meet certain requirements. In additionCoal 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 costflexibility.
Warrior Run is a key business driver for someone of our facilities.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
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.—— For aRisk Factors for additional discussion of environmentalon U.S. regulatory matters affecting U.S. Generation, see Item 1.—United States Environmental and Land-Use Legislation and Regulations.matters. AES Southland
Business Description — In terms of aggregate installed capacity, AES Southland is one of the largest generation operators in California by aggregate installed capacity, with an installed gross capacity of 3,9413,611 MW accounting for approximately 5%at the end of the state's installed capacity and 17% of the peak demand in Southern California Edison's territory.2020. The threefive 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.
All of AES Southland's capacity was previously contracted through a 20 year agreement (the “Tolling Agreement”), that expired on May 31, 2018. Currently, AES Huntington Beach, LLC, and AES Alamitos, LLC, and AES Redondo Beach ("Southland OTC units") are contracted thoughthrough Resource Adequacy Purchase Agreements (the “RAPAs”(“RAPAs”),. Under the RAPAs, as approved by the California Public Utilities Commission, in 2017. AES Redondo Beach, LLC has also entered into various RAPAs for the period of June 1, 2018 through December 31, 2020.
Under the RAPAs, thethese 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 willwould result in an assessed penalty.
Re-powering — In November 2014, AES Southland was awarded 20-year contracts by SCESouthern California Edison ("SCE") to provide 1,284 MW of combined cycle gas-fired generation and 100 MW of interconnected battery-based energy storage.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 resource adequacy agreementsRAPAs with annual energy put options. If AES Southland exercises the annual put option, is exercised, all capacity, energy and ancillary services will be sold to SCE in exchange for a fixed monthly capacity fee that covers fixed operating cost, debt service, and return on capital. In addition, SCE will reimburse variable costs and provide the natural gas and charging electricity. If the annual put option is not exercised, SCE only has rights to the resource adequacy capacity for that contract year and AES Southland can sell the energy and ancillary services to other counterparties.gas.
In April 2017, the California Energy Commission unanimously approved the licenses for the newSouthland Energy combined cycle projects at AES Alamitos and AES Huntington Beach. In June 2017, AES closed the financing of $2.0$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 this new capacity startedthe Alamitos Energy Center, an interconnected battery-based energy storage facility, began in 2017June 2019 and commercial operation of the gas-fired capacity is expected to commence in 2020 and the energy storage capacity is expected to commence inwas 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.
Additional U.S. Generation Facilities
Regulatory Framework and Market Structure — For the non-renewable businesses, 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.
Several of our generation businesses in the U.S. currently operate as QFs, includingAES Hawaii Shady Point and Warrior Run, as defined under the PURPA. These businesses entered into long-term contracts with electric utilities 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 applications 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.
Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under the EPAct 1992. 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 Federal Power Act and FERC's regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to FERC that the seller lacks market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller.
The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by FERC, and regional regulation as defined by rules designed and implemented by the RTOs, non-profit corporations that operate the regional transmission grid and maintain organized markets for electricity. These rules, for the most part, govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. See Item 1A.—Risk Factors for additional discussion on U.S. regulatory matters.Business Description — Additional businesses include thermal, wind, and solar generating facilities, of which our U.S. Renewables businesses and AES Hawaii are the most significant.
U.S. Renewables
sPower owns and/or operates 153 utility and distributed electrical generation systems with a capacity of 1,221 MWh currently in operation across the U.S. sPower is also actively buying, developing and constructing renewable assets in the U.S.
AES Distributed Energy develops, constructs and sells electricity generated by photovoltaic solar energy systems and energy storage systems to public sector, utility, and non-profit entities through PPAs.
Excluding sPower wind plants, AES has 732 MW of wind capacity in the U.S., located in California, Texas and West Virginia. Mountain View I & II, Mountain View IV and Buffalo Gap I sell under long-term PPAs through which the energy price on the entire production of these facilities is guaranteed. 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.
AES manages the U.S. Renewables portfolio as part of its broader investments in the U.S.. A portion of U.S. Solar projects and the majority of wind projects 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.
AES Hawaii
AES Hawaii receives a fuelan 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 fuelenergy 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 December 20192021 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 2019.31, 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 — U.S. thermal generation'sAES 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. The financial results of U.S. Wind are primarily driven by increased production due to faster and less turbulent wind and reduced turbine outages. In addition, PJM and ERCOT power prices impact financial results for the wind projects that are operating without long-term contracts for all or some of their capacity. The financial results of U.S. Solar are primarily driven by the amount of sunshine hours available at the facilities, cell maintenance and growth in projects. For additional details see Key Trends and Uncertainties in Item 7.— Management’s Discussion and Analysis of Financial Condition and Results of Operations. Construction and Development — Planned capital projects include the AES Southland re-powering described above. In addition to the new construction project, U.S. Generation performs capital projects related to major plant
maintenance, repairs and upgrades to be compliant with new environmental laws and regulations. sPower has 360 MW of projects under construction and a development pipeline that includes 938 MW of projects for which long-term PPAs have been signed. The budget for construction of the projects currently under construction and the contracted projects is over $1.8 billion. AES Distributed Energy has 78 MW of projects under construction and a development pipeline that includes 332 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 $1 billion.
Puerto Rico
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 suppliesprovides 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 98%97% produced by thermal plants (47% from petroleum, 34%(43% from natural gas, 17%36% from petroleum, and 18% from coal).
AES Clean Energy
Business Description — AES Puerto Rico ownsmanages the U.S. renewables portfolio, which comprises AES Distributed Energy, sPower and operates a coal-fired cogeneration plantother renewable assets, as part of its broader investments in the U.S. On January 4, 2021, the sPower and a solar plant of 524 MWAES 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 24 MW, respectively, representing approximately 9%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 installedtop 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 Puerto Rico. Both plants havevariability 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, expiringthrough which the energy price on the entire production of these facilities is guaranteed. The financial results of renewable assets are
primarily driven by the amount of wind or solar resource at the facilities, availability of facilities, and growth in 2027projects.
Laurel Mountain, Buffalo Gap II and 2032, respectively,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.
AES Clean Energy has a renewable project backlog that includes 2,206 MW of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Ricoprojects for further discussionwhich long-term PPAs have been signed or, as applicable, tariffs have been assigned through a regulatory process. The budget for construction of the long-term PPAprojects 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
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, as well as 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.Honduras, allowing transactions with all Central American countries. The sector has approximately 1,6591,799 MW of installed capacity, composed primarily of thermal (43%(40%), hydroelectric (34%(31%), geothermal (10%solar (11%), biomass (9%), and solar (4%geothermal (9%) generation plants.
Business DescriptionDevelopment Strategy — In order to explore new business opportunities, AES El Salvador is the majority owner of four of the five distribution companies operating in El Salvador (CAESS, CLESA, EEO and DEUSEM).created AES El Salvador's territory covers 79% of the country and accounted for 4,040 GWh of the wholesale market energy purchases during 2018, or about 63% market share.
Construction and Development
— As part of the initiative to pursue opportunities in renewable generation, AES El Salvador has entered into a joint venture with Corporacion Multi-Inversiones, a Guatemalan investment group, to develop, construct and operate Bosforo, a 142 MW solar farm. 43 MW of the project were completed in 2018 and are fully operational. 57 MW are under construction and expected to become operational during the first half of 2019
Soluciones, an LED public lighting service provider and the remaining 42 MW will start construction in 2019main commercial and are expected to be completedindustrial solar photovoltaic EPC provider in the second half of 2019. The energy produced by this project will be contracted directly by AES' utilities in El Salvador.country. AES Next is also the O&M services provider for the Bosforo project.
South America SBU
Our South America SBU has generation facilities in four countries — Chile, Colombia, Argentina and Brazil. AES Gener whichis 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, is a publicly traded company in Chile.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 TietêAES Brasil through its 24%44% economic interest.
Operating installed capacity of our South America SBU totals 12,43512,304 MW, of which 33%34%, 28%29%, 8%, and 31%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) | 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 | | 2019-2026 | | Various | Chivor | | Colombia | | Hydro | | 1,000 | | | 67 | % | | 2000 | | 2020-2037 | | Various |
| Castilla | | Castilla | | Colombia | | Solar | | 21 | | | 67 | % | | 2019 | | 2034 | | Ecopetrol |
| Tunjita | | Colombia | | Hydro | | 20 |
| | 67 | % | | 2016 | | Tunjita | | Colombia | | Hydro | | 20 | | | 67 | % | | 2016 | |
| Colombia Subtotal | | 1,020 |
| | | | Colombia Subtotal | | 1,041 | | |
Gener - Chile (1) | | Chile | | Coal/Hydro/Diesel/Solar/Biomass | | 1,532 |
| | 67 | % | | 2000 | | 2019-2040 | | Various | Gener - Chile (1) | | Chile | | Coal/Hydro/Diesel/Solar/Wind/Biomass | | 1,578 | | | 67 | % | | 2000 | | 2020-2040 | | Various |
Guacolda (2) | | Chile | | Coal | | 760 |
| | 33 | % | | 2000 | | 2019-2032 | | Various | Guacolda (2) | | Chile | | Coal | | 764 | | | 33 | % | | 2000 | | 2020-2032 | | Various |
| Electrica Angamos | | Chile | | Coal | | 558 |
| | 67 | % | | 2011 | | 2026-2037 | | Minera Escondida, Minera Spence, Quebrada Blanca | 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 | | Chile | | Coal | | 550 | | | 40 | % | | 2016 | | 2030-2037 | | SQM, Sierra Gorda, Quebrada Blanca |
| Cochrane ES | | Chile | | Energy Storage | | 20 |
| | 40 | % | | 2016 | | Cochrane ES | | Chile | | Energy Storage | | 20 | | | 40 | % | | 2016 | |
| Electrica Angamos ES | | Chile | | Energy Storage | | 20 |
| | 67 | % | | 2011 | |
| |
| Electrica Angamos ES | | Chile | | Energy Storage | | 20 | | | 67 | % | | 2011 | |
| Norgener ES (Los Andes) | | Chile | | Energy Storage | | 12 |
| | 67 | % | | 2009 | |
| |
| Norgener ES (Los Andes) | | Chile | | Energy Storage | | 12 | | | 67 | % | | 2009 | |
| Alfalfal Virtual Reservoir | | Alfalfal Virtual Reservoir | | Chile | | Energy Storage | | 10 | | | 67 | % | | 2020 | |
| Chile Subtotal | | 3,452 |
| | | | Chile Subtotal | | 3,512 | | |
TermoAndes (3) | | Argentina | | Gas/Diesel | | 643 |
| | 67 | % | | 2000 | | 2019-2020 | | Various | TermoAndes (3) | | Argentina | | Gas/Diesel | | 643 | | | 67 | % | | 2000 | | 2020 | | Various |
| AES Gener Subtotal | | 5,115 |
| | | | AES Gener Subtotal | | 5,196 | | |
| Alicura | | Argentina | | Hydro | | 1,050 |
| | 100 | % | | 2000 | |
| | Various | Alicura | | Argentina | | Hydro | | 1,050 | | | 100 | % | | 2000 | |
| Paraná-GT | | Argentina | | Gas/Diesel | | 870 |
| | 100 | % | | 2001 | |
| |
| Paraná-GT | | Argentina | | Gas/Diesel | | 870 | | | 100 | % | | 2001 | |
| San Nicolás | | Argentina | | Coal/Gas/Oil | | 675 |
| | 100 | % | | 1993 | |
| |
| San Nicolás | | Argentina | | Coal/Gas/Oil/Energy Storage | | 691 | | | 100 | % | | 1993 | |
Guillermo Brown (4) | | Argentina | | Gas/Diesel | | 576 |
| | — | % | | 2016 | | Guillermo Brown (4) | | Argentina | | Gas/Diesel | | 576 | | | — | % | | 2016 | |
Los Caracoles (4) | | Argentina | | Hydro | | 125 |
| | — | % | | 2009 | | 2019 | | Energia Provincial Sociedad del Estado (EPSE) | |
| Cabra Corral | | Argentina | | Hydro | | 102 |
| | 100 | % | | 1995 | |
| | Various | Cabra Corral | | Argentina | | Hydro | | 102 | | | 100 | % | | 1995 | | Various |
| Vientos Bonaerenses | | Vientos Bonaerenses | | Argentina | | Wind | | 100 | | | 100 | % | | 2020 | | 2024-2040 | | Various |
| Vientos Neuquinos | | Vientos Neuquinos | | Argentina | | Wind | | 100 | | | 100 | % | | 2020 | | 2024-2040 | | Various |
| Ullum | | Argentina | | Hydro | | 45 |
| | 100 | % | | 1996 | |
| | Various | Ullum | | Argentina | | Hydro | | 45 | | | 100 | % | | 1996 | | Various |
| Sarmiento | | Argentina | | Gas/Diesel | | 33 |
| | 100 | % | | 1996 | |
| |
| Sarmiento | | Argentina | | Gas/Diesel | | 33 | | | 100 | % | | 1996 | |
| El Tunal | | Argentina | | Hydro | | 10 |
| | 100 | % | | 1995 | |
| | Various | El Tunal | | Argentina | | Hydro | | 10 | | | 100 | % | | 1995 | | Various |
| Argentina Subtotal | | 3,486 |
| | | | Argentina Subtotal | | 3,577 | | |
Tietê (5) | | Brazil | | Hydro | | 2,658 |
| | 24 | % | | 1999 | | 2029 | | Various | Tietê (5) | | Brazil | | Hydro | | 2,658 | | | 44 | % | | 1999 | | 2029 | | Various |
| Alto Sertão II | | Brazil | | Wind | | 386 |
| | 24 | % | | 2017 | | 2033-2035 | | Various | Alto Sertão II | | Brazil | | Wind | | 386 | | | 44 | % | | 2017 | | 2033-2035 | | Various |
| Guaimbe | | Brazil | | Solar | | 150 |
| | 24 | % | | 2018 | | 2037 | | CCEE | |
| Tietê Subtotal | | 3,194 |
| | | | |
| Uruguaiana | | Brazil | | Gas | | 640 |
| | 46 | % | | 2000 | | |
| Brazil Subtotal | | 3,834 |
| | | | |
| Ventus | | Ventus | | Brazil | | Wind | | 187 | | | 44 | % | | 2020 | | 2034 | | Regulated Market |
| Guaimbê | | Guaimbê | | Brazil | | Solar | | 150 | | | 44 | % | | 2018 | | 2037 | | CCEE |
| AGV Solar | | AGV Solar | | Brazil | | Solar | | 75 | | | 44 | % | | 2019 | | 2039 | | Various |
| Boa Hora | | Boa Hora | | Brazil | | Solar | | 69 | | | 44 | % | | 2019 | | 2035 | | CCEE |
| Drogaria Araujo | | Drogaria Araujo | | Brazil | | Solar | | 5 | | | 44 | % | | 2019 | | 2029 | | Drogaria Araujo |
| Brasil Community Solar | | Brasil Community Solar | | Brazil | | Solar | | 1 | | | 44 | % | | 2020 | |
| AES Brasil Subtotal | | AES Brasil Subtotal | | 3,531 | | |
| | | 12,435 |
| | | | | 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%.
| | | | | |
(1)
| Gener - Chile plants: Alfalfal, Andes Solar, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Norgener 1, Norgener 2, Queltehues, Ventanas 1, Ventanas 2, Ventanas 3, Ventanas 4 and Volcán.25 | 2020 Annual Report |
| |
(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 33%.
|
| |
(3)
| TermoAndes is located in Argentina, but is connected to both the SEN in Chile and the SADI in Argentina. |
| |
(4)
| AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses. |
| |
(5)
| Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim and Sao Jose. |
(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 | | | | | |
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Boa Hora | | Brazil | | Solar | | 69 |
| | 24 | % | | 1H 2019 |
| AGV Solar | | Brazil | | Solar | | 75 |
| | 24 | % | | 1H 2019 |
| Energetica | | Argentina | | Wind | | 100 |
| | 100 | % | | 1H 2020 |
| Vientos Nequinos | | Argentina | | Wind | | 80 |
| | 100 | % | | 1H 2020 |
| Alto Maipo | | Chile | | Hydro | | 531 |
| | 62 | % | | 2H 2020 |
| | | | | | | 855 |
| | | | |
(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.
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,
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 has operatedoperates in a single power market, referred to as the SEN, which has beenis managed by the grid operator CEN since November 2017. Previously, Chile had two main power systems, the SIC and SING, largely as a result of its geographic shape and size, which were merged to form the SEN.CEN. The SEN has an installed capacity
of approximately 24,586 MW. SEN26,056 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, (former SIC), 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.conditions in the highest demand area of the SEN. In the northern region of the SEN, (former SING), which includes the Atacama Desert, thermoelectric capacity represents the majority of installed capacity as hydroelectric generation is not feasible.capacity. The fuels used for thermoelectric generation, mainly coal, diesel, and LNG, are indexed to international prices. In 2018,2020, the installed generation installed capacity in the Chilean market was composed of the following:
|
| | | |
Installed Capacity | | | SEN |
Thermoelectric | | | 54% |
Hydroelectric | | | 27% |
Solar | | | 10% |
Wind | | | 7% |
Other | | | 2% |
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. HydrologicalPrecipitation and snow melt impact hydrological conditions influence reservoir water levels, which in turn affectsChile. 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. Precipitation and snow melt impact hydrological conditions in Chile. Rains occurs principally between June and August and are scarce during the remainder of the year. Snow melt occurs between September and November.
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.
In July 2016, modifications to the Transmission Law were enacted. This law establishes that the transmission system will be completely paid for by the end-users, gradually allocating the costs on the demand side from 2019 through 2034.
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 U.S. dollars,USD, although payments are made in Chilean pesos.
Business Description — In Chile, through AES Gener, we are engaged inThe Chilean government’s decarbonization plan includes the generation and supply of electricity (energy and capacity) in the SEN. AES Gener is the second largest generation operator in Chile in terms of installed capacity with 3,400 MW, excluding energy storage , and has a market share of approximately 14% as of December 31, 2018.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and fuel source. AES Gener's 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.
Our commercial strategy in Chile aims to maximize margin while reducing cash flow volatility. To achieve this, we contract a significant portion of our coal and hydroelectric baseload capacity under long-term agreements with a diversified customer base. Power plants not considered within our baseload capacity (higher variable cost units, mainly diesel) sell energy on the spot market when operating during scarce system supply conditions, such as low hydrology and/or plant outages. In Chile, sales on the spot market are made only to other generation companies who are memberscomplete retirement of the SEN atcoal fleet by the system marginal cost.
end of 2040 and carbon neutrality by 2050. During the year, AES Gener currently has long-term contracts, with an average remaining termannounced 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 approximately 11 years, with regulated distribution companiescurrent transmission constraints, and unregulated customers, such as miningto disconnect both plants from the SEN in 2025. On December 26, 2020, the
Ministry of Energy’s Supreme Decree Number 42 went into effect, allowing coal plants to enter into Strategic Reserve Status (“SRS”) and industrial companies. In general, these long-term contracts include pass-through mechanisms for fuel costs along with price indexations to US CPI.
In addition to energy payments, AES Gener also receivesreceive 60% of capacity payments for the 5-year period following its shutdown to compensate for availability during periodsremain connected as a backup in case of peak demand. CEN annually determinesa system emergency. Following the capacity requirements for eachissuance of this regulation and per the disconnection and termination agreement signed with the Chilean government in June 2019, the Ventanas 1 power plant. The
capacity price is fixed semiannually by the National Energy Commission and indexedplant was shut down on December 29, 2020 to the CPI and other relevant indices.enter into SRS.
Environmental Regulation — During 2017 and 2016, the Ministry of Environment under the previous administration updated the Atmospheric Decontamination Plan for the Ventanas and Huasco regions. Under that proposed plan, no significant investments were needed to comply with new requirements at our plants Ventanas and Guacolda. However, the authority under the current administration rejected that proposed plan on December 30, 2017. In December 2018,March 2019, a new decontamination plan for the Ventanas and Huasco regionsregion was proposedapproved. We are currently implementing the requirements defined by the authority under the current administration. Currently, the Environmental Ministry expects approval of the new decontamination plan in early March 2019which will impact our Ventanas and we are currently assessing the impact of the new proposed decontamination plan.Guacolda businesses.
Chilean law requires all electricity generators to supply a certain portion of their total contractual obligations with NCREs.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 the future requirements.
In September 2014, a new emission tax, or green tax, was enacted effective January 2017. EmissionsSince 2017, emissions of PM,particulate matter, SO2, NOxX, and CO2 are monitored for plants with an installed capacity over 50 MW; these emissions are taxed. In the case of CO2, the tax will beis equivalent to $5 per ton emitted. Certain PPAs originating from the SING have clauses allowing the Company to pass the green tax costs to unregulated customers. Distributioncustomers, while some distribution PPAs originating from the SIC 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 —Hedge levels at AES Gener limit volatility 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 the underlying financial drivers.Chivor's results of operations. In addition to hydrology, 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 (our hedging strategy reduces this risk, but some residual risk remains);
tax policy changes;
legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets;Colombian peso; and
market price risk when re-contracting.
Colombia
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 (68%(69%) and thermal (31%), totaled 17,39217,473 MW as of
December 31, 2018.2020. The marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2018, 84%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 CREG,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 EnergeticEnergy 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.
In 2018,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 Ministrywindiest spots on Earth, and two projects (255 MW) were awarded a 15-year PPA at the last renewable auction. One project (99 MW) of Mines and Energy published the final resolution for renewable energy auctions in Colombia. The auction allocates 12-year energy contracts for 1.1 TW/h of energy demand under which renewable generators commit to be in commercial operation by December 2021. The auction is scheduled for February 2019Wind Cluster has Environmental License and the regulator expects to adoptothers are progressing smoothly in their development process. During 2020, AES Colombia was awarded the current regulation for61 MW San Fernando Solar project through a 15-year PPA with Ecopetrol and started construction in September. This solar project, along with the entry of21 MW Castilla project built in 2019 also with a PPA with Ecopetrol, has been fundamental in leading the renewable generation to the market during 2019.in Colombia.
Argentina
Business Description — We operateAES operates plants in Colombia throughArgentina totaling 4,220 MW, representing 10% of the country's total installed capacity. AES Chivor, a subsidiary of AES Gener, which owns a hydroelectric plant with an installed capacitydiversified generation portfolio in Argentina in terms of 1,000 MW,geography, technology, and Tunjita, a 20 MW run-of-river hydroelectric plant, both located approximately 160 km east of Bogota.fuel source. AES Chivor’s installed capacity accounted for approximately 6% of system capacity atArgentina's plants are placed in strategic locations within the end of 2018. AES Chivor is dependent on hydrological conditions, which influence generation and spot prices of non-contracted generationcountry in Colombia.
AES Chivor's commercial strategy aimsorder to execute contracts with commercial and industrial customers, and bid in public tenders for one to four year contracts, mainly with distribution companies to reduce margin volatility with proper portfolio risk management. The remainingprovide energy generated by our portfolio is sold to the spot market including ancillary services. Additionally, and customers, making use of wind, hydro, and thermal plants.
AES Chivor receives reliability payments for maintainingprimarily sells its energy in the plant available during periodswholesale 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 scarcity, such as adverse hydrological conditions, in order to prevent power shortages.plants.
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. Hedge levels at Chivor limit volatility in the underlying financial drivers. In addition to hydrology, financialFinancial results are driven by many factors, including, but not limited to:
•forced outages;
•exposure to fluctuations of the ColombianArgentine peso;
•changes in hydrology and wind resources;
spot market prices.•timely collection of FONINVEMEM installments and outstanding receivables (see Regulatory Framework and Market Structure below); and
Argentina•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, 2018,2020, the installed capacity of the SADI totaled 38,53841,991 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (64%(61%) and hydroelectric generation (28%(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 betweenfrom June andto August.
Regulatory Framework — 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
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 the prices for electricity and defines fuel and adjusts them periodically for inflation, changes in fuel prices and other factors.reference prices. As a result, our businesses are particularly sensitive to changes in regulation.
The Argentine electric market is an "average cost" system, with generators beingsystem. Generators are compensated for fixed costs and non-fuel variable costs, plus a rateunder prices denominated in Argentine pesos. CAMMESA is in charge of return. All fuel, except coal, can be providedproviding the natural gas and liquid fuels required by CAMMESA. In December 2018, Resolution 70/2018 was enacted. This allowsthe generation companies, to buy fuel directly from producers or from CAMMESA.except for coal.
Argentina’s administration continues introducing regulatory improvements aiming to normalize the energy sector. Among others, Resolution 19/2017 was enacted in 2017 to set higher tariffs, denominated in USD, for energy and capacity prices. The enactment of resolution 19/2017 ceased the remuneration intended to fund increased capacity projects . Likewise, long term USD-denominated PPAs have been awarded to develop 9.4 GW
of new capacity (thermal and renewable) through the execution of competitive auctions. During 2018,2020, the government has continuedmaintained prices to increasethe end user, prices to reduceincreasing subsidies and decreasethe system deficit. By December 2020, distribution companies recovered an average 55% of the total cost of the system.
AES Argentina has contributed certain accounts receivable to fund the construction of new power plants under FONINVEMEM agreements. These receivables accrue interest and arehave been collected in monthly installments over 10 years onceafter commercial operation date of the related plants begin to operate.plant took place. AES Argentina hasparticipated in the construction of three FONINVEMEM funds related to operationalpower plants under which payments are being received.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 6.7.—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, 2018,2020, AES operates plants totaling 4,129 MW, representing 11%owns 44% of AES Brasil and is the controlling shareholder and manages and consolidates this business. As a result of the country's total installed capacity.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
operational since 2013 with 159 MW of installed capacity, in the SADI includes the TermoAndes plant, a subsidiary of AES Gener, which is connected both to the SADI and the Chilean SEN markets. AES Argentina has a diversified generation portfolio.
AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2018, approximately 93% of the energy wasfully sold in the wholesale electricityregulated market for 20 years.
AES Brasil aims to contract most of its physical guarantee requirements and 7% was sold under contract, as a result of contract sales made by TermoAndes.
Foreign currency controls were liftedsell the remaining portion in December 2015, allowing the Argentine pesospot market. The commercial strategy is reassessed periodically according to float under the administration of the Argentinian Central Bank. In 2018, the Argentine peso devalued by approximately 102% and Argentina’s economy was determined to be highly inflationary. See Item 7.—Management's Discussion and Analysis Key Trends and Uncertainties of this Form 10-K for further discussion.
Tax Regulation — On December 29, 2017, Law 27430 was enacted in Argentina, which introduced a tax reform with several changes in the Argentine tax system, effective on January 1, 2018. This tax reform reduced the statutory corporate tax rate of companies from 35% to 30% in 2018market conditions, hydrology, and 2019, and will reduce the rate to 25% from 2020 onward. The law also eliminated the Equalization Tax on the distribution of earnings generated after January 1, 2018. The Equalization Tax was replaced with a withholding tax on dividends at the rate of 7% for 2018 and 2019, and 13% from 2020 onward.other factors. AES Brasil generally sells available energy through medium-term bilateral contracts.
Key Financial Drivers — FinancialThe 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:
forced outages;•hydrology, impacting quantity of energy generated in the MRE (see Regulatory Framework and Market Structure below for further information);
exposure•growth in demand for energy;
•market price risk when re-contracting;
•asset management;
•cost management; and
•ability to fluctuations of the Argentine peso;
changes in hydrology;
| |
• | timely collection of FONINVEMEM installment and outstanding receivables (See Note 6.—execute on its growth strategy.Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion); and |
natural gas prices and availability for contracted generation.
Brazil
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 162,932 MW, which is primarily176 GW, composed of hydroelectric (64%(62%), thermoelectric (25%), renewable (12%), and nuclear (1%) and renewables (19%).sources. Operation is centralized and controlled by the national operator, ONS, and regulated by ANEEL.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.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.
Business DescriptionIn 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 — Tietê has a portfolio of 12 hydroelectric power plants in the state of São Paulo with total installed capacity of 2,658 MW. Tietê represents approximately 10% of the total generation capacity in the state of São Paulo. Tietê hydroelectric plants operate under a 30-year concession expiring in 2029. AES owns 24% of Tietê and is the controlling shareholder and manages and consolidates this business. Tietê 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. Tietê generally sells available energy through medium-term bilateral contracts.
Tietê'sBrasil's strategy is to grow by adding renewable capacity to its generation platform. 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 2017, Tietê2020, AES Brasil acquired Alto Sertão II Wind Complex (“Alto Sertão II”) locatedthe 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 anUnipar 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.
In March 2020, AES Brasil signed two purchase option agreements for a total installed capacity up to 1,100 MW of 386 MW and subject to 20-year PPAs expiring between 2033 and 2035. Furthermore, in 2017 Tiete acquired Boa Hora Solar, a solar developmentCajuína greenfield wind power project and won a bid to develop a second solar project, AGV Solar, 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 Paulo. In 2018, Tietê acquired Guaimbê, a solar power complex. AllRicardo, which has installed capacity of 437 MW, was signed in February 2021. AES Brasil is seeking other long-term PPAs to fulfill the solar assets are fully contracted with 20 year PPAs. Through its ownership of Tietê, AES owns a 24% economic interestremaining 777 MW in those entities. These assets are not subject to return at the end of the concession.phases 1 and 2.
Under the current terms of the 2018 legal agreement in connection with AES Brasil's concession agreement, Tietêwith the state government, AES Brasil is required to increase its capacity in the state of São Paulo by 15% (or 398 MW). The above mentioned investments in new solar generation capacity in the state of São Paulo allowed Tietê to sign a legal agreement inan additional 81 MW by October 2018 with the state government in which it was agreed that: (i) 80% of the expansion obligation (317 MW) was delivered or is in performance stage; and (ii) the Company will have up to six years from the agreement's approval date to meet the remaining balance (81 MW).2024.
Uruguaiana is a 640 MW gas-fired combined cycle power plant located in the town of Uruguaiana in the state of Rio Grande do Sul. AES manages and has a 46% economic interest in the plant. The plant's operations have been largely suspended due to the unavailability of gas. The plant operated for short periods of time in 2013, 2014 and 2015 when short-term supply of LNG was sourced for the facility. The plant did not operate in 2016, 2017 or 2018. AES has evaluated several alternatives to bring gas supply on a competitive basis to Uruguaiana. Capacity restrictions on the Argentinean pipeline are a challenge, especially during the winter season when gas demand in Argentina is very high. Uruguaiana continues to work toward securing gas on a long-term basis.
— As the system is highly dependent on hydroelectric generation, electricity pricing is driven by hydrology in Brazil. Plant availability is also a significant financial driver as in times of high hydrology AES is more exposed to the spot market. The availability of gas is also a driver for continued operations at Uruguaiana. Tietê's financial results are driven by many factors, including, but not limited to:
hydrology, impacting quantity of energy generated in MRE;
demand growth;
re-contracting price;
asset management and plant availability;
cost management; and
ability to execute on its growth strategy.Construction and Development — As part of the initiative to pursue opportunities in renewable generation discussed above, Tietê is currently constructing photovoltaic power plants with a total projected capacity of 144 MW, subject to 20 year PPAs. Commercial operation of first phase, Boa Hora Solar, and of the second phase, AGV Solar, is expected in the first half of 2019.
MCAC SBU
Our MCAC SBU has a portfolio of generation facilities, including renewable energy, in three countries, with a total capacity of 3,205 MW as of December 31, 2018.3,459 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) | 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 | | CDEEE | DPP (Los Mina) | | Dominican Republic | | Gas | | 358 | | | 85 | % | | 1996 | | 2022 | | Andres, CDEEE, Non-Regulated Users |
| Andres | | Dominican Republic | | Gas | | 319 |
| | 85 | % | | 2003 | | 2022 | | Ede Norte/Ede Este/Ede Sur/Non-Regulated Users | |
Itabo (1) | | Dominican Republic | | Coal | | 295 |
| | 43 | % | | 2000 | | 2022 | | Ede Norte/Ede Este/Ede Sur | |
Andres (1) | | Andres (1) | | Dominican Republic | | Gas | | 319 | | | 85 | % | | 2003 | | 2022 | | Ede Norte, Ede Este, Ede Sur, Non-Regulated Users |
Itabo (2) | | 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 | | Andres ES | | Dominican Republic | | Energy Storage | | 10 | | | 85 | % | | 2017 | |
| Los Mina DPP ES | | Dominican Republic | | Energy Storage | | 10 |
| | 85 | % | | 2017 | | Los Mina DPP ES | | Dominican Republic | | Energy Storage | | 10 | | | 85 | % | | 2017 | |
| Dominican Republic Subtotal | | 992 |
| | | | Dominican Republic Subtotal | | 957 | | |
| Merida III | | Mexico | | Gas | | 505 |
| | 75 | % | | 2000 | | 2025 | | Comision Federal de Electricidad | Merida III | | Mexico | | Gas/Diesel | | 505 | | | 75 | % | | 2000 | | 2025 | | Comision Federal de Electricidad |
Mesa La Paz (3) | | 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 Golfo (TEG) | | Mexico | | Pet Coke | | 275 | | | 99 | % | | 2007 | | 2027 | | CEMEX |
| Termoelectrica del Penoles (TEP) | | Mexico | | Pet Coke | | 275 |
| | 99 | % | | 2007 | | 2027 | | Penoles | Termoelectrica del Penoles (TEP) | | Mexico | | Pet Coke | | 275 | | | 99 | % | | 2007 | | 2027 | | Peñoles |
| Mexico Subtotal | | 1,055 |
| | | | Mexico Subtotal | | 1,361 | | |
Colon (2)(4) | | Panama | | Gas | | 381 |
| | 50 | % | | 2018 | | 2028 | | Electra Noreste/Edemet/Edechi | | Panama | | Gas | | 381 | | | 50 | % | | 2018 | | 2028 | | ENSA, Edemet, Edechi |
| Bayano | | Panama | | Hydro | | 260 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | Bayano | | Panama | | Hydro | | 260 | | | 49 | % | | 1999 | | 2030 | | ENSA, Edemet, Edechi, Other |
| Changuinola | | Panama | | Hydro | | 223 |
| | 90 | % | | 2011 | | 2030 | | AES Panama | Changuinola | | Panama | | Hydro | | 223 | | | 90 | % | | 2011 | | 2030 | | AES Panama |
| Chiriqui-Esti | | Panama | | Hydro | | 120 |
| | 49 | % | | 2003 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | Chiriqui-Esti | | Panama | | Hydro | | 120 | | | 49 | % | | 2003 | | 2030 | | ENSA, Edemet, Edechi, Other |
| Estrella del Mar I | | Panama | | Heavy Fuel Oil | | 72 |
| | 49 | % | | 2015 | | 2020 | | Electra Noreste/Edemet/Edechi/Other | |
| Penonome I | | Penonome I | | Panama | | Wind | | 55 | | | 49 | % | | 2020 | | 2023 | | Altenergy |
| Chiriqui-Los Valles | | Panama | | Hydro | | 54 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | Chiriqui-Los Valles | | Panama | | Hydro | | 54 | | | 49 | % | | 1999 | | 2030 | | ENSA, Edemet, Edechi, Other |
| Chiriqui-La Estrella | | Panama | | Hydro | | 48 |
| | 49 | % | | 1999 | | 2030 | | Electra Noreste/Edemet/Edechi/Other | Chiriqui-La Estrella | | Panama | | Hydro | | 48 | | | 49 | % | | 1999 | | 2030 | | ENSA, Edemet, Edechi, Other |
| Panama Subtotal | | 1,158 |
| | | | Panama Subtotal | | 1,141 | | |
| | | 3,205 |
| | | | |
| | | | 3,459 | | |
_____________________________
| |
(1)(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. | Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine). |
| |
(2)
| Plant also includes an adjacent regasification facility, as well as a 180,000 m3 LNG storage tank, which is expected to come on-line in 2019.
|
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) | | | | | | 57 | | | | | |
| 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 | | | | | |
| | | | | | 78 | | | | | |
_____________________________
(1)A second 50 TBTU LNG storage tank is under construction and expected to come on-line in the first half of 2023.
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
| Mesa La Paz | | Mexico | | Wind | | 306 |
| | 50 | % | | 1H 2020 |
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.
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 avoidprevent monopolistic practices.
In addition to the two agencies responsible for monitoring compliance with the General Electricity Law, the IndustrialMinistry of Industry and Commerce Ministry supervises commercial and industrial activities in the Dominican Republic as well as the fuels and natural gas commercialization to the end users.
The Dominican Republic has one main interconnected system with approximately 3,8004,921 MW of installed capacity, composed primarily of thermal (78%(75%), hydroelectric (16%(13%), wind (4%(8%), and solar (2%(4%) generation plants/farms..
Development Strategy — AES will continue to develop the commercialization of natural gas and incorporate partners directly in gas infrastructure projects. AES partnered with Energas in a joint venture which has been operating the 50 km Eastern Pipeline since February 2020. The joint venture is also developing a new LNG facility of 120,000 cubic meters, including additional storage, regasification, and truck loading capacity, for which construction is scheduled to start in 2021. This will allow AES to reach new customers who have converted, or are in the process of converting, to natural gas as a fuel source, and better operational flexibility.
Business Description — AES Dominicana consists of three operating subsidiaries, Itabo, Andres and Los Mina. With a total of 992 MW of installed capacity, AES has 26% of the system capacity and supplies approximately 40% of energy demand via these generation facilities. 821 MW is mostly 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 twofive 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 power generation unitssince 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 of 295 MW of installed capacity.
Andres and Los Mina are owned 85% by AES. Andres has a combined cycle natural gas turbine, an energy storage solution and generationcontracted capacity of 329 MW as well as the only LNG import facility383 MW. Our thermal asset in the country,Panama has PPAs with 160,000 cubic meters of storage capacity. Los Mina hasdistribution companies for a combined cycle with two natural gas turbines, an energy storage solution and generationtotal contracted 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 markets350 MW expiring 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 re-gasified 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.August 2028.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•changes in spothydrology, which impacts commodity prices dueand exposes the business to variability in the cost of replacement power;
•fluctuations in commodity prices, (since fuel is a pass-throughmainly oil and natural gas, which affect the cost underof thermal generation and spot prices;
•constraints imposed by the PPAs, any variation in oil prices will impactcapacity of transmission lines connecting the spot sales for both Andreswest side of the country with the load, keeping surplus power trapped during the rainy season; and Itabo);
contracting levels and the extent of capacity awarded;
supply shortages in the near term (next two to three years) may provide opportunities for short term upside, but new generation•country demand as GDP growth is expected to come online beginning 2019;remain strong over the short and
additional sales derived from domestic natural gas demand are expected to continue providing income and growth based on the entry of future projects and the fees from the infrastructure service.
Panama 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 the PPA market,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 SNENational Secretary of Energy in Panama (SNE) has the responsibilities of planning, supervising, and controlling policies of the energy sector within Panama. With these responsibilities, theThe 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 3,5013,854 MW, composed primarily of hydroelectric (49%(47%), thermal (41%), wind (7%), and thermal (40%solar (5%) generation.
Business DescriptionDevelopment Strategy — AES owns and operates five hydroelectric plants and two thermoelectric power plants, Estrella del Mar I and Colon, representing 705 MW and 453 MW of hydro and thermal capacity, respectively and 33% of the total installedGiven our LNG facility’s excess capacity in Panama.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.
The majority of hydroelectric plantsIn addition to investing in Panama are based on run-of-river technology, withLNG infrastructure, AES is investing in renewable projects within the exception of the 260 MW Bayano plant. Hydrological conditions have an important influence on profitability. Variations in hydrology
can result in excess or a shortfall in energy production relative to our contract obligations. Hydro generation is generally in a shortfall position during the dry season from January through May, while thermal assets are expected to be in a long position as their behavior is opposite and complimentary to hydro generation.
Both hydro and thermal assets are mainly contracted through medium- to long-term PPAs with distribution companies. A small volume of contracts are with unregulated users.
Hydroregion. This will increase complementary non-hydro renewable assets in Panama have PPAs with distribution companies up to December 2030 for a total contracted capacity of 350 MW. Thermal assets in Panama have PPAs with distribution companies for a total contracted capacity of 430 MW, of which 80 MW will expire in June 2020the system and 350 MW will expire in December 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, affect the cost of thermal generation and spot prices;
constraints imposed by the capacity of the transmission lines connecting the west side of the country with the load, keeping surplus power trapped during the wet season; and
country demand as GDP growth is expected to remain strong over the short and medium term.
Construction and Development — In August 2015, AES executed a partnership agreement with Deeplight Corporation, a minority partner, to construct, operate, and maintain a natural gas power generation plant and a liquefied natural gas terminal, in order to purchase and sell energy and capacity as well as commercialize natural gas and other ancillary activities related to natural gas. The combined cycle natural gas power generation plant initiated operations in September 2018 and the liquefied natural gas storage and regasification facility is scheduled for completion in the second half of 2019.
Mexico
Regulatory Framework and Market Structure — Mexico has a single electric grid, the National Electricity System, covering all of Mexico's territory through the Interconnected National Electricity, Baja California and Southern Baja California Systems. The market comprises generation, transmission, distribution and commercialization segments.
Three main agencies, in additioncontribute to the Ministryreduction of Energy, are responsible for monitoring compliance with the Electric Industry Law:
The Energy Regulatory Commission is responsible for the establishment of directives, orders, methodologies and standards oriented to regulate the electric and fuel markets.
The National Center for Energy Control, as new ISO, is responsible for managing the wholesale electricity market, transmission and distribution infrastructure, planning the network developments, guaranteeing open access to network infrastructure, executing competitive mechanisms to cover regulated demand, and setting transmission charges.
The CFE owns the transmission and distribution grids and it 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.hydrological risk in Panama.
Mexico has an installed capacity totaling 74 GW with a generation mix primarily comprising of thermal (71%) and hydroelectric (17%) plants.
Business Description — AES has 1,0551,361 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 in Merida, 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.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
as•fully contracting the companies, are fully contracted,providing additional benefits from improved operational performance, provides additional benefits, 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 CFE.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.
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 with Grupo BAL to co-invest in power and related infrastructure projects in Mexico, focusing on renewable and natural gas generation.
The first development, a 306 MW wind project, began construction in 2018 and is expected to be completed in 2020.
Eurasia SBU
Generation — Our Eurasia SBU has generation facilities in six countries. Operatingfive countries with total operating installed capacity totaled 4,578of 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) | 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 | | Natsionalna Elektricheska | Maritza | | Bulgaria | | Coal | | 690 | | | 100 | % | | 2011 | | 2026 | | NEK |
| St. Nikola | | Bulgaria | | Wind | | 156 |
| | 89 | % | | 2010 | | 2025 | | Natsionalna Elektricheska | St. Nikola | | Bulgaria | | Wind | | 156 | | | 89 | % | | 2010 | | 2025 | | Electricity Security Fund |
| Bulgaria Subtotal | | 846 |
| | | | Bulgaria Subtotal | | 846 | | |
OPGC (1) | | India | | Coal | | 420 |
| | 49 | % | | 1998 | | 2026 | | GRID Corporation Ltd. | |
| Delhi ES | | India | | Energy Storage | | 10 |
| | 60 | % | | 2019 | | Delhi ES | | India | | Energy Storage | | 10 | | | 60 | % | | 2019 | |
| India Subtotal | | 430 |
| | | | India Subtotal | | 10 | | |
| Amman East | | Jordan | | Gas | | 381 |
| | 37 | % | | 2009 | | 2033 | | National Electric Power Company | |
| IPP4 | | Jordan | | Heavy Fuel Oil | | 250 |
| | 36 | % | | 2014 | | 2039 | | National Electric Power Company | |
Amman East (1) | | Amman East (1) | | Jordan | | Gas | | 381 | | | 37 | % | | 2009 | | 2033 | | National Electric Power Company |
IPP4 (1) | | IPP4 (1) | | Jordan | | Heavy Fuel Oil | | 250 | | | 36 | % | | 2014 | | 2039 | | National Electric Power Company |
| AM Solar | | AM Solar | | Jordan | | Solar | | 52 | | | 36 | % | | 2019 | | 2039 | | National Electric Power Company |
| Jordan Subtotal | | 631 |
| | | | Jordan Subtotal | | 683 | | |
| Netherlands ES | | Netherlands | | Energy Storage | | 10 |
| | 100 | % | | 2015 | | Netherlands ES | | Netherlands | | Energy Storage | | 10 | | | 100 | % | | 2015 | |
| Netherlands Subtotal | | 10 |
| | | | Netherlands Subtotal | | 10 | | |
Ballylumford (2) | | United Kingdom | | Gas | | 708 |
| | 100 | % | | 2010 | | 2023 | | Power NI/I-SEM | |
Kilroot (3) | | United Kingdom | | Coal/Oil | | 701 |
| | 99 | % | | 1992 | | I-SEM | |
| Kilroot ES | | United Kingdom | | Energy Storage | | 10 |
| | 100 | % | | 2015 | | |
| United Kingdom Subtotal | | 1,419 |
| | | | |
| Mong Duong 2 | | Vietnam | | Coal | | 1,242 |
| | 51 | % | | 2015 | | 2040 | | EVN | |
Mong Duong 2 (2) | | Mong Duong 2 (2) | | Vietnam | | Coal | | 1,242 | | | 51 | % | | 2015 | | 2040 | | EVN |
| Vietnam Subtotal | | 1,242 |
| | | | Vietnam Subtotal | | 1,242 | | |
| | | 4,578 |
| | | | | 2,791 | | |
_____________________________
| |
(1)
| Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates. |
| |
(2)
| The Ballylumford B Station began the process for a safe shutdown in December 2018. |
| |
(3)
| Includes Kilroot Open Cycle Gas Turbine. |
Under construction (1)— The following table listsEntered into an agreement to sell 26% interest in these businesses in November 2020.
(2)Entered into an agreement to sell our plants under constructionentire interest in the Eurasia SBU:Mong Duong 2 plant in December 2020.
|
| | | | | | | | | | | | |
| Business | | Location | | Fuel | | Gross MW | | AES Equity Interest | | Expected Date of Commercial Operations |
OPGC 2 (1) | | India | | Coal | | 1,320 |
| | 49 | % | | 1H 2019 |
| AM Solar | | Jordan | | Solar | | 52 |
| | 36 | % | | 2H 2019 |
| | | | | | | 1,372 |
| | | |
_____________________________
| |
(1)
| Unconsolidated entity, accounted for as an equity affiliate. |
In March 2018,December 2020, the Company completed the sale of its entire 51% ownership interest in Masinloc, a 630 MW coal-fired plant located in the Philippines. Prior to its sale, Masinloc was accounted for as a consolidated entity and its results were included in our operations as we had a controlling49% equity interest in the business.OPGC coal-fired generation facilities in India.
The following map illustrates the location of our Eurasia facilities:
Eurasia Businesses
Bulgaria
Regulatory Framework and Market Structure — The electricity sector in Bulgaria allows both regulated and competitive segments. NEK, the state-owned electricity public supplier and energy trading company, 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 a model that will allow the 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 in neighboring countries. In addition, it plays an important role in the energy balance in the Balkan region.
Bulgaria has 12 GW of installed capacity enabling the country to meet and exceed domestic demand and export energy. Installed capacity is 37% coal-fired and 17% nuclear.
Business Description — Our Maritza plant is a 690 MW lignite fuel thermal power plant. Maritza's entire power output is contracted with NEK under a 15-year PPA, expiring in May 2026. Since the renegotiation of the PPA in April 2016, Maritza has been collecting receivables from NEK in a timely manner. However, NEK's liquidity position remains subject to political conditions and regulatory changes in Bulgaria.
The DG Comp is reviewing NEK’s PPA with Maritza pursuant to the European Commission’s state aid rules. Maritza believes that its PPA is legal and in compliance with all applicable laws. See Item 7. —Management's
Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Regulatory.
AES also owns an 89% economic interest in the St. Nikola wind farm with 156 MW of installed capacity. Through December 31, 2018, the entire power output of the St. Nikola wind farm was contracted under a 15-year PPA with NEK. Starting January 1, 2019, the power output of St. Nikola is sold on the Independent Bulgarian Electricity Exchange and the plant receives additional revenue per the terms of an October 2018 Contract for Premium with the state-owned Electricity Security Fund.
Environmental Regulation — Best Available Techniques Reference Document for Large Combustion Plants (BREF LCP), the new EU environmental standards regulating emissions from the combustion of solid fuels for large combustion plants, was enacted in August 2017 and applies to Maritza. Impacted power plants are required to either meet the new standards or be granted a derogation by August 2021. Maritza requested such derogation from the Bulgarian environmental authorities in 2018, and expects to receive a response in 2019. If derogation is not received Maritza would seek to pass through the compliance costs to the off-taker pursuant to the PPA.
Key Financial Drivers —Financial results are driven by many factors, including, but not limited to:
regulatory changes to the Bulgaria power market;
results of the DG Comp review;
the availability 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.
United Kingdom
Regulatory Framework and Market Structure — AES UK operates in the Integrated Single Electricity Market ("I-SEM") in Northern Ireland. The I-SEM is the wholesale electricity market arrangement operating in the Republic of Ireland and Northern Ireland starting October 1, 2018, replacing the previously existing SEM. The I-SEM market arrangements are designed to integrate the Irish All Island electricity market with European electricity markets enabling the free flow of energy across borders, creating increased levels of competition and increased security of supply.
The Single Electricity Market Operator facilitates the continuous operation and administration of the I-SEM. The organization is managed as a contractual joint venture between EirGrid, the transmission system operator for the Republic of Ireland, and the System Operator for Northern Ireland. The Single Electricity Market Operator is licensed and regulated cooperatively by the Commission for Energy Regulation in the Republic of Ireland and the Northern Ireland Authority for Utility Regulation.
In addition, the I-SEM has a competitive capacity payment mechanism to ensure that sufficient generating capacity is offered to the market. The first competitive capacity auction for the capacity year May 2018 to September 2019 was completed in January 2018. The second capacity auction for the capacity year October 2019 to September 2020 was completed on February 1, 2019.
Since the introduction of I-SEM in October 2018, new instruments such as day-ahead, intra-day and balancing markets were introduced to reflect integration with EU energy markets. The system support services market was also reformed in May 2018 through the introduction of DS3, a competitive services market where participants are required to complete a separate qualification process.
Northern Ireland's power sector is supported by a diverse generation mix, a stable regulatory environment, universal access to the grid, and connections between the Republic of Ireland, Northern Ireland and the remainder of the UK. Installed capacity in the I-SEM is 41% gas fired and 38% from renewable sources, resulting in sensitivity to gas prices relative to order of merit. I-SEM has also set a target of 40% renewable generation by 2020.
Business Description — AES has two generation plants in the UK, Kilroot and Ballylumford, both of which are located in Northern Ireland within the Greater Belfast region.
Kilroot is a 701 MW coal-fired merchant plant, with an additional 10 MW of energy storage, that bids into the I-SEM. Kilroot's coal fired units failed to clear in the first I-SEM capacity auction process finalized in January 2018. Consequently, AES announced its intent to shut down the coal units, pending the results of an assessment by the
regulator to determine the long term needs of the Northern Ireland power grid. In November 2018, Kilroot's Unit 1 was awarded the 12 month System Support Service Agreement for the period October 2018 to September 2019. In addition, the Company also decided to transfer the capacity contract awarded to Ballylumford Unit 4 to Kilroot Unit 2. As a result, the decision to shut down both Kilroot coal units was reversed.
Ballylumford is a 708 MW gas-fired plant, of which 592 MW is contracted under a PPA with Power NI Power Procurement Business expiring in 2023. The 116 MW remaining capacity is bid into the I-SEM market. Ballylumford's B station Unit 5 failed to clear the aforementioned I-SEM capacity auction while Unit 4’s capacity contract was transferred to Kilroot. As a result, AES stopped generation at Ballylumford's B station in late 2018, and ongoing work to safely shut down the station is expected to be completed in early 2019.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
regulatory changes to the market structure and payment mechanisms;
investments to maintain compliance with EU environmental legislation;
weather conditions impacting availability of growing renewables generation;
availability of the operating units and trading strategy;
commodity and FX prices (gas, coal, CO2) and sufficient market liquidity to hedge prices in the short-term; and
electricity demand in the I-SEM (including impact of wind generation).
Jordan
Regulatory Framework and Market Structure — The Jordan electricity transmission market is a single-buyer model with the state owned NEPCO responsible for transmission. NEPCO generally enters into long-term power purchase agreements with IPP's to fulfill energy procurement requests from distribution utilities. The sector is prioritizing renewable energy development, with 2,200 MW of renewable energy installed capacity expected by 2020, 940 MW of which is already connected to the grid.
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, and a 36% controlling interest in the IPP4 plant, a 250 MW oil/gas-fired peaker plant, fully contracted with the national utility until 2039. We consolidate the results in our operations as we have controlling interest in these businesses.
Construction and Development —AES, in conjunction with Mitsui & Co of Japan and NEBRAS Power of Qatar, have signed an agreement to construct a 52 MW solar project in Jordan. The plant is currently under construction, and is expected to be completed by mid 2019 to coincide with the start of a PPA to provide energy to NEPCO through 2038.
India
Regulatory Framework and Market Structure — The power sector is comprised of state and central government-owned and privately-owned generation and distribution utilities. Electricity is sold to state utilities mostly under long-term PPAs and about 10% of electricity is sold in the short-term market, for example, traded on an energy exchange or through competitively bid bilateral contracts. The tariffs are fixed on yearly basis by the Electricity Regulatory Commissions Central / State(s) for the long-term PPAs or determined through a competitive bidding process. OERC regulates the electricity purchase process for the distribution licensees, including the price at which the electricity from generating companies shall be procured for supply within the state of Orissa. OERC also facilitates intrastate transmission and wheeling of electricity. The electricity regulatory commissions are guided by the Electricity Act, National Electricity Policy, National Electricity Plan and Tariff Policy issued by the Government of India.
The power sector in India is composed of coal, gas, hydroelectric, renewable and nuclear energy. Total installed capacity as of December 31, 2018 was 349 GW, of which 64% is thermal generation. Renewable energy is adding capacity at a rapid pace and currently represents 21% of the total installed capacity. The remaining capacity is nuclear (2%) and hydro (13%).
Business Description — OPGC is a 420 MW coal-fired generation facility located in the state of Odisha. OPGC has a 30-year PPA with GRIDCO Limited, a state utility, expiring in 2026. OPGC is an unconsolidated entity and results are reported as Net equity in earnings of affiliates on our Consolidated Statements of Operations.
Construction and Development — AES has one 1,320 MW coal-fired project under construction, which is expected to begin operations in the first half of 2019. As of December 31, 2018, total capitalized costs at the project level were $1.3 billion. Once becoming operational, 75% of the expansion installed capacity is contracted with GRIDCO for a period of four years through 2023 and 100% for the next 25 years through 2048. A separate trading agreement is being negotiated for the remaining 25% of capacity to be sold in the trading market by GRIDCO on behalf of OPGC during the first four years following commencement of operations.
Environmental Regulation — The Ministry of Environment, Forest and Climate Change in India amended the Environment (Protection) Rules with stricter emission limits for thermal power plants through their notification issued in December 2015. All existing plants installed before December 31, 2003 are required to meet revised emission limits within two years and any new thermal power plants that will be operational from January 1, 2017 onwards are required to operate within the revised emission limits. As a result of this amendment, Selective Catalytic Rectifier and Flue Gas Desulphurisation systems are to be installed in the existing OPGC units to comply with the new NOX and SO2 emissions limits. The hardware to be installed to meet the tightened emission requirements will require substantial investment by OPGC. We believe the cost of complying with the new environmental regulations for particulate matters, water consumption, SOx and NOx limits will be a pass-through in the OERC prescribed tariff regulations for both the existing and expansion units.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
operating performance of the facility;
regulatory and environmental policy changes;
tariff determination by the OERC; and
PPA provisions and energy trading.
Vietnam
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 Petro Vietnam.
The Vietnam power market is divided into three regions (North, Central and South), with total installed capacity of approximately 47 GW. The fuel mix in Vietnam is composed primarily of hydropower at 42% and coal at 37%. EVN, the national utility, owns 60% 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. A competitive electricity market has already been established. A pilot competitive wholesale electricity market has been developed, and will be implemented over the next five years. The retail market will undergo similar reforms after 2022. BOT power plants will not directly participate in the power market; however, their dispatch will be impacted by the merit order
Business Description — Mong Duong II2 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
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.
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
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.
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.
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, PM,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 our business and results of operations 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
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, PM,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, Oklahoma 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 NOxX ozone season emissions in 22 states (including Indiana, Maryland, Ohio and Oklahoma)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 NOxX ozone season emission budgets for electric generating units within these states and implemented these budgets through modifications to the CSAPR NOxX ozone season allowance trading program. Implementation started in the 2017 ozone season (May-September 2017). Affected facilities began to receive fewer ozone season NOxX 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 2017 and 2018additional CSAPR compliance costs wereto 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 RMRRroutine 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 aan NOV issued by the EPA against IPL concerning NSR and prevention of significant deterioration issues under the CAA.
If NSR requirements wereare 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.
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 BARTthe 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 beginsbegan 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.
National Ambient Air Quality Standards ("NAAQS")NAAQS — Under the CAA, the EPA sets NAAQS for six principal pollutants considered harmful to public health and the environment, including ozone, particulate matter, NOxX, 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, NOxX, 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 FGDflue 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 15, 2018,17, 2020, the EPA proposed to approve Indiana’sapproved the reduced SO2 limits as part of a revised Indiana State Implementation Plan addressingconcluding that Indiana has appropriately demonstrated that the plan provides for attainment of the 2010 SO2 standard for certain locations including those of IPL's Petersburg Generating Stations.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 Systembest system of Emissions Reductionemissions 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.NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal.
On December 22, 2015, the EPA finalized CO2 emission rules for existing power plants under Clean Air Act Section 111(d) (called the CPP). The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved starting in 2030. The full impact of the CPP would depend on the following:
whether and how the states in which the Company's U.S. businesses operate respond Challenges to the CPP;GHG NSPS
whether the states adopt an emissions trading regime and, if so, which trading regime;
how other states respond to the CPP, which will affect the size and robustness of any emissions trading market; and
how other companies may respond in the face of increased carbon costs.Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit. Pursuant to a court order issued in August 2017, the litigation is being held in indefinite abeyance pending further court order.
In addition, on February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP pending resolution of challenges to the rule. Challenges to both the CPP and the GHG NSPS are being held in abeyance at this time. On October 16, 2017, the EPA published in the Federal Register a proposed rule that would rescind the CPP. On December 28, 2017, the EPA published an Advance Notice of Proposed Rulemaking to solicit comments as EPA considers a potential rule to establish emission guidelines to replace the CPP and limit GHG emissions from existing electric generating units under Section 111(d) of the CAA.
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. In addition,On July 8, 2019, the EPA proposedpublished the final ACE Rule along with associated revisions to implementing regulations and the New Source Review program.regulations. The proposedfinal ACE Rule would replaceestablished CO2 emission rules for existing power plants under CAA Section 111(d) and replaced the EPA’sEPA's 2015 Clean Power Plan and proposes to determineRule (CPP). In accordance with the ACE Rule, the EPA determined that heat rate improvement measures are the best system of emission reductionemissions 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 the CPP or potential replacement rule,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 CPP,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 BTAbest technology available ("BTA") for cooling water intake structures. On August 15, 2014, the EPA published its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants. These standardsbased on CWA Section 316(b) which require certain subject facilities to choose among seven BTA options to reduce fish impingement. In addition, certain facilities that withdraw at least 125 million gallons per day for cooling purposes must conduct studies to assist permitting authorities to determine whichwhether and what site-specific controls, if any, are required to reduce entrainment.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 recent 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 December 31, 2020, the compliance datedates 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 power purchase agreementsPPAs to support project financing of the replacement generating units at AES Alamitos and AES Huntington Beach. The SWRCB is currently reviewingreviews the implementation plan and latest information on OTC generating unit retirement dates and
new generation availability to evaluate the impact on electrical system reliability which could result in the extension ofand OTC compliance dates for specific units.
The Company’s California subsidiaries have signed 20-year term power purchase agreementsPPAs 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. ConstructionThe new air-cooled combined cycle gas turbine generators were constructed at both sites is on schedulethe AES Alamitos and will require the following existingAES Huntington Beach generating stations. Certain OTC units were required to retire earlier than December 31, 2020be retired in 2019 to provide interconnection capacity and/or emissions credits prior to startup of the new generating units:
Redondo Beach Unit 7 - September 30, 2019
Huntington Beach Unit 1 - December 31, 2019
Alamitos Units 1, 2,units, and 6 - December 31, 2019
Thethe 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 United States.U.S. This rule, which initially became effective on August 28, 2015, maycould expand or otherwise change the number and types of waters or features subject to federal permitting. On June 27, 2017,However, the EPA proposedagencies engaged in a rule that would rescindtwo-step process to repeal the “Waters2015 "Waters of the United States”U.S." rule and re-codifyreplace it with a newly promulgated rule called the definition of “Waters of"Navigable Waters Protection" rule. The agencies completed the United States” that existed prior tofirst step on October 22, 2019 by publishing the 2015 rule. However, on February 6, 2018, the EPA published a final rule to delay the original effective date ofrepealing the 2015 “Waters of the United States” to February 6, 2020, which allows the EPA to create a new rule in the interim period without the 2015 rule taking effect. On June 29, 2018,U.S.” rule. In step two, the agencies signedissued a supplemental noticerevised definition of proposed rulemaking clarifying that the proposal is to permanently repeal the 2015 Rule. We cannot predict the outcomewaters of the judicial challenges to the rule or the regulatory process to rescind the rule, but if the “Waters of the United Sates” rule is ultimately implemented in its current or substantially similar form and survives legal challenges, it could have a material impactU.S. on our business, financial condition or results of operations. On February 14, 2019, the agencies published a proposed rule to revise the definition of the “Waters of the United States.” We are reviewing the December 11, 2018 proposedand released the prepublication version of the final "Navigable Waters Protection" rule and iton April 21, 2020. It is too early to determine whether this mightthe 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 National Pollutant Discharge Elimination SystemNPDES permits that regulate specific industrial waste water and storm water discharges to the waters of the United StatesU.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.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 de-sulfurizationdesulfurization wastewater. The required compliance time linestimelines 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 described below and wastewater treatment systems in response to the NPDES permits described above in advance of the ELG compliance date. As a resultOther 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
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 retire Stuart and Killen generating stations, we do not expect the ELG rule tomight have a material impact on these two stations. While weour 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 still evaluatingconveyed to navigable waters through a nonpoint source, such as groundwater. The Court held that discharges to groundwater require a permit if the effectsaddition of the rule on our other U.S. businesses, we anticipate
thatpollutants through groundwater is the implementationfunctional equivalent of its current requirements coulda 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 adverse effectimpact on our business, financial condition, or results of operations, financial condition and cash flows, and a postponement or reconsideration of the rule that leads to less stringent requirements would likely offset some or all of the adverse effects of the rule.operations.
Selenium Rule — In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant Seleniumselenium in fresh water. NPDES permits may be updated to include Seleniumselenium water quality basedquality-based effluent limits based on a site-specific evaluation process, which includes determining if there is a reasonable potential to exceed the revised final Seleniumselenium 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 — In the course of operations, the Company's facilities generate solid and liquid waste materials requiring eventual disposal or processing. With the exception of coal combustion residuals ("CCR"), the wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCR, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities may include asbestos, CCR, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl contaminated liquids and solids. The Company endeavors to ensure that all of its solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. 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. It is too earlyOn 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 determine whetherforced 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 the groundwater monitoring data, or the outcome of CCRCCR-related litigation or a potential CCR Remand Rule maycould have a material impact on our business, financial condition, orand results of operations. IPL would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard.
The existing ash ponds atOn January 2, 2020, Puerto Rico Senate Bill 1221 was signed by the Petersburg Station did not meet certain structural stability requirements set forthPuerto 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 CCR rule.Puerto Rico Department of Natural and Environmental Resources to develop implementation regulations. As such, the Company was ultimately requiredit is not yet possible to cease usedetermine whether this might have a material impact on our business, financial condition, and results of all ash ponds at Petersburg by November 11, 2018.operations.
Comprehensive Environmental Response, Compensation and Liability Act of 1980 — This act, also knowknown 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 potentially responsible partyPRP 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,
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 twothree 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—Our Organization and SegmentsBusiness, above.under the applicable SBUs. Customers
We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 20182020 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:
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* 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
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.
Executive Officers
The following individuals are our executive officers:
Sanjeev Addala, 53 years old, was appointed Chief Information and Digital officer in October 2018. Prior to joining AES, Mr. Addala was Chief Digital Officer at GE from 2016 to September 2018, Chief Digital Officer at Caterpillar from 2013 to 2015, and Chief Information Officer, Americas, Climate Control Technologies at Ingersoll-Rand from 2008 to 2013. He also previously held business and technology leadership roles at General Motors from 1994 to 2008. He served on Energize Ventures and AppLariat advisory Boards. Mr. Addala is a member of the Board of AES Distributed Energy. Mr. Addala holds a Master of Science degree in Mechanical Engineering from South Dakota School of Mines and Tech. and a Master of Business Administration degree from the Kellogg School of Management at Northwestern University. Mr. Addala has also completed an Executive Leadership program at Duke University.
Bernerd Da Santos, 5557 years old, has beenserved as Executive Vice President and Chief Operating Officer and Executive Vice President since December 2017. Previously, Mr. Da Santos held several positions at the Company,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 the chairman of AES Gener in Chile and a member of the Boardboards 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, and Indianapolis Power & Light.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.
Manuel Pérez DubucPaul L. Freedman, 5550 years old, has served as SeniorExecutive Vice President, Global New Energy Solutions since October 2018. Previously Mr. Pérez Dubuc served as the President of the South America SBU from March 2018 to October 2018 and President of the MCAC SBU from November 2012 to March 2018. He also served as Vice President and General Manager AES North Asia, President of AES Dominicana and Chief Financial Officer of EDC. Mr. Pérez Dubuc is a member of the Boards of SPower, AES Gener, AES Tiete, Fluence and EnerAB, Ron Santa Teresa SACA and GFR Group Advisory board. Prior to joining AES, Mr. Pérez Dubuc served as a Chairman and CEO of Meiya Power Company based in Hong Kong. Mr. Pérez Dubuc studied electrical engineering at the Universidad Simon Bolivar and with a master’s degree in business administration from IESA (Instituto de Estudios Superiores de Administración) of Caracas, Venezuela. He attended the Executive Leadership Program at the University of Virginia’s Darden School of Business and the Global Executive Leadership Program at Georgetown University’s McDonough School of Business in 2015.
Paul L. Freedman, 48 years old, has been Senior Vice President and General Counsel and Corporate Secretary since February 2018 and was appointed Corporate Secretary in October 2018.2021. Prior to assuming his current position, Mr. Freedman served aswas 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, Fluence and the Business Council for International Understanding.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 LLP and Freshfields. Mr. Freedman received a B.A. from Columbia University and a J.D. from the Georgetown University Law Center.
Andrés R. Gluski, 6163 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 DepartmentsDepartments 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 AES Gener in Chile.Fluence. Mr. Gluski is also Chairman of the Americas Society/Council of the Americas, and Director of the Edison Electric Institute.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 thethe University of Virginia.
Lisa Krueger, 5557 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 sincefrom 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
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 a Master of Business Administration degreean MBA from the Jones Graduate School of Business at Rice University.
Tish Mendoza, 4345 years old, ishas served as Executive Vice President and Chief Human Resources Officer andsince February 2021. Prior to assuming her current position, Ms. Mendoza was Senior Vice President, Global Human Resources and Internal Communications since 2015. Prior to assuming her current position, Ms. Mendoza was theand 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,Compensation, from 2008 to 2011, and acted in the same capacity as the Director of the function from 2006 to 2008. In 2015, Ms. Mendoza was appointedis a member of the Boardsboards of AES Chivor S.A., DP&L, AES Distributed Energy, and DP&L,Uplight and sits on AES' compensation and benefits committees. She is also currently serving as co-chair of Evanta Global HR, and is part of its governing body in Washington, D.C. 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 CompensationCompensation 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.
Leonardo MorenoGustavo Pimenta, , 3942 years old, has served as Senior Vice President, Corporate Strategy and Investments and Chief Risk Officer since May 2017. Previously Mr. Moreno served as the Chief Financial Officer, Europe SBU from May 2015 to April 2017 and as a Managing Director on AES’ Mergers & Acquisitions team from January 2012 to April 2015. Since joining AES in 2006, Mr. Moreno has served in various positions throughout the Company. Mr. Moreno serves as a member of the Board of DP&L and AES Tiete. Prior to joining AES Mr. Moreno worked for Ernst & Young. Mr. Moreno has a degree in Business Administration from Universidade Federal de Minas Gerais, Brazil and has completed executive business and leadership programs at the London Business School, Georgetown University and the University of Virginia.
Julian Nebreda, 52 years old, has served as Senior Vice President and President of the South America SBU since October 2018. Prior to assuming his current position Mr. Nebreda served as the President of the AES Brazil SBU from April 2016 to October 2018, and President of the Europe SBU from June 2009 to April 2016. Prior to June 2009, Mr. Nebreda held several senior positions, such as Vice President for Central America and Caribbean, Chief Executive Officer of EDC and President of AES Dominicana, in Santo Domingo, Dominican Republic. Mr. Nebreda serves as Chairman of the Board of AES Gener and AES Tiete. Before joining AES, Mr. Nebreda has held positions in the public and private sectors, namely he served as Counsellor to the Executive Director from Panama and Venezuela at the Inter-American Development Bank. Mr. Nebreda earned a law degree from Universidad Católica Andrés Bello in Caracas, Venezuela. He also earned a Master of Laws in Common Law with a Fulbright Fellowship and a Master of Laws in Securities and Financial Regulations, both from Georgetown University.
Gustavo Pimenta, 40 years old, was appointed Executive Vice President and Chief Financial Officer effectivesince January 1, 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 Company’s 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.
Juan Ignacio Rubiolo, 42 years old, has served Senior Vice President and President of the MCAC SBU since March 2018. Previously Mr. Rubiolo served as the Chief Executive Officer of AES Mexico from 2014 to March 2018 and as a Vice President on the Commercial team of the MCAC SBU from 2013 to 2014. Mr. Rubiolo joined AES in 2001 and has worked in AES businesses in the Philippines, Argentina, Mexico, Panama and the Dominican Republic. Mr. Rubiolo serves on the Boards of AES Gener, Itabo, AES Andres, and AES Panama. Mr. Rubiolo has a Science Degree in Business from the Universidad Austral of Argentina, a Master of Project Management from the Quebec University in Canada and has completed the executive business and leadership program at the University of Virginia.
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 8, 2018.4, 2020.
Our Code of Business Conduct ("Code of Conduct") and Corporate Governance Guidelines have been adopted by our Board of Directors. The Code of Conduct is intended to govern, as a requirement of employment, the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. Our Ethics and Compliance Department provides training, information, and certification programs for AES employees related to the Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering and associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to, or waivers from, the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.
ITEM 1A. RISK FACTORS
You should consider carefully the following risks, along with the other information contained in or incorporated by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations, including those discussed in Item 7
.—Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. If any of the following events actually occur, our business, financial results and financial condition could be materially adversely affected.
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 of this Form 10-K include the following: risks related toassociated with our operations, governmental regulation and laws, our indebtedness and financial condition;
external risks associated with revenue and earnings volatility;
risks associated with our operations; and
risks associated with governmental regulation and laws.
Risks Related to our Indebtedness and Financial Condition
We have a significant amount of debt, a large percentage of which is secured, that could adversely affect our business and our ability to fulfill our obligations.
As of December 31, 2018, we had approximately $19 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings, if any, under The AES Corporation's senior secured credit facility and secured term loan are secured by certain of our assets, including the pledge of capital stock of many of The AES Corporation's directly held subsidiaries. Most of the debt of The AES Corporation's subsidiaries is secured by substantially all of the assets of those subsidiaries. Since we have such a high level of debt, a substantial portion of cash flow from operations must be used to make payments on this debt. Furthermore, since a significant percentage of our assets are used to secure this debt, this reduces the amount of collateral available for future secured debt or credit support and reduces our flexibility in operating these secured assets. This high level of indebtedness and related security could have other important consequences to us and our investors, including:
making it more difficult to satisfy debt service and other obligations at the holding company and/or individual subsidiaries;
increasing our vulnerability to general adverse industry and economic conditions, including but not limited to adverse changes in foreign exchange rates, interest rates and commodity prices;
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 the financial and other restrictive covenants relating to such indebtedness, among other things, our ability to borrow additional funds as needed or take advantage of business opportunities as they arise, pay cash dividends or repurchase common stock.
The agreements governing our indebtedness, including the indebtedness of our subsidiaries, limit, but do not prohibit the incurrence of additional indebtedness. If we were to become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flows may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets, raise equity or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. In addition, our ability to refinance existing or future indebtedness will depend on the capital markets and our financial condition at such time. Any refinancing of our debt could come at higher interest rates or may require us to comply with onerous covenants, which could restrict our business operations. See Note 10.—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for a schedule of our debt maturities.The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.
The AES Corporation is a holding company with no material assets other than the stock of its subsidiaries. Almost all of The AES Corporation's cash flow is generated by the operating activities of its subsidiaries. Therefore, The AES Corporation's ability to make payments on its indebtedness and to fund its other obligations is dependent not only on the ability of its subsidiaries to generate cash, but also on the ability of the subsidiaries to distribute cash to it in the form of dividends, fees, interest, tax sharing payments, loans or otherwise.
However, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation. Most of the subsidiaries are obligated, pursuant to loan agreements, indentures or non-recourse financing arrangements, to satisfy certain restricted payment covenants or other conditions before they may make distributions to The AES Corporation. Business performance and local accounting and tax rules may also limit dividend distributions. Subsidiaries in foreign countries may also be prevented from distributing funds to The AES Corporation as a result of foreign governments restricting the repatriation of funds or the conversion of currencies.
The AES Corporation's subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of The AES Corporation's indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other payments.
Existing and potential future defaults by subsidiaries or affiliates could adversely affect The AES Corporation.
We attempt to finance our domestic and foreign projects primarily under loan agreements and related documents that, except as noted below, require the loans to be repaid solely from the project's revenues and provide that the repayment of the loans (and interest thereon) is secured solely by the capital stock, physical assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as
non-recourse debt or "non-recourse financing." In some non-recourse financings, The AES Corporation has explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take the form of guarantees, indemnities, letters of credit, letter of credit reimbursement agreements and agreements to pay, in certain circumstances, the project lenders or other parties.
As of December 31, 2018, we had approximately $19.3 billion of outstanding indebtedness on a consolidated basis, of which approximately $3.7 billion was recourse debt of The AES Corporation and approximately $15.6 billion was non-recourse debt. In addition, we have outstanding guarantees, indemnities, letters of credit, and other credit support commitments which are further described in this Form 10-K in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Parent Company Liquidity.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in our Consolidated Balance Sheets related to such defaults was $351 million as of December 31, 2018. While the lenders under our non-recourse financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults thereunder can still have important consequences for The AES Corporation, including, without limitation:
reducing The AES Corporation's receipt of subsidiary dividends, fees, interest payments, loans and other sources of cash since the project subsidiary will typically be prohibited from distributing cash to The AES Corporation during the pendency of any default;
under certain circumstances, triggering The AES Corporation's obligation to make payments under any financial guarantee, letter of credit or other credit support which The AES Corporation may have provided to or on behalf of such subsidiary;
triggering defaults in The AES Corporation's outstanding debt. For example, The AES Corporation's senior secured credit facility, secured term loan, and outstanding senior notes include events of default for certain bankruptcy related events involving material subsidiaries. In addition, The AES Corporation's senior secured credit facility includes certain events of default relating to accelerations of outstanding material debt of material subsidiaries or any subsidiaries that in the aggregate constitute a material subsidiary; or
foreclosure on the assets that are pledged under the non-recourse loans, resulting in write-downs of assets and eliminating any and all potential future benefits derived from those assets.
None of the projects that are currently in default are owned by subsidiaries that individually or in the aggregate meet the applicable standard of materiality in The AES Corporation's senior secured credit facility or other debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of future mix of distributions, write-down of assets, dispositions and other matters that affect our financial position and results of operations, it is possible that one or more of these subsidiaries, individually or in the aggregate, could fall within the applicable standard of materiality and thereby upon an acceleration of such subsidiary's debt, trigger an event of default and possible acceleration of the indebtedness under The AES Corporation's senior secured credit facility or other indebtedness of The AES Corporation.
The AES Corporation, or the Parent Company, has significant cash requirements and limited sources of liquidity.
The AES Corporation requires cash primarily to fund:
principal repayments of debt;
interest;
acquisitions;
construction and other project commitments;
other equity commitments, including business development investments;
equity repurchases and/or cash dividends on our common stock;
taxes; and
Parent Company overhead costs.
The AES Corporation's principal sources of liquidity are:
dividends and other distributions from its subsidiaries;
proceeds from debt and equity financings at the Parent Company level; and
proceeds from asset sales.
While we believe that these sources will be adequate to meet our obligations at the Parent Company level for the foreseeable future, this belief is based on a number of material assumptions, which could prove incorrect, including, without limitation, assumptions about our ability to access the capital or commercial lending markets, the operating and financial performance of our subsidiaries, exchange rates, our ability to sell assets, and the ability of our subsidiaries to pay dividends and other distributions. There can be no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than expected. In addition, our cash flow may not be sufficient to repay at maturity the entire principal outstanding under our credit facility, term loan, and our debt securities and we may have to refinance such obligations. There can be no assurance that we will be successful in obtaining such refinancing on terms acceptable to us or at all and any of these events could have a material effect on us.
Our ability to grow our business depends on our ability to raise capital on favorable terms.
From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Our ability to arrange for financing on either a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:
general economic and capital market conditions;
the availability of bank credit;
the financial condition, performance and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing;
the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances; and
changes in tax and securities laws which are conducive to raising capital.
Should access to capital not be available to us, we may have to sell assets or decide not to build new plants, or expand or improve existing facilities, either of which would affect our future growth, results of operations or financial condition.
A downgrade in the credit ratings of The AES Corporation or its subsidiaries could adversely affect our access to the capital markets, increase our interest costs and/or adversely affect our liquidity and cash flow.
If any of the credit ratings of The AES Corporation or its subsidiaries were to be downgraded,following events actually occur, our ability to raise capital on favorable termsbusiness, financial results and financial condition could be impaired and our borrowing costs could increase. Furthermore, depending on The AES Corporation's credit ratings and the trading prices of its equity and debt securities, counterparties may no longer be as willing to accept general unsecured commitments by The AES Corporation to provide credit support. Accordingly, with respect to both new and existing commitments, The AES Corporation may be required to provide some other form of assurance, such as a letter of credit and/or collateral, to backstop or replace any credit support by The AES Corporation. There can be no assurance that such counterparties will accept such guarantees or that AES could arrange such further assurances in the future. In addition, to the extent The AES Corporation is required and able to provide letters of credit or other collateral to such counterparties, it will limit the amount of credit available to The AES Corporation to meet its other liquidity needs.
We may not be able to raise sufficient capital to fund development projects in certain less developed economies, which could affect our growth strategy.
Part of our strategy is to grow our business by developing businesses in less developed economies where the return on our investment may be greater than projects in more developed economies. Commercial lending institutions sometimes refuse to provide non-recourse project financing in certain less developed economies, and in these situations we have sought and may continue to seek direct or indirect (through credit support or guarantees) project financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such project financing available, the lending institutions may also require governmental guarantees for certain project and sovereign-related risks. There can be no assurance, however, that project financing from the international financial agencies or that governmental guarantees will be available when needed,
and if they are not, we may have to abandon the relevant project or invest more of our own funds, which may not be in line with our investment objectives and would leave less funds for other projects.
External Risks Associated with Revenue and Earnings Volatility
Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets.
Some of our businesses sell electricity in the spot markets when they operate at levels in excess of 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;
seasonality;
hydrology and other weather conditions;
illiquid markets;
transmission,transportation constraints, inefficiencies and/or availability;
renewables source contribution to the supply stack;
new entrants;
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, and other catastrophic events;
energy, market and environmental regulation, legislation and policies;
general economic conditions globally as well as in areas where we operate that impact demand and energy consumption; and
bidding behavior and market bidding rules.
Adverse economic developments in China could have a negative impact on demand for electricity in many of our markets.
The Chinese market has been driving global materials demand and pricing for commodities over the past decade. Many of these commodities are produced in areas that are also our key markets for the sale of electricity. After experiencing rapid growth for more than a decade, China’s economy has experienced decreasing foreign and domestic demand, weak investment, factory overcapacity and oversupply in the property market, and has experienced a significant slowdown in recent years. U.S. tariffs are also expected to have a negative impact on China's economic growth. 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.
Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.
Our exposure to currency exchange rate fluctuations results primarily from the translation exposure associated with the preparation of the Consolidated Financial Statements, as well as from transaction exposure associated with transactions in currencies other than an entity's functional currency. While the Consolidated Financial Statements are reported in U.S. dollars, the financial statements of several of our subsidiaries outside the United States are prepared using the local currency as the functional currency and translated into U.S. dollars by applying appropriate exchange rates. As a result, fluctuations in the exchange rate of the U.S. dollar relative to the local currencies
where our subsidiaries outside the United States report could cause significant fluctuations in our results. In addition, while our expenses with respect to foreign operations are generally denominated in the same currency as corresponding sales, we have transaction exposure to the extent receipts and expenditures are not denominated in the subsidiary's functional currency. Moreover, the costs of doing business abroad may increase as a result of adverse exchange rate fluctuations. Our financial position and results of operations could bematerially adversely affected by fluctuations in the value of a number of currencies.
Wholesale power prices are declining in many markets and this could have a material adverse effect on our operations and opportunities for future growth.
The wholesale prices offered for electricity have declined significantly in recent years in many markets in which the Company has businesses. This price decline is due to a variety of factors, including the increased penetration of renewable generation resources, low-priced natural gas and demand side management. The levelized cost of electricity from new solar and wind generation sources has dropped substantially in recent years as solar panel costs and wind turbine costs have declined, while wind and solar capacity factors have increased. These renewable resources have no fuel costs and very low operational costs. In many instances, energy from these facilities are bid into the wholesale spot market at a price of zero or close to zero during certain times of the day, driving down the clearing price for all generators selling power in the relevant spot market. Also, in many markets new PPAs have been awarded for renewable generation at prices significantly lower than the prices being awarded just a few years ago.
This trend of declining wholesale prices could continue and could have a material adverse impact on the financial performance of our existing generation assets to the extent they currently sell power into the spot market or will seek to sell power into the spot market once their PPAs expire. The trend of declining prices can also make it more difficult for us to obtain attractive prices under new long-term PPAs for any new generation facilities we may seek to develop. As a result, the trend can have an adverse impact on our opportunities for new investments.
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.
Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.
We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of some of our facilities. If these suppliers cannot perform, we would seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price, which could adversely impact the profitability of the affected business and our results of operations, and could result in a breach of agreements with other counterparties, including, without limitation, offtakers or lenders.
At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. Counterparties to these agreements may breach or may be unable to perform their obligations, due to bankruptcy, insolvency, financial distress or other factors. Furthermore, in the event of a bankruptcy or similar insolvency-type proceeding, our counterparty can seek to reject our existing PPA under the U.S. Bankruptcy Code or similar bankruptcy laws, including those in Puerto Rico. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement PPAs, these businesses may have to sell power at market prices. A breach by a counterparty of a PPA or other agreement could also result in the breach of other agreements, including, without limitation, the debt documents of the affected business.
The financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers. Any failure of a supplier or customer to fulfill its contractual obligations to The AES Corporation or our subsidiaries could have a material adverse effect on our financial results.
The market price of our common stock may be volatile.
The market price and trading volumes of our common stock could fluctuate substantially in the future. Factors that could affect the price of our common stock include, among other factors, general conditions in our industry and the power markets in which we participate, environmental and economic developments, and general credit and capital markets conditions, as well as developments specific to us, including risks that could result in revenue and earnings volatility, failing to meet our publicly announced guidance or other risk factors described in Item 1A.—Risk Factors and key trends and other matters described in Item 7.—Management's Discussion and Analysis of Financial Conditions and Results of Operations.
Risks Associated with our Operations
We do a significant amount of business outside the United States, including in developing countries, which presents significant risks.
A significant amount of our revenue is generated outside the United States and a significant portion of our international operations is conducted in developing countries. Part of our growth strategy is to expand our business in certain developing countries in which AES has an existing presence. We believe these countries may have higher growth rates and offer greater opportunities, with potentially higher returns than in some more developed countries. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:
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 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;
unexpected delays in permitting and governmental approvals;
unexpected changes or instability affecting our strategic partners in developing countries;
risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, UK Bribery Act or other anti-bribery laws applicable to our operations, including, among other things, cost and disruption in responding to allegations or investigations (regardless of ultimate finding), civil and/or criminal fines, criminal prosecution of individuals, revocation or suspension of permits and/or licenses, civil litigation, reputational damage, loss in share price, and loss of business;
difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with GAAP expertise;
unwillingness of governments and their agencies, similar organizations or other counterparties to honor their contracts;
unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and less beneficial to counterparties, against such counterparties, whether such counterparties are governments or private parties;
inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
adverse changes in government tax policy;
difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and
potentially adverse tax consequences of operating in multiple jurisdictions.
Any of these factors, by itself or in combination with others, could materially and adversely affect our business, results of operations and financial condition. Our operations may experience volatility in revenues and operating margin which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability and currency devaluations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses. A number of our businesses are facing challenges associated with regulatory changes.
The operation of power generation, distribution and transmission facilities involves significant risks that could adversely affect our financial results.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. This could have a material adverse effect on our businesses' results of operations, financial condition and prospects.
In addition, a portion of our generation facilities were constructed many years ago. Older generating equipmentago and may require significant capital expenditures for maintenance. The equipment at our plants whether old or new, is also likely to requirerequires periodic upgrading, improvement or repair, and replacement equipment or parts may be difficult to obtain in circumstances where we rely on a single supplier or a small number of suppliers. The inability to obtain replacement equipment or parts may impact the ability of our plants to perform and could, therefore, have a material impact on our business and results of operations.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 the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems, which reduce, but domay not eliminate, the possibility ofprevent 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 Proceedingsbelow. There can be no assurance that the outcomes of such matters will not have a material adverse effect on our consolidated financial position.
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;
•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;
•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 from time to time become exposed to significant liabilities for which we may not have adequate risk mitigation and/or insurance coverage. Furthermore, through AGIC, AES’ captive insurance company, we take certain insurance risk on our businesses. We maintain an amount of insurance protection that we believe is customary, but there can be no assurance that our insuranceit will be sufficient or effective underin light of all circumstances, and against all hazards or liabilities to which we may be subject. Our insurance does not cover every potential risk associated with our operations. Adequate coverage at reasonable rates is not always obtainable and dueobtainable. In particular, the availability of insurance for coal-fired generation assets has decreased as certain insurers have opted to the cyclical nature of thediscontinue or limit offering insurance markets, wefor such assets. Certain insurers have also withdrawn from insuring hydroelectric assets. We cannot provide assurance that insurance coverage will continue to be
available in the amounts or on terms similar to those presently available to us or at all.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 fully or partiallyadequately covered by insurance could have a material adverse effect on our business, results or operations, financial condition, and prospects.
We may not be able to enter into long-term contracts that reduce volatility in our results of operations.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 in part by entering into power sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from certain sovereign governments of the customer's obligations. However,obligations; however, many of our customers do not have or have failed to maintain, annot maintained, investment-grade credit rating, and ourratings. Our generation businessbusinesses cannot always obtain government guarantees and if they do, the government doesmay not always have an investment grade credit rating. We have also sought to reduce our credit risk by locatinglocated our plants in different geographic areas in order to mitigate the effects of regional economic downturns; however, there can be no assurance that our efforts to mitigate this risk will be successful.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.
OurSupplier 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.
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 will needdebt agreements. Any failure of a supplier or customer to continue to adapt to technological change and wefulfill its contractual obligations could have a material adverse effect on our financial results.
We may incur significant expenditures to adapt to theseour 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 the demand for large-scale renewable electricity generation and/or impact our customers’ ability to perform underperformance 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
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.
IfTo the extent that hydrological conditions result in droughts or other conditions that negatively affect our hydroelectric generation business, such as has happened in Panama in 2019, our results of operations couldcan be materially adversely affected. Additionally, our contracts in certain markets where hydroelectric facilities are prevalent may require us to purchase power in the spot markets when our facilities are unable to operate (or operate at lower than anticipated levels)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 and adversely affect our financial results.business.
Weather conditions directly influence the demand for electricity and natural gas and other fuels and affect the price of energy and energy-related commodities. In addition, severe weather and natural disasters, such as hurricanes, floods, tornadoes, icing events, earthquakes, dam failures and tsunamis can be destructive and could prevent us from operating our business in the normal course by causing power outages and property damage, reducing revenue, affecting the availability of fuel and water, causing injuries and loss of life, and requiring us to incur additional costs, for example, to restore service and repair damaged facilities, to obtain replacement power and to access available financing sources. Our power plants could be placed at greater risk of damage should changes in the global climate produce unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, including heatwaves, fewer cold temperature extremes, abnormal levels of precipitation resulting in
river and coastal urban floods in North America or reduced water availability and increased flooding across Central and South America, and changes in coast lines due to sea level change.
Depending on the nature and location of the facilities and infrastructure affected, any such incident also could cause catastrophic fires; releases of natural gas, natural gas odorant, or other greenhouse gases; explosions, spills or other significant damage to natural resources or property belonging to third parties; personal injuries, health impacts or fatalities; or present a nuisance to impacted communities. Such incidents that do not directly affect our facilities may 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.
Our development projects are subject to substantial uncertainties.
Certain of our subsidiaries and affiliatesWe are in various stages of developing and constructing power plants. Some but not allCertain of these power plant projects have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion of the development of these projects depends upon overcoming substantial risks, including but not limited to, risks relating to siting, financing, engineering and construction, permitting, governmental approvals, commissioning delays, or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. For additional information regarding our projects under construction see Item 1.—Business—Our Organization and Segments included in this Form 10-K.In certain cases, our subsidiaries may enter into obligations in the development process even though the subsidiariesthey have not yet secured financing, power purchase arrangements,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 even where they do not havewithout having financing, a PPA or critical permits in place (or conversely, to enter into a PPA, procurement agreement or other agreement without financing in place)agreed financing). If the project does not proceed, our subsidiaries may remain obligated forretain certain liabilities even though the project will not proceed. Development is inherently uncertain and we may forgo certain development opportunities andliabilities. Furthermore, we may undertake significant development costs before determining that we willand 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 will be completed and reach commercial operation. If these development efforts are not successful, we may abandon a project under development and writecertain projects, resulting in, writing off the costs incurred, in connection with such project. At the time of abandonment, we would expense allexpensing related capitalized development costs incurred in connection therewith and could incurincurring additional losses associated with any related contingent liabilities.
We do not control certain aspects of our joint ventures.ventures or our equity method investments.
We have invested in some joint ventures in which our subsidiaries share operational, management, investment and/or other control rights with our joint venture partners. In many cases, we may exert influence over the joint venture pursuant to a management contract, by holding positions on the board of the joint venture company or on management committees and/or through certain limited governance rights, such as rights to veto significant actions. However, we do not always have this type of influence over the project or business in every instance and we may be dependent on our joint venture partners or the management team of the joint venture to operate, manage, invest or otherwise control such projects or businesses. Our joint venture partners or the management team of our joint ventures may not have the level of experience, technical expertise, human resources, management and other attributes necessary to operate these projects or businesses optimally, and they may not share our business priorities. In some joint venture agreements in which we do have majority control of the voting securities, we have entered into shareholder agreements granting minority rights to the other shareholders.
The approval of joint venture partners also may be required for us to receive distributions of funds from jointly owned entities or to transfer our interest in projects or businesses. The control or influence exerted by our joint venture partners may result in operational management and/or investment decisions that are different from the decisions our subsidiarieswe would make if they operated independently and could impact the profitability and value of these joint ventures. In addition, in the event thatif a joint venture partner becomes insolvent or bankrupt or is
otherwise unable to meet its obligations to the joint venture or its share of liabilities atfor the joint venture, we may be subject to joint and several liability for these joint ventures, which means that we may be responsible for meeting certain obligations of the joint ventures should our joint venture partner be unable to do so, if and to the extent provided for in our governing documents or applicable law.
In addition, we are generally dependent on the management team of our equity method investments to operate and control such projects or businesses. While we may exert influence pursuant to having positions on the boards of such investments and/or through certain limited governance rights, such as rights to veto significant actions, we do not always have this type of influence and the scope and impact of such influence may be limited. The management teams of our equity method investments may not have the level of experience, technical expertise, human resources, management and other attributes necessary to operate these projects or businesses optimally, and they may not share our business priorities, which could have a material adverse effect on value of such investments as well as our growth, business, financial condition, results of operations and prospects.
Our renewable energy projects and other initiatives face considerable uncertainties, including development, operational, and regulatory challenges.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
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 example, for our wind projects, wind resource estimates are based on historical experience when available and on wind resource studies conducted by an independent engineer. These wind resource estimates are not expected to reflect actual wind energy production in any given year, but long-term averages of a resource.
As a result, these types of renewable energy projects face considerable risk, including the risk that favorable regulatory regimes expire or are adversely modified. In addition, because certain of these projects depend on technology outside of our expertise in generation and utility businesses, there are risks associated with our ability to develop and manage such projects profitably. Furthermore, atAt the development or acquisition stage, because of our more limited experience with the relevant technologies, our ability to predict actual performance results may be hindered and the projects may not perform as predicted. There are also risks associated with the fact that some of these projects exist in markets where long-term fixed pricefixed-price contracts for the major cost and revenue components may be unavailable, which in turn may result in these projects having relatively high levels of volatility. These projects can be capital-intensive and generally are designed with a view to obtaining third-party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to develop these projects or obtain third-party financing for these projects.
Government incentivesFluctuations in currency exchange rates may impact our financial results and policies that supportposition.
Our exposure to currency exchange rate fluctuations results primarily from the developmenttranslation exposure associated with the preparation of renewable energy generation projectsthe 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 change at any time.
AES’ U.S. renewable energy generation growth strategy dependscause significant fluctuations in part on federal, stateour 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 local government policies and incentives that supportexpenditures are not denominated in the development, financing, ownership and operationsubsidiary's functional currency. Moreover, the costs of renewable energy generation projects. These policies and incentives include investment tax credits, production tax credits, accelerated depreciation, renewable portfolio standards, feed-in-tariffs and similar programs, renewable energy credit mechanisms, and tax exemptions. If these policies and incentives are changed or eliminated, or AES is unable to use them, it coulddoing business abroad may increase as a result in a materialof adverse impact on AES’ U.S. renewable growth opportunities, including fewer future PPAs or lower prices for the sale of power in future PPAs, decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing.exchange rate fluctuations.
We may not be ableadequately hedged against our exposure to attractchanges in commodity prices or interest rates.
We routinely enter into contracts to hedge a portion of our purchase and retain skilled people,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 adverse effect on our operations.
Our operating success and ability to carry out growth initiatives depends, in part, on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity, including people in our foreign businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements. For example, we routinely assess the financial impacts of complicated business transactions that occur on a worldwide basis. These assessments are dependent on hiring personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with U.S. reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse effect on our financial and tax reporting.
Cyber-attacks and data security breaches could harm our business.
Our business is heavily reliant on electronic systems and network technologies to operate our generation, transmission and distribution infrastructure. We also use various financial, accounting and other infrastructure systems. Our infrastructure may be targeted by nation states, hacktivists, criminals, insiders or terrorist groups. Such an attack, by hacking, malware or other means, may interrupt our operations, cause property damage, affect our ability to control our infrastructure assets, cause the release of sensitive customer information or limit
communications with third parties. Any loss or corruption of confidential or proprietary data through such breach may:
impair our reputation;
impact our operations and strategic objectives;
impact our customer and vendor relationships;
result in substantial revenue loss;
expose us to legal claims and/or regulatory investigations and proceedings; and
require extensive repair and restoration costs for additional security measures to avert future cyber-attacks.
In addition, a breach of our financial and accounting systems could impact our ability to correctly record, process and report financial information.
In addition, 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 can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation. The EU GDPR recently came into force and applies to the processing of personal information collected from individuals located in the EU. The GDPR creates new compliance obligations and significantly increases fines for noncompliance.
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 on our business and operations have not had a material impact on these businesses and/or our operations or financial results. We continue to assess potential threats and vulnerabilities and make investments to address them, including global monitoringresults of networks and systems, identifying and implementing new technology, improving user awareness through employee security training, and updating our security policies as well as those for third-party providers. We cannot guarantee the extent to which our security measures will prevent future cyber-attacks and security breaches or that our insurance coverage will adequately cover any losses we may experience.operations.
Our utilities businesses may be negatively affected by a lack of growth orexperience slower growth in the number of customers or in customer usage.
Customer growth and customer usage in our utilities businesses are affected by a number ofexternal factors, outside our control, such asincluding mandated energy efficiency measures, demand side management requirements, and economic and demographic
conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. A lack of growth, or a decline, in the number of customers or in customer demand for electricity may cause us to fail to fullynot realize the anticipated benefits from significant investments and expenditures and could have a material adverse effect on our growth, business, financial condition, results of operations and prospects.
Some of our subsidiaries participate in defined benefit pension plans and their net pension plan obligations may require additional significant contributions.
We have 3028 defined benefit plans, five at U.S. subsidiaries and the remaining plans at foreign subsidiaries, which cover substantially all of the employees at these subsidiaries. Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be incorrect, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. We periodically evaluate the value of the pension plan assets to ensure that they will be sufficient to fund the respective pension obligations. Our exposure to market volatility is mitigated to some extent due to the fact that the asset allocations in our largest plans include a significant weighting of investments in fixed income securities that are generally less volatile than investments in equity securities. Future downturnsDownturns 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 ana material increase in pension expense and future funding requirements, which may be material.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. Satisfying such funding requirementsplan, which may necessitate additional cash contributions to the pension plans that could adversely affect the Parent Companyour and our subsidiaries' liquidity. For additional information regarding the funding position of the Company's pension plans, seeSee Item 7.—Management's Discussion and Analysis of Financial Condition and Results
Impairment of goodwill or long-lived assets would negatively impact our consolidated results of operations and net worth.
As of December 31, 2018,2020, the Company had approximately $1.1 billion of goodwill, which represented approximately 3% of theour total assets on its Consolidated Balance Sheets.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, including but not limited to:such as: deterioration in general economic conditions or our operating or regulatory environment; increased competitive environment; lower forecasted revenue; increase in fuel costs, particularly whencosts that we are unable to pass through the impact to customers; increase in environmental compliance costs; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; developments in our strategy; divestiture of a significant component of our business; or adverse actions or assessments by a regulator. For example, 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 annual goodwill impairment test performed asthird quarter of October 1, 2018,2020, the Company determined thatthere 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 7%. Therefore, Gener's $868 million goodwill balance was13%, and is not currently considered to be "at risk". We continue to monitor the Gener reporting unit for potential interim goodwill impairment as of December 31, 2018 largely due to the fact that a market participant would no longer assume perpetual cash flows from coal-fired power plants due to the increased penetration of renewable energy in Chile.triggering events. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Impairments. These types of events and the resulting analyses could result in goodwill impairment, which could substantially affect our results of operations for those periods.impairment. Additionally, goodwill may be impaired if our acquisitions do not perform as expected. See the risk factor Our acquisitions may not perform as expected for further discussion. Long-lived assets are initially recorded at fair value, and are amortized or depreciated over their estimated useful lives. Long-lived assetslives, and are evaluated for impairment only when impairment indicators, similar to those described above for goodwill, are present, whereaspresent. Any impairment of goodwill is also evaluated for impairment on an annual basis.
Any of the foregoingor 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. Westrategy and we may continue to grow our business throughmake 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:
that we will be successful in transitioning them to private ownership;
such businesses will perform as expected;
integrationownership or other one-time costs will not be greater than expected;
that we will not incur unforeseen obligations or liabilities;liabilities. Further, we may incur integration or
other one-time costs that are greater than expected. Such businesses willmay not generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them; or
and the rate of return from such businesses willmay not justify our decision to investinvestment of capital to acquire them.
Risks associated with Governmental Regulation and Laws
Our operations are subject to significant government regulation and our business and results of operations could be adversely affected by changes in the law or regulatory schemes.
Our ability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any ability to obtainobtaining expected or contracted increases in electricity tariff or contract rates or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analysts' expectations.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, but not limited to: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 what is an appropriate rate of return on invested capital or a determination that a utility's operating income or the rates it charges customers are too high, resulting in a rate reduction of rates or consumer rebates;
•changes in the definition or determination of controllable or non-controllable costs;
adverse •changes in tax law;
•changes in law or regulation whichthat limit or otherwise affect the ability of our counterparties (including sovereign or private parties) to fulfill their obligations (including payment obligations) to us or our subsidiaries;us;
•changes in environmental law whichthat impose additional costs or limit the dispatch of our generating facilities within our subsidiaries;facilities;
•changes in the definition of events which may or may notthat 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 markets where we operate.our markets.
Any of the above events may resultFurthermore, in lower operating margins for the affected businesses, which can adversely affect our business.
In many countries where we conduct business, the regulatory environment is constantly changing and it may be difficult to predict the impact of the regulations on our businesses. The impacts described above could also result from our (or our subsidiaries') efforts to comply with European Market Infrastructure Regulation, which includes regulations related to the trading, reporting and clearing of derivatives. It is also possible that additionalderivatives and similar regulations may be passed in other jurisdictions where we conduct business. Any of these outcomes could have a material adverse effect on the Company.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 which consists of bottom ash, fly ash and air pollution control wastes generated at our current and former coal-fired generation plant sites, is currently handled and/or has been handled in the past in the following ways: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 U.S. EPA's final CCR rule which became effective in October 2015, regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR ponds, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On December 16, 2016, President Obama signed the WIN Act into law, which includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. The primaryprovides that enforcement mechanisms under this regulation couldactions can be actions commenced by U.S.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.
Our business in the United States isSome of our U.S. businesses are subject to the provisions of various laws and regulations administered in whole or in part by FERC and NERC, including PURPA, the Federal Power Act, and the EPAct 2005. Actions 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 PUHCA 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, PUCHA, while continuing to provide FERC and state utility commissions with enhanced access to the books and records of certain utility holding companies. PUHCA 2005 also creates additional potential challenges and opportunities. By removing some barriers to mergers and other potential combinations, the creation of large, geographically dispersed utility holding companies is more likely. These entities may have enhanced financial strength and therefore an increased ability to compete with us in the U.S. market.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.
In accordance with Congressional mandates in the EPAct 1992 and the EPAct 2005, FERC has strongly encouragedencourages competition in wholesale electric markets. Increased competition may have the effect of lowering our operating margins. Among other steps, FERC has encouraged RTOs and ISOs to develop demand response bidding programs as a mechanism for responding to peak electric demand. These programs may reduce the value of generation assets. Similarly, FERC is encouraging the construction of new transmission infrastructure in accordance with provisions of EPAct 2005. Although new transmission lines may increase market opportunities, they may also increase the competition in our existing markets.
FERC has civil penalty authority over violations of any provision of Part II of the FPA, which concerns wholesale generation or transmission, as well as any rule or order issued thereunder. The FPA also provides for the assessment of criminal fines and imprisonment for violations under the FPA. This penalty authority was enhanced in EPAct 2005. As a result, FERC is authorized to assess a maximum penalty authority established by statute and such penalty authority has been and will continue to be adjusted periodically to account for inflation. With this expanded enforcement authority, violations of the FPA and FERC's regulations could potentially have more serious consequences than in the past.
Pursuant to EPAct 2005, the NERC has been certified by FERC as the Electric Reliability Organization ("ERO")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 in the U.S. face significant regulation by their respective state utility commissions. The regulatory discretion is reasonably broad in both Indiana and Ohio and includes regulation as to services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of certain securities, the acquisition and sale of some public utility properties or securities and certain other matters. These businesses face the risk of unexpected or adverse regulatory action which could have a material adverse effect on our results of operations, financial condition, and cash flows. See Item 1.—Business—US SBU—U.S. Businesses—U.S.and Utilities SBU for further information on the regulation faced by our U.S. utilities.. Our businesses are subject to stringent environmental laws, rules and regulations.
Our businesses are subject to stringent environmental laws and regulations by many federal, regional, state and local authorities, international treaties and foreign governmental authorities. These laws and regulations generally concern emissions into the air, effluents into the water, use of water, wetlands preservation, remediation of contamination, waste disposal, endangered species and noise regulation. Failure to comply with such laws and regulations or to obtain or comply with any associated environmental permits could result in fines or other sanctions.
For example, in recent years, the EPA has issued notices of violation (NOVs)NOVs to a number of coal-fired
generating plants alleging wide-spread violations of the new source review and prevention of significant deterioration provisions of the CAA. The EPA has brought suit against and obtained settlements with many companies for allegedly making major modifications to a coal-fired generating units without proper permit approvals and without installing best available control technology. The primary focus of these NOVs has been emissions of SO2 and NOx and the EPA has imposed fines and required companies to install improved pollution control technologies to reduce such emissions. In addition, state regulatory agencies and non-governmental environmental organizations have pursued civil lawsuits against power plants in situations that have resulted in judgments and/or settlements requiring the installation of expensive pollution controls or the accelerated retirement of certain electric generating units.
Furthermore,Congress and other domestic and foreign governmental authorities have either considered or implemented various laws and regulations to restrict or tax certain emissions, particularly those involving air emissions and water discharges. These laws and regulations have imposed, and proposed laws and regulations could impose in the future, additional costs on the operation of our power plants. See the various descriptions of these laws and regulations contained in Item 1.—Business—Environmental and Land-Use Regulations of this Form 10-K.. We have incurred and will continue to incur significant capital and other expenditures to comply with these and other environmental laws and regulations. Changes in, or new development of, environmental restrictions may force us to incur significant expenses or expenses that may exceed our estimates. There can be no assurance that we would be able to recover all or any increased environmental costs from our customers or that our business, financial condition, including recorded asset values or results of operations, would not be materially and adversely affected by such expenditures or any changes in domestic or foreign environmental laws and regulations.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 2018,2020, the Company's subsidiaries operated businesses that had total CO2 emissions of approximately 5547 million metric tonnes, approximately 2316 million of which were emitted by our U.S. businesses (both figures are ownership adjusted). The Company uses CO2 emission estimation methodologies supported by "The Greenhouse Gas Protocol" reporting standard on GHG emissions. For existing power generation plants, CO2 emissions data are either obtained directly from plant continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission factors. The estimated annual CO2 emissions from fossil fuel-fired electric power generation facilities of the Company's subsidiaries that are in construction or development and have received the necessary air permits for commercial operations are approximately 74 million metric tonnes (ownership adjusted). This overall estimate is based on a number of projections and assumptions that may prove to be incorrect, such as the forecasted dispatch, anticipated plant efficiency, fuel type, CO2 emissions rates and our subsidiaries' achieving completion of such construction and development projects. However, it is certain thatWhile 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. Because there is significant uncertainty regarding these estimates, actual emissions from these projects under construction or development may vary substantially from these estimates.
There currently is no U.S. federal legislation imposing mandatory GHG emission reductions (including for CO2) that affects our electric power generation facilities; however, in 2015, the EPA promulgated a rule establishing New Source Performance Standards for CO2 emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUselectric utility steam generating units larger than 25 MW. AlsoMW and in 2015,2018 proposed revisions to the rule. In 2019, the EPA promulgated the Affordable Clean Power Plan (CPP),Energy (ACE) Rule which requires interimestablishes 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 preexisting EUSGUs beginning in 2022, with full compliance achieved by 2030. These actions have been challenged in courtthe U.S. Supreme Court. The impact of this decision and potential new or revised rules from the current Administration has announced plans to significantly amend or rescind the rules.remains uncertain. In 2016,2010, 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, butmodification. 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.
In December 2015, the The Parties to the United Nations Framework Convention on Climate Change convened for the 21st Conference of the Parties and the resultingChange'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 de-carbonizedecarbonize 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 among others, the degree and timing of GHG emissions
reductions required under any such legislation or regulation, the cost of emissions reduction equipment and the price and availability of offsets, the extent to which market based compliance options are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the ability of our subsidiaries to recover costs incurred through rate increases or otherwise. The costs of compliance could be substantial.
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, or our business development opportunities. 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. While these lawsuits were dismissed, futureFuture 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 Item 1A.—Risk Factors—Certain of our businesses are sensitive to variations in weather and hydrologyand Severe weather and natural disasters may present significant risks to our business and adversely affect our financial results within this section for more information.
information. If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on our electric power generation businesses and on our consolidated results of operations, financial condition,cash flows and reputation.
Concerns about data privacy have led to increased regulation and other actions that could impact our businesses.
In the ordinary course of business, we collect and retain sensitive information, including personal identification information about customers and employees, customer energy usage and other information. The theft, damage or improper disclosure of sensitive electronic data collected by us can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation. 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 our results of operations and financial condition.us
Our subsidiaries have operationsWe operate in the U.S. and various non-U.S. jurisdictions. As such, wejurisdictions 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. There can be no assurance thattaxes, our effective tax rate or tax payments will not be adversely affected by these legislative measures.
payments. The TCJA enacted December 22, 2017 introduced significant changes to current U.S. federal tax law, including but not limited to lowering the corporate income tax rate, introducing new limits on interest expense deductibility, and changing the way in which foreign earnings are taxed.law. These changes are complex, and are subject to additional guidance to be issued by the U.S. Treasury and the Internal Revenue Service. In addition, the reaction to the federal tax changes by the individual states is still evolving. Our interpretations and assumptions around U.S. tax reform may evolve in future periods, as further administrative guidance and regulations are issued, which may materially affect our effective tax rate or tax payments. For further details, please seeAdditionally, 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
Additionally, longstanding international tax norms that determine how and where cross-border international trade is subjected to tax are evolving. The Organization for Economic Cooperation and Development,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 very difficult to assess whether the overall effect of such potential tax changes would be cumulatively positive or negative for our earnings and cash flow, but suchflow. Such changes could adverselyhave a material adverse impact our results of operations.
U.S. federal, stateRisks 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 wella result of foreign governments restricting the repatriation of funds or the conversion of currencies. Our subsidiaries
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 non-U.S., tax lawscurrent 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 regulationsother 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 extremely complexpledged under the non-recourse financings, resulting in write-downs of assets and subjecteliminating 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 varying interpretations.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 our tax positionswe will be sustained if challengedsuccessful 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 relevantoperating cash
flows. Our ability to arrange for financing on either a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including: general economic and capital market conditions; the availability of bank credit; the availability of tax authoritiesequity partners; the financial condition, performance and ifprospects of AES as well as our competitors; and changes in tax and securities laws. Should access to capital not sustained, therebe 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 a material impact on our results of operations.
Weimpaired and our affiliates are subjectborrowing costs could increase. Furthermore, counterparties may no longer be willing to material litigation and regulatory proceedings.
We andaccept 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 affiliates are parties to material litigation and regulatory proceedings. See Item 3.—Legal Proceedings below.available credit. There can be no assurancesassurance that the outcomecounterparties will accept such guarantees or other assurances.The market price of suchour 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 will not have a material adverse effect on our consolidated financial position.described in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations. ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-term leases, none of which we believe are material. With a few exceptions, our facilities, which are described in Item 1—Business of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project's related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate. ITEM 3. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company's consolidated financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material, but that cannot be estimated as of December 31, 2018.2020.
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
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 ($21 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$2910 million to R$41 million ($82 million to $8 million), and there could be additional remediation costs which cannot be estimated at this time. In June 2016, the Company sold AES Sul to CPFL Energia S.A. and as part of the sale, AES Guaiba, a holding Companycompany of AES Sul, retained the potential liability relating to this matter. The Company believes that there are meritorious
defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2012,February 2017, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê had paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the grounds that the tax rate was set in the applicable legislation. In April 2013, the FIAC determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest, and penalties totaling approximately R$1.21 billion ($312 million) as estimated by AES Tietê. AES Tietê appealed to the SIAC. In January 2015, the Second Instance Administrative Court ("SIAC")EPA issued a decision in AES Tietê's favor, finding that AES Tietê was not liableNOV for unpaid taxes. The public prosecutor subsequently filed an appeal, which was denied as untimely. The Tax Authority thereafter filed a motion for clarification of the SIAC's decision, which was denied in September 2016. The Tax Authority later filed a special appeal (“Special Appeal”), which was rejected as untimely in October 2016. The Tax Authority thereafter filed an interlocutory appeal with the Superior Administrative Court (“SAC”). In March 2017, the President of the SAC determined that the SAC would analyze the Special Appeal. AES Tietê challenged the Special Appeal. In May 2018, the SAC rejected the Special Appeal on the merits. In August 2018, the Tax Authority filed a motion for clarification. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2015, DPL received NOVs from the EPAStuart Station, alleging violations of opacity atin 2016. On May 31, 2018, Stuart Station was retired, and Killen Stations, and inon 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 February 2017, the EPA issued a second NOV for DPL Stuart Station, alleging violations of opacity in 2016. Moreover,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. ItOn 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 too earlysubject to determine whetherfinal review and approval by the NOVs could haveU.S. District Court for the Southern District of Indiana, following a material impact30-day public comment period, which began upon publication in the Federal Register. On January 14, 2021, the United States and Indiana, on our business, financial condition or resultsbehalf of our operations. IPL would seek recovery of any operating or capital expenditures, but not fines or penalties, relatedEPA and IDEM, respectively, filed a motion asking the court to air pollution control technologyenter the proposed Consent Decree, along with the United States’ response to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard.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 and has ordered AES Redondo Beach to restore the site. Additional potentialProgram. Potential outcomes of the CCC determination could include an order requiring AES Redondo Beach to fundperform a wetland mitigation projectrestoration and/or pay fines or penalties. AES Redondo Beach believes that it has meritorious arguments and intends to vigorously prosecute such lawsuit,concerning the underlying CCC determination, but there can be no assurances that it will be successful.
In October 2015, Ganadera Guerra, S.A. 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 (“GG”CDP”) and Constructora Tymsa, S.A. (“CT”) filed separate lawsuits against AES Panama inapplication for the local courts of Panama. The claimants allege that AES Panama profited from a hydropower facility (La Estrella) being partially located on land owned initially by GG and currently by CT, and that AES Panama must pay compensation for its useremoval of the land.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 damages sought fromNOV also directed AES Panama are approximately $685 million (GG)to submit technical analysis regarding additional water pumps located within onsite electrical vaults and $100 million (CT). Ina 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 2016,14, 2020, the court dismissed GG's claim because of GG's failureCity deemed the CDP application to comply withbe complete and indicated a court order requiring GG to disclose certain information. GG has refiled its lawsuit. Also, there are ongoing administrative proceedings concerning whether AES Panama is entitled to acquire an easement over the land and whether AES Panama can continue to occupy the land. AES Panama believes it has meritorious defenses and claims and will assert them vigorously; however, there can be no assurances that itpublic hearing will be successful in its efforts.required, at which
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. Thereafter, the SMA made three separate requests for information about the Compliance Plan, to which Alto Maipo duly responded. 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”) an acceptablea 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. Furthermore,
A number of lawsuits have been filed in May 2018, three lawsuits were filed with the Environmental Court of Santiago (“ECS”) challengingrelation to the April 2018 Approval. Alto Maipo does not believe that thereApproval, some of which are grounds to challengestill pending. To date, none of the lawsuits have negatively impacted the April 2018 Approval. The ECS has not decidedApproval or the lawsuits to date.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 over $230at 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 has made submissions allegingalleges that it is entitled to damages ranging from $90$70 million to $150$170 million (which include the LC Funds) plus interest and costs.costs, based on various scenarios. Alto Maipo has contested these submissions. There will be another round of briefing. The evidentiary hearing is scheduled forin the First Arbitration took place May 20-31, 2019.2019, 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 requiringholding 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. Alto Maipo requested inThe Second Arbitration has been consolidated into the First Arbitration an interim order restraining CNM from proceeding withArbitration. The arbitral tribunal has bifurcated the Second Arbitration untilto determine in the conclusion offirst instance the First Arbitration. That request was denied. Separately,jurisdictional objections raised by AES Gener and the Company requested thatto CNM’s piercing claims. The hearing on the relevant arbitral institution decide that the Second Arbitration shall not proceed, given that (among other reasons) there is no arbitration agreement betweenjurisdictional 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 and CNM. That request was not granted. Subsequently, AES Gener and the Company requested that the Second Arbitration be consolidated into the First Arbitration. That request was granted. The schedule has not yet been established on CNM’s claims against AES Gener and the Company. Each of the above-referenced AES companies believes it has meritorious claims and/or defenses and will pursue its interests vigorously; however, there can be no assurances that each of the AES companies will be successful in its efforts.
In February 2018, Tau Power B.V. and Altai Power LLP (collectively, “AES Claimants”) initiated arbitration againstOctober 2017, the Republic of Kazakhstan (“ROK”)Maritime Prosecution Office from Valparaíso issued a ruling alleging responsibility by AES Gener for the ROK’s failure to paypresence of coal waste on Ventanas beach, and proposed a fine before the Maritime Governor, of approximately $75 million (“Return Transfer Payment”) for$380,000. AES Gener submitted its statement of defense, denying the return of two hydropower plants (“HPPs”) pursuant to a concession agreement. In April 2018, the ROK respondedallegations. An evidentiary stage was concluded and then re-opened by denying liability and asserting purported counterclaims concerning the annual payment provisions in the concession agreement, a bonus allegedly due for the 1997 takeoverorder of the HPPs,Maritime Governor on February 5, 2019 to allow AES Gener an opportunity to present reports and dividends paid byother evidence to challenge the HPPs. The ROK seeks to recovergrounds of the Return Transfer Payment (which is in an escrow account maintained by a third party)ruling. AES Gener has completed its presentation of evidence and appears to be seeking over $480 million on its counterclaims. The AES Claimants believe thatawaits the ROK’s defenses and counterclaims are without merit. An arbitrator has been appointed to decideMaritime Prosecution Office’s decision of the case. The final evidentiary hearing is scheduled for July 22AES Gener believes that it has meritorious defenses to 26, 2019. The AES Claimants will pursue their case and assert their defenses vigorously;the allegations; however, there can beare no assurances that theyit will be successful in their efforts.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.
In February 2019, a separate lawsuit was filed in Dominican Republic civil court against the Company, AES Puerto Rico, two other AES affiliates, and an unaffiliated company and its principal. The lawsuit purports to be brought on behalf of over 200 Dominican claimants, living and deceased, and appears to seek relief relating to CCRs that were delivered to the Dominican Republic in 2003 and 2004. The lawsuit generally alleges that the CCRs caused personal injuries and deaths and demands $900 million in alleged damages. The lawsuit does not identify, or provide any supporting information concerning, the alleged injuries of the claimants individually. Nor does the lawsuit provide any information supporting the demand for damages or explaining how the quantum was derived. In August 2020, at the request of the relevant AES companies, the case was transferred to a different civil court. The relevant AES companies believe that they have meritorious defenses to the claims asserted against them and will defend themselves vigorously in this proceeding; however, there can be no assurances that they will be successful in their efforts.
In October 2019, the Superintendency of the Environment (the "SMA") notified AES Gener of certain alleged breaches associated with the environmental permit of the Ventanas Complex, initiating a sanctioning process through Exempt Resolution N° 1 / ROL D-129-2019. The alleged charges include exceeding generation limits, failing to reduce emissions during episodes of poor air quality, exceeding limits on discharges to the sea, and exceeding noise limits. As the charges are currently classified, the maximum fine is approximately $6.5 million. On October 14, 2019, the SMA notified AES Gener of other alleged breaches at the Guacolda Complex under Exempt Resolution N° 1 / ROL D-146-2019. These allegations include failure to comply with all measures to mitigate atmospheric emissions, failure to comply with mitigation measures to avoid solid fuel discharges to the sea, failure to perform temperature monitoring in intake and water discharge at Unit 3, and a one-day exceedance of the seawater discharge limits. As the Guacolda charges are currently classified, the maximum fine is approximately $4 million. For each complex, additional fines are possible if the SMA determines that non-compliance resulted in an economic benefit. AES Gener has submitted proposed "Compliance Programs" to the SMA for the Ventanas Complex and the Guacolda Complex, respectively. In August 2020, the Compliance Program for Guacolda Complex was approved by the SMA. Upon successful execution of the Compliance Program, the process is expected to conclude without sanctions and to not generate further actions. If the Ventanas Complex submission is approved by the SMA and satisfactorily fulfilled by AES Gener, the process is also expected to conclude without sanctions and to not generate further action.
In March 2020, Mexico’s Comisión Federal de Electricidad (“CFE”) served an arbitration demand upon AES Mérida III. CFE makes allegations that AES Mérida III is in breach of its obligations under a power and capacity purchase agreement ("Contract") between the two parties, which allegations relate to CFE’s own failure to provide fuel within the specifications of the Contract. CFE seeks to recover approximately $190 million in payments made to AES Merida under the Contract as well as approximately $431 million in alleged damages for having to acquire power from alternative sources in the Yucatan Peninsula. AES Mérida has filed an answer denying liability to CFE and asserting a counterclaim for damages due to CFE’s breach of its obligations. The parties submitted their respective initial briefs and supporting evidence in December 2020. After additional briefing, the evidentiary hearing will take place in November 2021. AES Mérida believes that it has meritorious defenses and claims and will assert them vigorously in the arbitration; however, there can be no assurances that it will be successful in its efforts.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
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 repurchaserepurchases from the commencement of the Stock Repurchase Program in July 2010 through December 31, 2018 is2020 totaled 154.3 million shares atfor 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, 2018,2020, $264 million remained available for repurchase under the Stock Repurchase Program. No repurchases were made by The AES Corporation of its common stock in 20182020, 2019, and 2017, respectively. The Parent Company repurchased 8,686,983 shares of its common stock in 2016.2018.
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 dividenddividends for the last three years are displayed below.
| | | Commencing the fourth quarter of | | 2018 | | 2017 | | 2016 | Commencing the fourth quarter of | | 2020 | | 2019 | | 2018 |
| Cash dividend | | $0.1365 | | $0.13 | | $0.12 | Cash dividend | | $0.1505 | | $0.1433 | | $0.1365 |
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 2728 electric and gas utilities included in the S&P 500.
ITEM 6. SELECTED FINANCIAL DATA
