Item 1. BUSINESS

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Item 1. BUSINESS

Item 1.—Business is an outline of our strategy and our businesses by SBU, including key financial drivers. Additional items that may have an impact on our businesses are discussed in Item 1A.—Risk Factors and Item 3.—Legal Proceedings.


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Executive Summary

Incorporated in 1981, AES is a global energy company accelerating the future of energy. Together with our many stakeholders, we are improving lives by delivering the greener, smarter energy solutions the world needs. Our diverse workforce is committed to continuous innovation and operational excellence, while partnering with our customers on their strategic energy transitions and continuing to meet their energy needs today.

Our Strategy

AES remains an industry leader in developing and operating the innovative solutions that enable the transition to zero and low-carbon sources of energy. We continue to see an enormous opportunity from the once-in-a-lifetime transformation of the electricity sector driven by decarbonization, electrification, and digitalization.

The focus of our strategy is to partner with large corporations that are transitioning to carbon-free sources of electricity. One example of our successful execution is our collaboration with large technology companies. Specifically, demand from data centers in the U.S. is expected to nearly double in the next three years. Our well-established relationships with these customers, combined with our proven track record of delivering our projects, positions us well to take advantage of this opportunity.

In 2023, we signed long-term contracts for 5.6 GW of renewables, bringing our backlog of projects — those with signed contracts, but which are not yet in operation — to 12.3 GW. Our backlog serves as the core component of future growth. As a result, we have been consistently rated by Bloomberg New Energy Finance as one of the top two largest sellers globally of renewable power to corporate customers, with a focus on large technology/data center providers.

We are a leader in developing green hydrogen. We are partnering with Air Products to develop, build, own, and operate the largest green hydrogen production facility in the United States. We are also participating in two green hydrogen hubs in the United States, which were awarded up to $2.4 billion of grant funding from the U.S. Department of Energy.

With our utilities, we are working with a broad range of stakeholders to transition to lower carbon forms of energy. At AES Indiana, for example, we are working to retire its remaining coal generation by the end of 2025, while adding new renewables and natural gas to the grid.

We are also developing and incubating new technologies that add value today and will drive our business in


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the future. We understand that the energy industry is changing rapidly, and aim to proactively seek solutions that will give us a continued competitive advantage. At the core of our innovation strategy is AES Next, our business and technology incubator. AES Next works to identify new and innovative technologies and business opportunities that provide or support leading-edge greener energy solutions.

2023 Strategic Highlights

*•*We signed 5.6 GW of renewables and energy storage under long-term PPAs.

We completed the construction of 3.5 GW.
Our backlog, which includes projects with signed contracts, but which are not yet operational, is now 12.3 GW, consisting of:

◦5.1 GW under construction; and

◦7.2 GW with signed PPAs, but that are not yet under construction.

AES Indiana reached a unanimous settlement agreement for its first rate case since 2018, and expects to receive approval from the IURC by the middle of 2024.
AES Ohio received approval from the PUCO for its Electric Security Plan (ESP4), providing the regulatory foundation necessary to enable future investments.
We exited or announced the sale or closure of 2.1 GW of coal generation in Vietnam, the U.S., and Chile.
We signed agreements for three-year extensions of 1.4 GW of gas generation at the Southland legacy units in Southern California. These extensions will help meet the State of California's grid reliability needs while supporting its decarbonization goals.
Awarded up to $2.4 billion of grant funding by the U.S. Department of Energy for two green hydrogen hubs with AES participation.
We secured $1.1 billion in asset sale proceeds, to accelerate our portfolio transformation, outpacing our target of $400 to $600 million.

Overview

Generation

We currently own and/or operate a generation portfolio of 34,596 MW, including generation from our integrated utility, AES Indiana. Our generation fleet is diversified by technologies and 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, economic activity, fixed-cost management, and competition. The financial performance of our renewables business is also impacted by our ability to complete construction projects and earn U.S. renewable tax credits.

Contract Sales — Most of our generation businesses sell electricity under medium- or long-term contracts in either regulated or competitive markets ("contract sales") or under short-term agreements in competitive markets ("short-term sales"). Our medium-term contract sales have terms of two to five years, while our long-term contracts have terms of more than five years.

Contracts requiring fuel to generate energy, such as natural gas or coal, are structured to recover variable costs, including fuel and variable O&M costs, either through direct or indexation-based contractual pass-throughs or tolling arrangements. When the contract does not include a fuel pass-through, we typically hedge fuel costs or enter into fuel or energy supply agreements for a similar contract period (see discussion below under Fuel Costs). These contracts also help us to fund a significant portion of the total capital cost of the project through long-term non-recourse project-level financing.

Certain contracts include capacity payments that cover projected fixed costs of the plant, including fixed O&M expenses, debt service, and a return on capital invested. In addition, most of our contracts require that the majority of the capacity payments be denominated in the currency matching our fixed costs. In some U.S. markets, the capacity payment is only for the resource adequacy or reliability benefits from the generating facility, allowing us to separately monetize the electricity produced by the facility through either contract sales or short-term sales.


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Contracts that do not have significant fuel cost or do not contain a capacity payment are structured based on long-term prices and may also include negotiated pass-through costs, allowing us to recover expected fixed and variable costs as well as provide a return on investment.

Many of these contracts are intended to reduce exposure to the volatility of fuel and electricity prices by linking the business's revenues and costs. We generally structure our business to eliminate or reduce foreign exchange risk by matching the currency of revenue and expenses, including fixed costs and debt. Our project debt may consist of both fixed and floating rate debt for which we typically hedge a significant portion of our exposure. Some of our contracted businesses also receive a regulated market-based capacity payment, which is discussed in more detail in the Short-Term Sales section below.

Thus, these contracts, or other related commercial arrangements, significantly mitigate our exposure to changes in electricity and, as applicable, fuel prices, currency fluctuations and changes in interest rates. In addition, these contracts generally provide or account for a recovery of our fixed operating expenses and a return on our investment, as long as we operate the plant to the reliability, availability, and efficiency standards required in the contract or otherwise.

Short-Term Sales — Our generation businesses also sell power and ancillary services under short-term contracts with average terms of less than two years, including spot sales, directly in the short-term market or at regulated prices. The short-term markets are typically administered by a system operator to coordinate dispatch. Short-term markets generally operate on merit order dispatch, where the least expensive generation facilities, based upon variable cost or bid price, are dispatched first and the most expensive facilities are dispatched last. The short-term price is typically set at the marginal cost of energy or bid price (the cost of the last plant required to meet system demand). As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity. In addition, many of these wholesale markets include markets for ancillary services to support the reliable operation of the transmission system. Across our portfolio, we provide a wide array of ancillary services, including voltage support, frequency regulation and spinning reserves.

Many of the short-term markets in which we operate include regulated capacity markets. These capacity markets are intended to provide additional revenue based upon availability without reliance on the energy margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand). 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 and in certain contract sales, our plants must be reliable and flexible to capture peak market prices and to maximize market-based revenues. In addition, our flexibility allows us to capture ancillary service revenue while meeting local market needs.

Fuel Costs — For our thermal generation plants, fuel is a significant component of our total cost of generation. For contract sales, we often enter into fuel supply agreements to match the contract period, or we may financially hedge our fuel costs. Some of our contracts include indexation for fuels. In those cases, we seek to match our fuel supply agreements to the indexation. For certain projects, we have tolling arrangements where the power offtaker is responsible for the supply and cost of fuel to our plants.

In short-term sales, we sell power at market prices that are generally reflective of the market cost of fuel at the time, and thus procure fuel supply on a short-term basis, generally designed to match up with our market sales profile. Since fuel price is often the primary determinant for power prices, the economics of projects with short-term sales are often subject to volatility of relative fuel prices. For further information regarding commodity price risk please see Item 7A.—Quantitative and Qualitative Disclosures about Market Risk in this Form 10-K.

53% of the capacity of our generation plants are renewables, including hydro, solar, wind, energy storage, biomass and landfill gas, which do not have significant fuel costs.

27% of the capacity of our generation plants are fueled by natural gas. With the exception of our plants in the Dominican Republic and Panama, where we import LNG to utilize in the local market, we use gas from local suppliers in each market.

18% 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 plant in Puerto Rico, we source coal from a mix of


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sources from the international market and in the local jurisdictions. To the extent possible, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.

2% of the capacity of our generation fleet utilizes pet coke or oil for fuel. We source oil and diesel locally at prices linked to international markets. We largely source pet coke from Mexico and the U.S.

Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal weather patterns and, therefore, operating margin is not generated evenly throughout the year. Additionally, weather variations, including temperature, solar and wind resources, and hydrological conditions, may also have an impact on generation output at our renewable generation facilities. In competitive markets for power, local economic activity can also have an impact on power demand and short-term prices for power.

Fixed-Cost Management — In our businesses with long-term contracts, the majority of the fixed O&M costs are recovered through the capacity payment or were otherwise factored in as a component of the long-term contract price. 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 market competition impacting prices 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

Our utility businesses consist of AES Indiana and AES Ohio in the U.S., and four utilities in El Salvador. AES' six utility businesses distribute power to 2.6 million customers and AES' two utilities in the U.S. also include generation capacity totaling 3,500 MW.

AES Indiana, our fully integrated regulated utility, and AES Ohio, our transmission and distribution regulated utility, each operate as the sole distributors of electricity within their respective jurisdictions. AES Indiana owns and operates all of the facilities necessary to generate, transmit and distribute electricity. AES Ohio owns and operates all of the facilities necessary to transmit and distribute electricity. Our distribution business in El Salvador faces 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. Revenue from utilities is classified as regulated on the Consolidated Statements of Operations.

Regulated Rate of Return and Tariff — In exchange for the right to sell or distribute electricity in a service territory, our utility businesses are subject to government regulation. This regulation sets the framework for the prices ("tariffs") that our utilities are allowed to charge customers for electricity and establishes service standards that we are required to meet.

Our utilities are generally permitted to earn a regulated rate of return on assets, determined by the regulator based on the utility's allowed regulatory asset base, capital structure and cost of capital. The asset base on which the utility is permitted a return is determined by the regulator, within the framework of applicable local laws, and is based on the amount of assets that are considered used and useful in serving customers. Both the allowed return and the asset base are important components of the utility's earning power. The allowed rate of return and operating expenses deemed reasonable by the regulator are recovered through the regulated tariff that the utility charges to its customers.

The tariff may be reviewed and reset by the regulator from time to time depending on local regulations, or the utility may seek a change in its tariffs. The tariff is generally based upon usage level and may include a pass-through of costs that are not controlled by the utility, such as the costs of fuel (in the case of integrated utilities) and/or the costs of purchased energy, to the customer. Components of the tariff that are directly passed through to the customer are usually adjusted through a summary regulatory process or an existing formula-based mechanism. In some regulatory regimes, customers with demand above an established level are unregulated and can choose to contract directly with the utility or with other retail energy suppliers and pay non-bypassable fees, which are fees to the distribution company for use of its distribution system.


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The regulated tariff generally recognizes that our utility businesses should recover certain operating and fixed costs, as well as manage uncollectible amounts, quality of service and technical and non-technical losses. Utilities, therefore, need to manage costs to the levels reflected in the tariff, or risk non-recovery of costs or diminished returns.

Seasonality, Weather Variations, and Economic Activity — Our utility businesses are generally affected by seasonal weather patterns and, therefore, operating margin is not generated evenly throughout the year. Additionally, weather variations may also have an impact based on the number of customers, temperature variances from normal conditions, and customers' historic usage levels and patterns. Retail sales, after adjustments for weather variations, are also affected by changes in local economic activity, energy efficiency and distributed generation initiatives, as well as the number of retail customers.

Reliability of Service — Our utility businesses must meet certain reliability standards, such as duration and frequency of outages. Those standards may be explicit, with defined performance incentives or penalties, or implicit, where the utility must operate to meet customer and/or regulator expectations.

Development and Construction

We develop and construct new generation facilities. For our utility business, new plants may be built or existing plants retrofitted in response to customer needs or to comply with regulatory developments. The projects are developed subject to regulatory approval that permits recovery of our capital cost and a return on our investment. For our generation businesses, our priority for development is in key growth markets, where we can leverage our global scale and synergies with our existing businesses by adding renewable energy. We make the decision to invest in new projects by evaluating the strategic fit, financial profile, projected returns and risk for the investment and against alternative uses of capital, including corporate debt repayment.

In most cases, we enter into long-term contracts for output from new facilities prior to commencing construction. To limit required equity contributions from The AES Corporation, we also seek non-recourse project debt financing and other sources of capital, including partners, when it is commercially attractive. We typically contract with a third party to manage construction, although our construction management team supervises the construction work and tracks progress against the project's budget, schedule, 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 businesses internally and is mainly organized by technology.

We are organized into four technology-oriented SBUs: Renewables (solar, wind, energy storage, and hydro generation facilities); Utilities (AES Indiana, AES Ohio, and AES El Salvador regulated utilities and their generation facilities); Energy Infrastructure (natural gas, LNG, coal, pet coke, diesel, and oil generation facilities, and our businesses in Chile); and New Energy Technologies (green hydrogen initiatives and investments in Fluence, Uplight, and 5B) — which are led by our SBU Presidents.

We have two lines of business: generation and utilities. Our Renewables, Utilities, and Energy Infrastructure SBUs participate 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 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. Our New Energy Technologies SBU includes investments in new and innovative technologies to support leading-edge greener energy solutions.

We measure the operating performance of our SBUs using Adjusted EBITDA, a non-GAAP measure. The Adjusted EBITDA by SBU for the year ended December 31, 2023 is shown below. The percentages for Adjusted EBITDA are the contribution by each SBU to the gross metric, i.e., the total Adjusted EBITDA by SBU, before deductions for Corporate. Our New Energy Technologies SBU generated losses for the year ended December 31, 2023. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted EBITDA.


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For financial reporting purposes, the Company's corporate activities are reported within "Corporate and Other" because they do not require separate disclosure. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 18—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure.


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(1) Non-GAAP measure. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis—Non-GAAP Measures for reconciliation and definition.

Renewables


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Our Renewables SBU is the highest growth segment for AES, adding 4.9 GW to our contracted backlog during 2023, including 1.2 GW with large technology companies.

Specifically, demand from data centers in the U.S. is expected to nearly double in the next three years as generative artificial intelligence use-cases expand. Our well-established relationships with these customers, combined with our proven track record of delivering our projects, positions us well to take advantage of this opportunity.

The Renewables SBU has generation facilities in ten countries — the United States, Brazil, Argentina, Colombia, Mexico, Panama, Bulgaria, the Dominican Republic, Jordan, and the Netherlands.

Generation — Total operating installed capacity of the Renewables SBU is 16,211 MW. The following table lists our Renewables SBU generation facilities:


Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
AES Brasil Operacoes (AES Tietê) (1)	Brazil	Hydro	2,658	47	%	1999	2032	Various
Alicura (9)	Argentina	Hydro	1,050	100	%	2000
Chivor	Colombia	Hydro	1,000	99	%	2000	2024-2039	Various
OpCo A (2)	US-Various	Solar	967	26	%	2017-2019	2028-2046	Various
	Wind	140
New York Wind (OpCo D) (3)	US-NY	Wind	612	75	%	2021		NYISO
AES Renewable Holdings (3)	US-Various	Solar	414	100	%	2015-2023	2029-2042	Utility, Municipality, Education, Non-Profit
	Energy Storage	90
Spotsylvania Solar Energy Center (OpCo B) (2)	US-VA	Solar	485	26	%	2020-2021	2035	Apple, Akami, Etsy, Microsoft
Ventos do Araripe, Caetes & Cassino (Cubico II)	Brazil	Wind	456	47	%	2022	2034-2035	Various, CCEE
Alto Sertão II	Brazil	Wind	386	36	%	2017	2033-2035	Various, CCEE
Cajuina 1	Brazil	Wind	314	36%-47%		2023	2035-2043	Various
Mesa La Paz (2)	Mexico	Wind	306	50	%	2019	2045	Fuentes de Energia Peñoles
McFarland A (4)	US-AZ	Solar	200	75	%	2023	2038	BP
	Energy Storage	100
Cajuina 2	Brazil	Wind	296	36%-47%		2023	2044	Various
OpCo B (2)	US-Various	Solar	260	26	%	2019	2039-2044	Various
Bayano	Panama	Hydro	260	49	%	1999	2030	ENSA, Edemet, Edechi, Other
Chevelon Butte (OpCo D) (3)	US-AZ	Wind	238	75	%	2023	2043	APS
Buffalo Gap II (3)	US-TX	Wind	233	100	%	2007
Baldy Mesa (4)	US-CA	Solar	150	75	%	2023	2043	Amazon
	Energy Storage	75
Changuinola	Panama	Hydro	223	90	%	2011	2030	AES Panama
Great Cove 1&2 (4)	US-PA	Solar	220	75	%	2023	2043	University of Pennsylvania
Raceway 1	US-CA	Solar	125	50	%	2023	2043	Microsoft
	Energy Storage	80
Prevailing Winds (OpCo B) (2)	US-SD	Wind	200	26	%	2020	2050	Prevailing Winds
Oak Ridge (4)	US-LA	Solar	200	75	%	2023	2043	Amazon
Ventus	Brazil	Wind	187	36	%	2020	2034	CCEE
Skipjack (OpCo D) (3)(4)	US-VA	Solar	175	75	%	2022	2036	Exelon Generation Company
Buffalo Gap III (3)	US-TX	Wind	170	100	%	2008
Tucano Phase 2	Brazil	Wind	161	47	%	2023	2036	Anglo American
Mandacaru and Salinas	Brazil	Wind	159	47	%	2021	2033-2034	CCEE
St. Nikola	Bulgaria	Wind	156	89	%	2010	2025	Electricity Security Fund
Tucano Phase 1	Brazil	Wind	155	24	%	2022-2023	2042	Unipar
Guaimbê	Brazil	Solar	150	36	%	2018	2037	CCEE


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Lancaster Area Battery (LAB) (3)(4)		US-CA		Energy Storage	127	75	%	2022	2037	PG&E
Buffalo Gap I (3)		US-TX		Wind	121	100	%	2006
Chiriqui-Esti		Panama		Hydro	120	49	%	2003	2030	ENSA, Edemet, Edechi, Other
Cavalier (4)		US-VA		Solar	116	75	%	2023	2043	Dominion Energy
Delta (4)		US-MS		Wind	104	75	%	2023	2043	Amazon
Cabra Corral		Argentina		Hydro	102	100	%	1995		Various
Southland Energy—Alamitos Energy Center (5)		US-CA		Energy Storage	100	50	%	2021	2041	Southern California Edison
East Line Solar (OpCo B) (2)		US-AZ		Solar	100	26	%	2020	2045	Salt River Project
Central Line (OpCo B) (2)		US-AZ		Solar	100	26	%	2022	2039	Salt River Project Agricultural Improvement & Power District
West Line (OpCo B) (2)		US-AZ		Solar	100	26	%	2022	2047	Salt River Project Agricultural Improvement & Power District
Luna (3)		US-CA		Energy Storage	100	75	%	2022	2037	Clean Power Alliance of Southern California
Vientos Bonaerenses		Argentina		Wind	100	100	%	2020	2024-2040	Various
Vientos Neuquinos		Argentina		Wind	100	100	%	2020	2024-2040	Various
Laurel Mountain Repowering (OpCo D) (4)		US-WV		Wind	99	75	%	2022	2037	AES Solutions Management, LLC
McFarland B (4)		US-AZ		Solar	60	75	%	2023	2043	Amazon
		Energy Storage		30
Estrella		US-CA		Solar	56	50	%	2023	2038	Southern California Edison
		Energy Storage		28
Platteview (4)		US-NE		Solar	81	75	%	2023	2043	Omaha Public Power District
Clover Creek (OpCo B) (2)		US-UT		Solar	80	50	%	2021	2046	UMPA
Westwing 1 (4)		US-AZ		Energy Storage	77	75	%	2023	2043	APS
AGV Solar		Brazil		Solar	76	36	%	2019	2040	Various, CCEE
OpCo C (3)		US-Various		Solar	73	50	%	2021-2022	2041-2042	Various
Boa Hora		Brazil		Solar	69	47	%	2019	2038	CCEE
Mountain View Repowering (OpCo D) (3)(4)		US-CA		Wind	67	75	%	2022	2042	Southern California Edison
San Fernando		Colombia		Solar	61	99	%	2021	2036	Ecopetrol
Big Island Waikoloa (OpCo E) (3)(6)		US-HI		Solar	30	100	%	2022-2023	2047	HECO
	Energy Storage		30
Penonome I		Panama		Wind	55	49	%	2020	2030	ENSA, Edemet, Edechi
Chiriqui-Los Valles		Panama		Hydro	54	49	%	1999	2030	ENSA, Edemet, Edechi, Other
Bayasol		Dominican Republic		Solar	50	65	%	2021	2036	Ede Sur
Agua Clara		Dominican Republic		Wind	50	65	%	2022	2039	Ede Norte
Santanasol		Dominican Republic		Solar	50	65	%	2022	2038	Ede Sur
Mountain View IV (OpCo E) (6)		US-CA		Wind	49	100	%	2012	2032	Southern California Edison
Chiriqui-La Estrella		Panama		Hydro	48	49	%	1999	2030	ENSA, Edemet, Edechi, Other
AM Solar (7)		Jordan		Solar	48	36	%	2019	2039	National Electric Power Company
Ullum		Argentina		Hydro	45	100	%	1996		Various
Lawa'i (3)(6)		US-HI		Solar	20	100	%	2018	2043	Kaua'i Island Utility Cooperative
	Energy Storage		20
OpCo D (2)		US-Various		Solar	38	75	%	2022-2023	2042-2043	Various
		Energy Storage		2


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Kuihelni (4)	US-HI		Solar		14.5	100	%	2023	2048	HECO
		Energy Storage		14.5
Kekaha (3)(6)	US-HI		Solar		14	100	%	2019	2045	Kaua'i Island Utility Cooperative
	Energy Storage		14
Brisas	Colombia		Solar		27	99	%	2022	2037	Ecopetrol
West Oahu Solar (6)	US-HI		Solar		12.5	100	%	2023	2048	HECO
	Energy Storage		12.5
Na Pua Makani (6)	US-HI		Wind		24	100	%	2020	2040	HECO
Ilumina	US-PR		Solar		24	100	%	2012	2037	LUMA Energy
Castilla	Colombia		Solar		21	99	%	2019	2034	Ecopetrol
Tunjita	Colombia		Hydro		20	99	%	2016	2024-2039	Various
Laurel Mountain ES	US-WV		Energy Storage		16	100	%	2011
Community Energy (4)	US-Various		Solar		14	75	%	2022	2024-2043	Various
Southland Energy—AES Gilbert (Salt River (5) (8)	US-AZ		Energy Storage		10	50	%	2019	2039	Salt River Project Agricultural Improvement & Power District
El Tunal	Argentina		Hydro		10	100	%	1995		Various
Andres ES	Dominican Republic		Energy Storage		10	65	%	2017
Los Mina DPP ES	Dominican Republic		Energy Storage		10	65	%	2017
Pesé Solar	Panama		Solar		10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Mayorca Solar	Panama		Solar		10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Cedro	Panama		Solar		10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Caoba	Panama		Solar		10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Netherlands ES	Netherlands		Energy Storage		10	100	%	2015
Warrior Run ES	US-MD		Energy Storage		5	100	%	2016
5B Costa Norte	Panama		Solar		1	100	%	2021	2051	Costa Norte LNG Terminal
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(1)AES Tietê hydro plants: Água Vermelha (1,396 MW), Bariri (143 MW), Barra Bonita (141 MW), Caconde (80 MW), Euclides da Cunha (109 MW), Ibitinga (132 MW), Limoeiro (32 MW), Mog-Guaçu (7 MW), Nova Avanhandava (347 MW), Promissão (264 MW), Sao Joaquim (3 MW) and Sao Jose (4 MW).

(2)Unconsolidated entity, accounted for as an equity affiliate.

(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 or Redeemable stock of subsidiaries in the Company's Consolidated Balance Sheets, depending on the partnership rights of the specific project.

(4)Owned by ACED.

(5)On December 1, 2022, Southland Energy sold an additional 14.9% ownership interest in the Southland Energy assets. Following the sale, AES holds 50.1% of Southland Energy's interest and this business continues to be consolidated by AES.

(6)Owned by AES Renewable Holdings.

(7)Announced the sale of 26% of our interest in this business in November 2020.

(8)Facility experienced a fire event in April 2022 which rendered the asset currently inoperable.

(9)Operated by AES under a concession contract granted for a term of 30 years, which was set to expire on August 11, 2023. In accordance with the contract, the concession could be extended with a transitional period up to a maximum of 12 months. The Energy Secretariat has enacted several resolutions since the contractual expiration date extending it until March 18, 2024. Once its term expires, the ownership and possession of the power plant equipment will be transferred by full right to the National State in its capacity as grantor.


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Under construction — The majority of projects under construction have executed long-term PPAs or, as applicable, have been assigned tariffs through a regulatory process. The following table lists our plants under construction in the Renewables SBU:


Business	Location	Fuel	Gross MW	AES Equity Interest		Expected Date of Commercial Operations
High Mesa (1)	US-CO	Solar	10	75	%	1H 2024
	Energy Storage	10
Westwing 1 (1)	US-AZ	Energy Storage	3	75	%
Delta (1)	US-MS	Wind	81	75	%	1H 2024
Chevelon Butte Phase II (1)	US-AZ	Wind	216	75	%	1H 2024
Kuihelni (2)	US-HI	Solar	45	100	%	1H 2024
	Energy Storage	45
Cajuína 2	Brazil	Wind	74	47	%	1H 2024
Tucano Phase 2	Brazil	Wind	6	47	%	1H 2024
Mirasol 1&2	Dominican Republic	Solar	100	65	%	1H 2024
AES Clean Energy Development	US-Various	Solar	69	75	%	1H-2H 2024
	Energy Storage	7
McFarland B (1)	US-AZ	Solar	240	75	%	2H 2024
	Energy Storage	120
Cavalier (1)	US-VA	Solar	40	75	%	2H 2024
Alamitos 2	US-CA	Energy Storage	82	100	%	2H 2024
Cavalier Solar A2 (1)	US-VA	Solar	84	75	%	2H 2024
Waiwa Phase 2 (1)	US-HI	Solar	30	75	%	2H 2024
	Energy Storage	30
Peravia I	Dominican Republic	Solar	70	65	%	2H 2024
Calhoun	US-MI	Solar	125	75	%	2H 2024
Mamm Creek	US-CO	Solar	10	75	%	2H 2024
	Energy Storage	10
AGV VII	Brazil	Solar	33	47	%	2H 2024
Los Santos Solar	Panama	Solar	8	49	%	2H 2024
Corotu Solar	Panama	Solar	10	49	%	2H 2024
Esti Solar II	Panama	Solar	18	49	%	2H 2024
Rexford	US-CA	Solar	300	100	%	2H 2024-1H 2025
	Energy Storage	240
Morris Solar	US-MO	Solar	250			1H 2025
Bellefield Phase 1 (1)	US-CA	Solar	500	75	%	2H 2025
	Energy Storage	500
			3,366

(1)Owned by ACED.

(2)Owned by AES Renewable Holdings.

AES Clean Energy

Business Description — AES' U.S. renewables portfolio, referred to as AES Clean Energy, is the leading U.S. renewables growth platform in serving large corporations with its 51 GW development pipeline. AES Clean Energy aims to solve customers' energy challenges by offering an expanded portfolio of innovative solutions based on cutting-edge technologies that are designed to accelerate customers' transitions to carbon-free energy. The generation capacity of the systems owned and/or operated under AES Clean Energy is 6,964 MW across the U.S., with another 3,121 MW under construction, including 1,725 MW of solar, 297 MW of wind, and 1,099 MW of energy storage. AES Clean Energy has a 6.1 GW backlog of projects, the majority of which are expected to come online through 2025. The adoption of the Inflation Reduction Act ("IRA") in 2022 and the expansion of data center needs related to the growing use of generative artificial intelligence are expected to be a significant accelerant to the growth of the U.S. renewables market and AES seeks to capture a significant portion of this market expansion.

AES Clean Energy comprises AES Renewable Holdings, sPower, ACED, and other renewable assets, as part


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of its broader investments in the U.S. ACED was formed on February 1, 2021, as specifically identified projects in the sPower and AES Renewable Holdings development platforms were merged. ACED serves as the development vehicle for all future renewables projects in the U.S. Following the merger, ACED expanded through the acquisitions of the Valcour Intermediate Holdings wind platform and Community Energy, a U.S. solar developer, as well as the acquisition of a small wind team and multiple development projects, most notably Bellefield in 2023. AES Clean Energy has also grown organically at a rapid pace and now has more than 1,300 employees, in contrast to less than 500 employees at the time of its formation in 2021 as it has expanded its capabilities and geographic reach to better serve the needs of the growing U.S. market. During the same time period, the development pipeline has also more than doubled.

In line with AES' strategy of using partnerships to promote the effective deployment of capital, in February 2023, the Company sold 49% of its indirect interest in a 1.3 GW portfolio of sPower's operating assets ("OpCo B") that includes 17 solar projects and one wind project, located across six states, to Hannon Armstrong Sustainable Infrastructure Capital, Inc. ("HASI"). Further, in December 2023, AES Renewable Holdings issued preferred shares in a portfolio of approximately 605 MW across 200 solar and solar plus storage assets ("OpCo 1") operating across eleven states to HASI.

Key Financial Drivers — The financial results of AES Clean Energy are primarily driven by the efficient construction and operation of renewable energy facilities across the U.S. under long-term PPAs, through which the energy price on the entire production of these facilities is determined. Tax credits associated with the development of U.S. renewables projects can be substantial and have increased with the adoption of the IRA. In 2023, AES recognized $611 million of pre-tax contribution related to the monetization of tax attributes to tax equity investors and transferability tax credit buyers relating to U.S. renewables projects,$18 million of which relates to a solar project owned by our utility at AES Indiana. The financial results of U.S. renewable assets are primarily driven by the amount of wind or solar resource at the facilities, availability of facilities, growth in projects, and by tax credit recognition once placed in service.

A majority of solar projects under AES Clean Energy have been financed with tax equity structures. Under these tax equity structures, the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could result in variability to earnings attributable to AES compared to the earnings reported at the facilities. In 2023, AES Clean Energy largely generated investment tax credits ("ITCs") from its renewable assets. We expect that the extension of the current ITCs and production tax credits ("PTCs"), as well as higher credits available for projects that satisfy wage and apprenticeship requirements under the IRA, will increase demand for our renewable products. Also in 2023, AES Clean Energy monetized tax credits under the transferability provisions of the IRA for the first time. These tax credit sales reduce our tax rate under U.S. GAAP.

Buffalo Gap I, 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. For these projects, ERCOT power prices impact financial results. The Alamitos Energy Storage Facility is a 100 MW interconnected battery-based energy storage facility located in California that operates under 20-year tolling agreements with Southern California Edison.

Development Strategy — As states, communities, and organizations of all types make commitments and plan to reduce their carbon footprints, renewables are the fastest-growing source of electricity generation in the U.S. AES Clean Energy works with its customers to co-create and deliver the smarter, greener energy solutions that meet their needs, including 24/7 carbon-free energy. For example, AES has worked with several major technology companies to provide clean energy solutions to power their network of data centers and we see these relationships growing as utilization of generative artificial intelligence drives the expansion of data center use.

In 2023, AES Clean Energy signed or was awarded 4,770 MW of PPAs. As of December 31, 2023, AES Clean Energy's renewables project backlog includes 6.1 GW 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 $5 billion. The IRA includes increases, extensions, and/or new tax credits for onshore wind, solar, storage, and hydrogen projects. These changes in tax policy are supportive of our strategy to grow the AES Clean Energy business through development of our 51 GW U.S. pipeline.

AES Brasil


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Business Description — AES Brasil is a publicly traded company in Brazil. AES controls and consolidates AES Brasil through its 47% economic interest. With an exclusive focus on renewable energy, AES Brasil has strategically positioned plants across the country to supply energy to customers and the regulated market. Leveraging hydro, solar, and wind generation, AES Brasil has been a key player in the Brazilian energy sector for nearly 25 years.

As a 100% renewable energy generator, AES Brasil holds a diversified portfolio and has expanded from an installed capacity of 2.7 GW in 2016 to 5.2 GW in 2023, which is composed by hydroelectric plants (2,658 MW) operating under a 33-year concession expiring in 2032, wind complexes (2,194 MW) and solar complexes (328 MW), equivalent to 52%, 42% and 6%, respectively. Among these, 5.1 GW are already operational and 113 MW are under construction.

AES Brasil aims to contract most of its physical guarantee requirements and sell the remaining portion in the spot market. The commercial strategy is reassessed periodically according to changes in market conditions, hydrology, and other factors. AES Brasil generally sells available energy through medium-term bilateral contracts.

Key Financial Drivers — The electricity market in Brazil is highly dependent on hydroelectric generation, therefore electricity pricing is driven by hydrology. AES Brasil owns 12 hydroelectric power plants in the state of São Paulo, which represents approximately 2% of the hydropower physical guarantee of the hydrological risk sharing system (Energy Reallocation Mechanism or "MRE", as described below in the topic International Energy Markets and Regulatory Environment). Plant availability is also a significant financial driver as in times of high hydrology, AES is more exposed to the spot market. AES Brasil's financial results are driven by many factors, including, but not limited to:

hydrology, impacting quantity of energy generated in the MRE;
expansion in the demand for energy, especially considering the market opening in the years ahead;
market price risk when re-contracting;
effective asset management;
efficient cost management; and
successful execution on its growth strategy*.*

Development Strategy — AES Brasil's strategy is to grow by adding renewable capacity to its generation platform through acquisition or greenfield projects, to focus on client satisfaction and innovation to offer new products and energy solutions, and to be recognized for excellence in asset management.

Under the current terms of the 2018 legal agreement in connection with AES Brasil's concession with the state government, AES Brasil is required to increase its capacity in the state of São Paulo by an additional 28 MW by October 2024. On November 30, 2021, AES Brasil acquired AGV VII Solar project with an under construction installable capacity of 33 MW of solar generation, that is expected to be concluded in 2024.

AES Argentina

Business Description — AES operates plants in Argentina within the Renewables SBU totaling 1,407 MW, representing 3% of the country's total installed capacity, and AES Argentina's plants are placed in strategic locations within the country in order to provide energy to the spot market and customers.

AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2023, approximately 76% of the energy sold in the wholesale electricity market was produced by the hydropower plants, and 24% generated by the wind power plants.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:

forced outages;
exposure to fluctuations of the Argentine peso;
timely collection of FONINVEMEM installments and outstanding receivables (see International Energy Markets and Regulatory Environment below);
changes in hydrology and wind resources; and
domestic energy demand and exports.

Development Strategy — AES Argentina has a pipeline of 753 MW of wind and solar greenfield projects in different stages of development. These projects are adjacent or nearby to AES Argentina's current operating assets and will be used to participate in future private auctions for renewable PPAs.


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AES Colombia

Business Description — We operate in Colombia through AES Colombia, a subsidiary of AES Andes, which owns Chivor, a hydroelectric plant with an installed capacity of 1,000 MW and Tunjita, a 20 MW run-of-river hydroelectric plant, both located approximately 100 miles east of Bogota, as well as the solar facilities of Castilla, Brisas, and San Fernando, 21 MW, 27 MW, and 61 MW respectively. AES Colombia’s installed capacity accounted for approximately 6% of system capacity at the end of 2023. AES Colombia is dependent on hydrological conditions, which influence generation and spot prices of non-contracted generation in Colombia.

AES Colombia'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 Colombia receives reliability payments for maintaining the plant's availability and generating firm energy during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.

Key Financial Drivers — Hydrological conditions largely influence Chivor's power generation. Maintaining the appropriate contract level, while maximizing revenue through the sale of excess generation, is key to AES Colombia's results of operations. In addition to hydrology, financial results are driven by many factors, including, but not limited to:

forced outages;
fluctuations of the Colombian peso; and
spot market prices.

Development Strategy — AES Colombia is committed to 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. Six wind projects totaling 1,149 MW are located in La Guajira, one of the windiest spots in the world. Of the 1,149 MW, 255 MW were awarded a 15-year PPAs in the renewable auction in 2019.

AES Panama

Business Description — AES owns and operates five hydroelectric plants totaling 705 MW of generation capacity, a wind farm of 55 MW and four solar plants of 10 MW each, which collectively represent 20% of the total installed capacity in Panama.

The majority of our hydroelectric plants in Panama are based on run-of-the-river technology, with the exception of 223 MW Changuinola plant with regulation reservoirs and 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 and wind generation since its behavior is opposite and complementary to hydro generation.

Our hydro assets are mainly contracted through medium to long-term PPAs with distribution companies, while a small volume of our hydro plants are contracted with unregulated users. Our hydro assets in Panama have PPAs with distribution companies expiring up to December 2030 for a total contracted capacity of 350 MW.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:

changes in hydrology, which impacts spot prices and exposes the business to variability in the cost of replacement power;
fluctuations in commodity prices, mainly fuel oil and natural gas, which affect the cost of thermal generation and spot prices;
constraints imposed by the capacity of transmission lines connecting the west side of the country with the load, keeping surplus power trapped during the rainy season; and
country demand as GDP growth is expected to remain stable over the short and medium term.

Development Strategy — AES is investing in renewables projects within the region. This will increase complementary non-hydro renewable assets in the system and contribute to the reduction of hydrological risk in Panama.

AES Mexico

Business Description — Mesa La Paz is a 306 MW wind project developed under a joint venture with Grupo


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Bal, located in Llera, Tamaulipas. Mesa La Paz sells 72% of its power under long-term PPAs expiring up to 2045.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:

contracting levels, providing additional benefits from improved operational performance, including performance incentives and/or excess energy sales;
changes in the methodology to calculate spot energy prices or Locational Marginal Prices, which impacts the excess energy sales;
improved operational performance and plant availability; and
changes in wind resources.

Development Strategy — AES has partnered with Grupo Bal in a joint venture to co-invest in power and related infrastructure projects in Mexico, focusing on renewable generation.

AES Bulgaria

Business Description — AES owns an 89% economic interest in the St. Nikola wind farm ("Kavarna") 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 may receive additional revenue per the terms of an October 2018 Contract for Premium with the state-owned Electricity System Security Fund.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:

regulatory changes in the Bulgarian power market;
availability and load factor of the operating units;
the level of wind resources; and
spot market price volatility beyond the level of compensation through the Contract for Premium.

In December 2022, Bulgaria implemented Regulation 2022/1854, approved by the European Council in October 2022 as an emergency intervention aiming at limiting energy prices in Europe. The main measure of interest to AES in Bulgaria is the limitation of revenues for "infra-marginal" producers, a category that includes renewables and other technologies which are providing electricity to the grid at a cost below the price level set by the more expensive “marginal” producers. For renewable plants such as Kavarna which are operating under a Contract for Premium, the regulation essentially captures 90% of the incremental margin of the wind farm when wholesale prices are above their original Feed in Tariff of €96.27/MWh. This regulation has been extended until the end of 2024 by the Bulgarian Parliament.

AES Dominicana

Business Description — AES Dominicana has three operating subsidiaries within the Renewables SBU, each of which are owned 65% by AES. Bayasol owns and operates a 50 MW solar farm, Santanasol operates a 50 MW solar farm, and Agua Clara operates a 50 MW wind farm.

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. In December 2023, AES completed the sale of an additional 10% ownership interest in AES Dominicana to the existing partners and a 10% interest to Grupo Popular's subsidiary, AFI Popular, selling 20% ownership interest in total. After this transaction, AES' ownership interest in AES Dominicana is 65%.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:

change in wind and solar resources due to heavy rains, hurricanes and other natural events that may affect the country;
constraints imposed by the capacity of transmission lines and potential delays on the transmission expansion projects; and
related to projects under construction, changes in execution cost and scope of work that may delay the operation of the new renewable plants.

AES Puerto Rico

Business Description — AES Puerto Rico owns and operates Ilumina, a 24 MW solar facility in Puerto Rico. The plant is fully contracted through a long-term PPA with PREPA expiring in 2037. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—


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Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPAs with PREPA.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to, operational performance and plant availability.

Development Strategy — Puerto Rico has clear goals of supplying its system from renewable resources, with targets of 40% from renewables by 2025 and 100% by 2050. To achieve the established target of 40%, PREPA intends to launch six tender processes for renewable generation in the coming years. Clean Flexible Energy LLC, the legal entity that AES is utilizing to develop renewables in Puerto Rico, expects to have a portfolio of solar and energy storage projects participating. On November 30, 2023, for the first tender process, Clean Flexible Energy, LLC and PREPA closed solar plus storage agreements for a total of 400 MW, which must reach COD within 24 months.

AES Jordan

Business Description — In Jordan, AES has a 36% controlling interest in a 48 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 this business.


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(1) Non-GAAP measure. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis—Non-GAAP Measures for reconciliation and definition.


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Utilities

Our Utilities SBU is the second largest contributor to our future growth, particularly in the U.S., where we are targeting a combined 10% annual growth in rate base at our two utilities: AES Indiana and AES Ohio. In this segment, we also have four utilities in El Salvador and a portfolio of generation facilities, including at our integrated utility in Indiana, with installed operating capacity of 3,500 MW. IPALCO (AES Indiana's parent), AES Ohio, and DPL Inc. (AES Ohio's parent) are all SEC registrants, and as such, follow the public filing requirements of the Securities Exchange Act of 1934.

Utilities — The following table lists our utilities and their generation facilities:


Business	Location	Type	AES Equity Interest		Approximate Number of Customers Served as of 12/31/2023	Approximate GWh Sold in 2023	Fuel	Gross MW	Year Acquired or Began Operation
CAESS	El Salvador	Distribution	75	%	659,000	2,214			2000
CLESA	El Salvador	Distribution	80	%	475,000	1,143			1998
DEUSEM	El Salvador	Distribution	74	%	95,000	174			2000
EEO	El Salvador	Distribution	89	%	357,000	762			2000
El Salvador Subtotal					1,586,000	4,293
AES Ohio (1)	US-OH	Transmission & Distribution	100	%	539,000	13,305			2011
AES Indiana (2)	US-IN	Integrated	70	%	523,000	14,127	Coal/Gas/Oil/Solar/Energy Storage	3,357	2001
United States Subtotal					1,062,000	27,432		3,357
					2,648,000	31,725

(1)AES Ohio's GWh sold in 2023 represent total transmission and distribution sales. AES Ohio's wholesale sales and SSO utility sales, which are sales to utility customers who use AES Ohio to source their electricity through a competitive bid process, were 3,183 GWh in 2023. AES Ohio 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. AES Ohio’s share of this generation is approximately 103 MW.

(2)CDPQ owns direct and indirect interests in IPALCO (AES Indiana's parent) which total approximately 30%. AES owns 85% of AES US Investments and AES US Investments owns 82.35% of IPALCO. AES Indiana plants: Georgetown, Harding Street, Petersburg and Eagle Valley. 20 MW of AES Indiana total is considered a transmission asset. In December 2023, the first stage of construction for the 195 MW Hardy Hills solar project was completed and initial operations for over half of the project commenced. The remaining MW are expected to be placed in service in 2024.

Generation — The following table lists our Utilities SBU generation facilities. The energy produced by these generation facilities is fully contracted by AES’ utilities in El Salvador.


Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Bosforo (1)	El Salvador	Solar	100	50	%	2018-2019	2043-2044	CAESS, EEO, CLESA, DEUSEM
Metapan	El Salvador	Solar	15	100	%	2043-2048	2033	CLESA, Cemento Holcim de El Salvador
Cuscatlan Solar (1)	El Salvador	Solar	10	50	%	2021	2046	CLESA
AES Nejapa	El Salvador	Landfill Gas	6	100	%	2011	2035	CAESS
Meangura del Gofo	El Salvador	Solar	1	100	%	2023	2048	EEO
	Energy Storage	4
Opico	El Salvador	Solar	4	100	%	2020	2040	CLESA
Moncagua	El Salvador	Solar	3	100	%	2015	2035	EEO
			143

(1)Unconsolidated entity, accounted for as an equity affiliate.


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Under construction — The following table lists our plants under construction in the Utilities SBU:


Business	Location	Fuel	Gross MW	AES Equity Interest		Expected Date of Commercial Operations
Hardy Hills Solar (AES Indiana) (1)	US-IN	Solar	80	70	%	1H 2024
Pike County (AES Indiana)	US-IN	Energy Storage	200	70	%	2024
Petersburg Energy Center (AES Indiana)	US-IN	Solar	250	70	%	2H 2025
	Energy Storage	45
			575

(1)In December 2023, the first stage of construction of this project was completed and initial operations for over half of the project commenced. The final stage of construction is expected to be completed during the first half of 2024.

AES Indiana

Business Description — IPALCO is a holding company whose principal subsidiary is AES Indiana. 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. AES Indiana 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 969,000 people.

AES Indiana owns and operates four generating stations, all within the state of Indiana. The first station, Petersburg, is coal-fired, and consists of four units. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (see Integrated Resource Plan below). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery-based energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. In addition, AES Indiana helps meet its customers' energy needs with long-term contracts for the purchase of 300 MW of wind-generated electricity and 94 MW of solar-generated electricity.

In December 2021, AES Indiana completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills solar project"). In December 2023, the first stage of construction for the Hardy Hills solar project was completed and initial operations for over half of the project commenced. The final stage of construction of the project is expected to be completed during the first half of 2024.

In August 2023, AES Indiana completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center project"). The Petersburg Energy Center project is expected to be completed in 2025.

In June 2023, AES Indiana executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS project is expected to be completed in 2024.

In July 2023, AES Indiana executed a purchase agreement for the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana, subject to IURC approval, which was received in January 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.

Key Financial Drivers — AES Indiana's financial results are driven primarily by retail demand, weather, and maintenance costs. In addition, AES Indiana's financial results are likely to be driven by many other factors 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 and operation and maintenance costs.

Regulatory Framework and Market Structure — AES Indiana 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 AES Indiana's business is typical of regulation


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generally imposed by state public utility commissions. The IURC sets tariff rates for electric service provided by AES Indiana. The IURC considers all allowable costs for ratemaking purposes, including a fair return on assets used and useful to providing service to customers.

AES Indiana's tariff rates for electric service to retail customers consist of basic rates and approved charges. In addition, AES Indiana'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 AES Indiana's retail load requirements, referred to as the Fuel Adjustment Charge, (ii) a rider for the timely recovery of costs incurred to comply with environmental laws and regulations, including a return, (iii) a rider to reflect changes in ongoing RTO costs, (iv) riders for passing through to customers wholesale sales margins and capacity sales above and below established annual benchmarks, (v) a rider for a return on, and of, investments for eligible TDSIC improvements, and (vi) a rider for cost recovery, lost margin recoveries and performance incentives from AES Indiana's demand side management energy efficiency programs. Each of these tariff rate components function somewhat independently of one another, but the overall structure of AES Indiana's rates is subject to review at the time of any review of AES Indiana's basic rates and charges. Additionally, AES Indiana's rider recoveries are reviewed through recurring filings.

AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement to increase AES Indiana's annual revenues by $44 million, or 3% (the "2018 Base Rate Order"), which are the base rates under which AES Indiana is currently operating. 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.

AES Indiana is one of many transmission system owner members in MISO, an RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. AES Indiana offers electricity in the MISO day-ahead and real-time markets.

Development Strategy — AES Indiana's construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental regulations, along with discretionary investments designed to replace aging equipment or improve overall performance.

Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that requests for recovery include a plan of at least five years and not more than seven for 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 base 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 AES Indiana's seven-year TDSIC Plan for eligible transmission, distribution, and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on, and of,


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investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying cost, approved for TDSIC recovery as of December 31, 2023 was $400 million.

Integrated Resource Plan — In December 2022, AES Indiana filed its Integrated Resource Plan ("IRP"), which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4, however, AES Indiana expects to do so at the appropriate time. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors, and carbon capture are developed and cost effective, we will evaluate them in the future planning processes.

AES Indiana expects to spend an estimated $3.2 billion on capital projects from 2024 through 2026, which includes AES Indiana's power generation and renewable energy projects discussed above, spending under AES Indiana's TDSIC Plan, as well as other new transmission and distribution projects.

In December 2021 and 2022, AES Indiana received equity capital contributions of $275 million and $253 million, respectively, from AES and CDPQ on a proportional share basis to be used for funding needs related to AES Indiana’s TDSIC and replacement generation projects.

AES Ohio

Business Description — DPL is a holding company whose principal subsidiary is AES Ohio. AES Ohio is a utility company that transmits and distributes electricity to approximately 539,000 retail customers in a 6,000 square mile area of West Central Ohio and is subject to regulatory authority—see Regulatory Framework and Market Structure below. AES Ohio 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.

Key Financial Drivers — AES Ohio's financial results are driven primarily by retail demand and weather. AES Ohio'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 — AES Ohio 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, AES Ohio is required to provide retail generation service at SSO rates to any customer that has not signed a contract with a CRES provider or as a provider of last resort in the event of a CRES provider default. SSO rates are subject to rules and regulations of the PUCO and are established through a competitive bid process for the supply of power to SSO customers.

AES Ohio's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. AES Ohio 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. AES Ohio's retail rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred related to power purchased through the competitive bid process, participation in the PJM RTO, severe storm damage, and energy efficiency.


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The costs associated with providing high voltage transmission service and wholesale electric sales and ancillary services are subject to FERC jurisdiction. AES Ohio implemented a formula-based rate for its transmission service, effective May 3, 2020.

AES Ohio is a member of PJM, an RTO that operates the transmission systems owned by utilities operating in all or parts of a multi-state region, including Ohio. PJM also administers the day-ahead and real-time energy markets, ancillary services market and forward capacity market for its members.

Ohio law requires utilities to file either an Electric Security Plan ("ESP") or MRO plan to establish SSO rates. AES Ohio is currently operating pursuant to ESP 4, described in the paragraph below. From November 1, 2017 through December 18, 2019, AES Ohio operated pursuant to an approved ESP plan, which was initially approved in October, 2017 (ESP 3). On December 18, 2019, the PUCO approved AES Ohio's Notice of Withdrawal and reversion to its prior rate plan (ESP 1). Among other items, the PUCO Order approving the ESP 1 rate plan includes reinstating the non-bypassable RSC Rider, which provides annual revenues of approximately $79 million. The Office of the Ohio Consumers’ Council (“OCC”) has appealed to the Ohio Supreme Court, the Commission’s decision approving the reversion to ESP 1 as well as argued for a refund of the Rate Stabilization Charge ("RSC") revenues dating back to August 2021. A decision is pending regarding this appeal, which has been consolidated with the appeal regarding the Smart Grid Comprehensive Settlement described in the paragraph below. We are unable to predict the outcome of this appeal, but if this results in terms that are more adverse than AES Ohio's current ESP rate plan, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Smart Grid Comprehensive Settlement — In October 2020, AES Ohio entered into a Stipulation and Recommendation (settlement) with the staff of the PUCO and various customers, and organizations representing customers of AES Ohio and certain other parties with respect to, among other matters, AES Ohio's applications pending at the PUCO for (i) approval of AES Ohio's plan to modernize its distribution grid ("Smart Grid Phase 1"), (ii) findings that AES Ohio passed the Significantly Excessive Earnings Test ("SEET") for 2018 and 2019, and (iii) findings that AES Ohio's current ESP 1 satisfies the SEET and the more favorable in the aggregate ("MFA") regulatory test. In June 2021, the PUCO issued their opinion and order accepting the stipulation as filed. With the PUCO’s issuance of their opinion and order, AES made cash contributions of $150 million in 2021 to improve AES Ohio's infrastructure and modernize its grid while maintaining liquidity. The OCC appealed this final PUCO Order to the Ohio Supreme Court in December 2021; this appeal remains pending.

In February 2024, AES Ohio filed a Smart Grid Phase 2 with the PUCO proposing to invest approximately $683 million in capital projects over a 10-year period following the Smart Grid Phase 1, which ends June 2025. There are three principal components of AES Ohio’s Smart Grid Phase 2: 1) Distribution Operations, 2) Advanced Intelligence 3) Telecommunications and Cybersecurity. These initiatives will also allow AES Ohio to be ready to leverage and integrate Distributed Energy Resources into its grid. If approved, AES Ohio will implement a comprehensive grid modernization project that will deliver benefits to customers, society as a whole and to AES Ohio. A procedural schedule is expected that will provide for an Order by the second quarter of 2025 prior to the end of Smart Grid Phase 1.

On September 26, 2022, AES Ohio filed its latest ESP ("ESP 4") with the PUCO. ESP 4 is a comprehensive plan to enhance and upgrade its network and improve service reliability, provide greater safeguards for price stability and continue investments in local economic development. In April 2023, AES Ohio entered into a Stipulation and Recommendation with the PUCO Staff and seventeen parties (the “Settlement”) with respect to AES Ohio’s ESP 4 application, and, in August, 2023, the PUCO approved the Settlement without modification. The Settlement provides for a three-year ESP without a rate stability charge, and, in addition to other items, provides for (i) a Distribution Investment Rider for the term of the ESP allowing for the timely recovery of distribution investments by AES Ohio based on a 9.999% return on equity, subject to revenue caps, (ii) recovery of approximately $66 million related to past expenditures by AES Ohio plus future carrying costs and the recovery of incremental vegetation management expenses up to certain annual limits during the term of ESP 4; and (iii) funding of programs for assistance to low-income customers and for economic development. With approval of this Settlement, the distribution rates that were approved by the PUCO in December 2022, and are described in the paragraph below, became effective on September 1, 2023.

In November, 2020, AES Ohio filed a new distribution rate case application with the PUCO to increase AES Ohio’s base rates for electric distribution service to address, in part, increased costs of materials and labor and substantial investments to improve distribution structures. In December, 2022, the PUCO issued an order on the application. Among other matters, the order (i) establishes a revenue increase of $76 million for AES Ohio’s base rates for electric distribution service and (ii) provides for a return on equity of 9.999% and a cost of long-term debt of


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4.4% on a rate base of $783 million and based on a capital structure of 53.87% equity and 46.13% long-term debt. These rates went into effect on September 1, 2023 with the approval of AES Ohio’s ESP 4.

Development Strategy — Planned construction projects primarily relate to new investments in and upgrades to AES Ohio'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.

AES Ohio is projecting to spend an estimated $1.2 billion on capital projects from 2024 through 2026, which includes expected spending under AES Ohio's Smart Grid Phase 1 included in the Stipulation and Recommendation entered into in October 2020 (see Regulatory Framework and Market Structure above) as well as other new transmission and distribution projects.

AES 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 4,293 GWh of the market energy sales during 2023. AES El Salvador owns and operates four solar farms, Opico Power, Moncagua, and Metapan with 4 MW, 3 MW and 15 MW of capacity, respectively; Meanguera del Golfo, a solar and battery storage facility with 0.6 MW capacity; AES Nejapa, a biomass power plant with 6 MW capacity; and 50% of Bosforo and Cuscatlan Solar, solar farms with 100 MW and 10 MW capacity, respectively. The energy produced by these solar farms 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:

operational performance;
regulatory outcomes and impacts;
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.

Development Strategy — In order to explore new business opportunities, AES El Salvador created AES Soluciones, an LED public lighting service provider and the main commercial and industrial solar photovoltaic EPC provider in the country. Electromobilty is also being promoted by AES Soluciones through a partnership with Blink Charger in order to design and deploy a private network of electric chargers throughout the country. AES Next, Ltda de. C.V. is the O&M services provider for the Bosforo project, as well as a developer of solar MW in El Salvador. Furthermore, the four distribution companies operated by AES El Salvador started a digitization and modernization initiative as part of the development, sustainability, and growth strategy of the business.


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(1) Non-GAAP measure. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis—Non-GAAP Measures for reconciliation and definition.
(2) Through asset sales, fuel conversions and retirements, while maintaining reliability and affordability, and subject to necessary approvals. AES may delay the exit of a few select plants through 2027 to support continued electricity reliability.


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Energy Infrastructure

Our Energy Infrastructure SBU aims to provide energy security to enable the integration of new renewables, maximize the value of our gas generation and LNG business through flexible operations that support the energy transition, and exit coal generation to achieve our decarbonization targets. This segment comprises generation facilities, using natural gas, LNG, coal, pet coke, diesel, and/or oil, in nine countries — Vietnam, the United States, Argentina, Chile, Bulgaria, Mexico, Jordan, Panama and the Dominican Republic. Although our businesses in Chile have a mix of generation sources, including renewables, the generation from all sources is pooled to service our existing PPAs. Consequently all of Chile’s generation is included within the Energy Infrastructure SBU.

Generation — Operating installed capacity of our Energy Infrastructure segment totals 14,885 MW. The following table lists our Energy Infrastructure segment generation facilities:


Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Mong Duong 2 (1)	Vietnam	Coal	1,242	51	%	2015	2040	EVN
Southland—Alamitos	US-CA	Gas	1,200	100	%	1998	2026	California Department of Water Resources
Paraná-GT	Argentina	Gas/Diesel	870	100	%	2001
Southland Energy—Huntington Beach (3)	US-CA	Gas	694	50	%	2020	2040	Southern California Edison
Southland Energy—Alamitos (3)	US-CA	Gas	693	50	%	2020	2040	Southern California Edison
San Nicolás	Argentina	Coal/Gas/Oil/Energy Storage	691	100	%	1993
Maritza	Bulgaria	Coal	690	100	%	2011	2026	National Electric Company (NEK)
TermoAndes (4)	Argentina	Gas/Diesel	643	99	%	2000	2024-2025	Various
Guillermo Brown (5)	Argentina	Gas/Diesel	576	—	%	2016
Angamos	Chile	Coal	558	99	%	2011		Various
Cochrane	Chile	Coal	550	57	%	2016	2030-2037	SQM, Sierra Gorda, Quebrada Blanca
Ventanas	Chile	Coal	537	99	%	2010, 2013
Alto Maipo (2)	Chile	Hydro	531	99	%	2021	2040	Minera Los Pelambres
AES Puerto Rico	US-PR	Coal	524	100	%	2002	2027	LUMA Energy
Merida III	Mexico	Gas/Diesel	505	75	%	2000	2025	Comision Federal de Electricidad
Amman East (6)	Jordan	Gas	472	37	%	2009	2033	National Electric Power Company
Colon (7)	Panama	Gas	381	65	%	2018	2028	ENSA, Edemet, Edechi
DPP (Los Mina)	Dominican Republic	Gas	358	65	%	1996	2025	Ede Este, Ede Norte, Ede Sur, Non-Regulated Users
Andres (8)	Dominican Republic	Gas/Diesel	319	65	%	2003	2025	Ede Este, Ede Norte, Ede Sur, Non-Regulated Users
Andes 2b	Chile	Solar	180	99	%	2023		Various
	Energy Storage	112
Norgener	Chile	Coal	276	99	%	2000	2028	Codelco
Termoelectrica del Golfo (TEG)	Mexico	Pet Coke	275	99	%	2007	2027	CEMEX
Termoelectrica del Penoles (TEP)	Mexico	Pet Coke	275	99	%	2007	2027	Peñoles
IPP4 (6)	Jordan	Gas	250	36	%	2014	2039	National Electric Power Company
Cordillera Hydro Complex (9)	Chile	Hydro	240	99	%	2000	2042	Various
Southland—Huntington Beach	US-CA	Gas	236	100	%	1998	2026	California Department of Water Resources
Warrior Run (10)	US-MD	Coal	205	100	%	2000	2024	Potomac Edison
Bolero	Chile	Solar	146	99	%	2023	2030	Various
Los Olmos	Chile	Wind	110	51	%	2022	2032	Google, Various
Los Cururos	Chile	Wind	109	51	%	2019		Various
Andes Solar 2a	Chile	Solar	81	51	%	2021		Google, Various


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Mesamávida	Chile	Wind	68	51	%	2022	2038	Google, Various
Campo Lindo	Chile	Wind	65	51	%	2023		Various
Virtual Reservoir 2	Chile	Energy Storage	50	99	%	2023
Sarmiento	Argentina	Gas/Diesel	33	100	%	1996
Andes Solar 4	Chile	Solar	13	99	%	2023		Google, Various
	Energy Storage	13
Andes Solar 1	Chile	Solar	22	99	%	2016	2036	Quebrada Blanca
Cochrane ES	Chile	Energy Storage	20	57	%	2016
Angamos ES	Chile	Energy Storage	20	99	%	2011
San Matias	Chile	Wind	17	99	%	2023	2038	Microsoft
Laja	Chile	Biomass	13	99	%	2000	2023	CMPC
Andes	Chile	Energy Storage	12	99	%	2009
Alfalfal Virtual Reservoir	Chile	Energy Storage	10	99	%	2020
PFV Kaufmann	Chile	Solar	1	99	%	2021	2040	Kaufmann
			14,885

(1)In November 2023, agreed to sell this business to Sev.en Global Investments Pty Ltd. Following approvals by the Government of Vietnam and the Ministry of Industry and Trade, the anticipated close for this transaction is in line with AES' intent to exit the majority of its coal assets by the end of 2025.

(2)In November 2021, Alto Maipo SpA filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code. After Chapter 11 filing, the Company no longer has control over Alto Maipo and therefore deconsolidated the business. In May 2022, Alto Maipo emerged from bankruptcy. The restructured business is considered a VIE and the Company continues to account for the business as a deconsolidated entity.

(3)On December 1, 2022, Southland Energy sold an additional 14.9% ownership interest in the Southland Energy assets. Following the sale, AES holds 50.1% of Southland Energy's interest and this business continues to be consolidated by AES.

(4)TermoAndes is located in Argentina, but is connected to both the SING in Chile and the SADI in Argentina.

(5)AES operates this facility through management or O&M agreements and to date owns no equity interest in the business.

(6)Entered into an agreement to sell 26% interest in these businesses in November 2020.

(7)Plant also includes an adjacent regasification facility, as well as an 80 TBTU LNG storage tank, or an operating capacity of 180,000 m3.

(8)Plant also includes an adjacent regasification facility, as well as two LNG storage tanks: Andres with 70 TBTU, or an operating capacity of 160,000 m3 and Enadom with 50 TBTU, or an operating capacity of 120,000 m3.

(9)Includes: Alfalfal, Queltehues and Volcan.

(10)On June 29, 2023, Warrior Run terminated its PPA with Potomac Edison. As part of the agreement, Warrior Run stopped selling its electricity to Potomac Edison, but will continue to provide capacity to Potomac Edison through May 31, 2024. The previous expiration for the PPA was 2030.

Under construction — The majority of projects under construction have executed mid- to long-term PPAs. The following table lists our plants under construction in the Energy Infrastructure SBU1:


Business	Location		Fuel		Gross MW	AES Equity Interest		Expected Date of Commercial Operations
San Matias	Chile		Wind		65	99	%	1H 2024
Andes Solar 4	Chile		Solar		225	99	%	2H 2024
		Energy Storage		135
Gatun	Panama		Gas		670	24	%	2H 2024
Andes Solar 2a	Chile		Energy Storage		80	51	%	1H 2025
					1,175

AES Chile

Business Description — In Chile, through AES Andes, we are engaged in the generation and supply of electricity (energy and capacity) in the SEN—see International Energy Markets and Regulatory Environment below. AES Andes is a publicly traded company in Chile and has applied to be de-listed. AES Andes owns all of our assets in Chile. AES has a 99.5% ownership interest in AES Andes, the third largest generation operator in Chile in terms of installed capacity with 3,516 MW, excluding energy storage, and has a market share of approximately 11% as of December 31, 2023. In addition, AES Andes has 237 MW of energy storage systems in operation.

AES Andes owns a diversified generation portfolio in Chile in terms of geography, technology, customers, and energy resources. AES Andes' generation plants are located near the principal electricity consumption centers, including Santiago, Valparaiso, and Antofagasta. AES Andes' 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.


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AES Andes' Green Blend strategy aims to reduce carbon intensity and incorporate renewable energy to extend our existing conventional PPAs. This strategy de-links company's PPAs from legacy fossil resources, grows its renewable energy portfolio, and delivers a competitive, reliable energy solution. In line with the Green Blend strategy, AES Andes has committed to not build additional coal-based power plants and to advance the development of new renewables projects, including the implementation of BESS and other technological innovations that will provide greater flexibility and reliability to the system.

AES Andes currently has long-term contracts with an average remaining term of approximately 12 years with unregulated customers, such as mining and industrial companies, mainly with pricing indexed to CPI. AES Andes also has contracts with regulated companies with a maximum remaining term of one year, which include pass-through mechanisms for fuel costs along with pricing indexed to CPI.

In addition to energy payments, AES Andes 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 CPI and other relevant indices.

Key Financial Drivers — Hedging strategies at AES Andes limit volatility to the underlying financial drivers. In addition, financial results are likely to be driven by many factors, including, but not limited to:

spot market prices (largely impacted by dry hydrology scenarios, forced outages and international fuel prices);
changes in current regulatory rulings altering the ability to pass through or recover certain costs;
fluctuations of the Chilean peso;
tax policy changes; and
legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets.

Decarbonization Strategy — The Chilean government’s decarbonization plan includes the complete retirement of the SEN coal fleet by the end of 2040 and carbon neutrality by 2050. Following the issuance of Supreme Decree Number 42 on December 26, 2020 by the Ministry of Energy and per the disconnection and termination agreement signed with the Chilean government in June 2019, AES Andes accelerated the retirement plans of its Ventanas 1 and Ventanas 2 coal-fired units, disconnecting them from the SEN as of June 30, 2022 and December 31, 2023, respectively.

In July 2021, AES Andes committed to allow the shutdown of coal-fired operations at its Ventanas 3, Ventanas 4, Angamos 1, and Angamos 2 units as early as January 1, 2025, once the safety, sufficiency, and competitiveness of the system allows it. These four units together have an installed capacity of 1,097 MW and each unit has publicly announced phase-out plans in line with the Company’s decarbonization strategy. In July 2021, the Company also sold its entire ownership interest in Guacolda, a 764 MW coal-fired plant located in Chile.

On February 8, 2024, AES Andes was authorized by the CEN to definitively disconnect the coal-fired generation units Norgener 1 and Norgener 2, with an installed capacity of 276 MW, from the SEN on March 31, 2024.

Ventanas, Angamos, Guacolda, and Norgener represent an aggregate of 2.5 GW of coal-fired capacity, or 82% of AES Andes’ legacy coal fleet. AES Andes continues to work under the Green Blend strategy to accelerate the phase-out of the remaining coal-fired units.

Development Strategy — AES Andes is committed to reducing the carbon intensity of the Chilean power grid and plans to increase the renewable energy capacity in its portfolio. As part of this commitment, AES Andes is building wind, solar, and battery projects to supply agreements with its main mining customers.

In total, the pipeline in Chile currently includes 5.4 GW under development at different stages and geographical locations. Within this portfolio, the Company has made significant progress in the development of non-conventional renewable energy ("NCRE") projects that are already contracted. The Rinconada wind project (258 MW) is being developed in the Biobío region. Several projects are being developed in the Antofagasta region: a new expansion of the Andes Solar power plant which will include a battery system to optimize solar generation (186 MW + 266 MW-3hr), the Cristales solar power plant (187 MW + 267 MW-3hr), the Bolero battery system (136 MW-3hr), and the Pampas hybrid project (120 MW wind, 160 MW solar + 229 MW-3hr).

In addition, Empresa Eléctrica Angamos, a subsidiary of AES Andes, received environmental approval for an


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innovative initiative on November 29,2023 to revolutionize the conversion of thermoelectric plants using molten salts. This project explores the possibility of replacing the current coal-fired generation of units 1 and 2 of the Angamos thermoelectric power plant, located in Mejillones, Antofagasta region, with a molten salt system. With this technology, renewable energy is stored as heat to later be used to provide energy and emission-free capacity to the electrical system.

Empresa Eléctrica Angamos is also promoting the advancement of green hydrogen technology for mass production through the Adelaida project, which contemplates the installation of a small-scale green hydrogen production plant with a capacity of 1,000 kg/day of green hydrogen, equivalent to 2.5 MW of power.

U.S. Conventional Generation

Business Description — In the U.S., we own a conventional generation portfolio. The principal markets and locations where we are engaged in the generation and supply of electricity (energy and capacity) are the California Independent System Operator ("CAISO"), PJM, and Puerto Rico. AES Southland, operating in the CAISO, is our most significant generation business. In June 2023, the Company closed on an agreement to terminate the PPA for the Warrior Run coal-fired power plant and to continue providing capacity through May 2024.

Many of our non-renewable U.S. generation plants provide baseload operations and are required to maintain a guaranteed level of availability. Any change in availability has a direct impact on financial performance. Some plants are eligible for availability bonuses if they meet certain requirements. Coal and natural gas are used as the primary fuels. Coal prices are set by market factors internationally, while natural gas prices are generally set domestically. Price variations for these fuels can change the composition of generation costs and energy prices in our generation businesses.

Before the termination of its PPA in June 2023, Warrior Run operated as a QF, as defined under the PURPA, under 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). Warrior Run no longer operates as a QF.

Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under the Energy Policy Act 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 Energy Policy 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.

AES Southland

Business Description — AES Southland is one of the largest generation operators in California by aggregate installed capacity, with an installed gross capacity of 3,699 MW at the end of 2023. The five coastal power plants comprising AES Southland are in areas that are critical for local reliability and play an important role in integrating the increasing amounts of renewable generation resources in California. The AES Southland Energy Infrastructure assets are composed of three once-through cooling ("OTC") power plants and two combined cycle gas-fired generation facilities.

Southland — Southland comprises AES Huntington Beach, LLC, AES Alamitos, LLC, and AES Redondo Beach ("Southland OTC units"). Until December 31, 2023, the Southland OTC units were contracted through Resource Adequacy Purchase Agreements (“RAPAs”). Under the RAPAs, as approved by the California Public Utilities Commission, these generating stations provided resource adequacy capacity, and had no obligation to


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produce or sell any energy to the RAPA counterparty. However, the generating stations were required to bid energy into the California ISO markets. Southland OTC units entered into commodity swap contracts to economically hedge price variability inherent in electricity sales arrangements. Compensation under these RAPAs was dependent on the availability of the Southland OTC units in the California ISO market. Failure to achieve the minimum availability target would result in an assessed penalty.

Commencing on January 1, 2024, AES Huntington Beach, LLC and AES Alamitos, LLC, are contracted through Standby Capacity Purchase Agreements with the California Department of Water Resources (“California DWR”), an agency of the State of California, as part of the Electricity Supply Strategic Reliability Reserve Program (‘Strategic Reserve”) established under California Assembly Bill 205. Under these agreements, California DWR is purchasing each facility’s available capacity for a three-year term.

The Southland OTC units are subject to a variety of rules governing water use and discharge. The units are required to comply with the more stringent of state or federal requirements. AES Southland's current plan is to comply with the SWRCB OTC Policy by shutting down and permanently retiring all remaining generating units that utilize OTC by the compliance dates included in the OTC Policy. 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.

Southland Energy — AES Huntington Beach Energy, LLC and AES Alamitos Energy, LLC, (collectively "Southland Energy") each operate under 20-year tolling agreements with Southern California Edison ("SCE") to provide 1,387 MW of combined cycle gas-fired generation (through 2040),

The contracts are RAPAs with annual energy tolling put options. If Southland Energy exercises the annual put option, all capacity, energy and ancillary services will be sold to SCE in exchange for a monthly energy and fixed capacity payment that covers fixed operating cost, debt service, and return on capital. In addition, SCE will reimburse variable costs and provide the natural gas. Southland Energy may exercise the annual put option for any contract year by delivering notice of such exercise to SCE at least one year before the start of such contract year, and no more than two years before the start of any contract year. If the annual put options are not exercised, Southland Energy is required to sell the physical output of the combined cycle gas-fired generation units to AES Integrated Energy. AES Integrated Energy is required to bid energy into the California ISO market. AES Integrated Energy enters into commodity swap contracts to economically hedge price variability inherent in electricity sales arrangements. Southland Energy continues to receive the monthly fixed capacity payments for periods when the put option is not exercised.

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.

AES Puerto Rico

Business Description — AES Puerto Rico owns and operates a 524 MW coal-fired cogeneration plant representing approximately 10% of the installed capacity in Puerto Rico. This plant is fully contracted through a long-term PPA with PREPA expiring in 2027. AES Puerto Rico receives a capacity payment based on the plants' twelve month rolling average availability, receiving the full payment when the availability is 90% or higher. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPAs with PREPA.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to, improved operational performance and plant availability.

AES Argentina and TermoAndes

Business Description — AES operates plants in Argentina within the Energy Infrastructure SBU totaling 2,814 MW, representing 6% of the country's total installed capacity. AES owns a diversified generation portfolio in Argentina in terms of geography, technology, and fuel source, and AES Argentina's plants are placed in strategic locations within the country in order to provide energy to the spot market and contracted customers.

AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2023, approximately 79% of the energy was sold in the wholesale electricity market and 21% was sold under contract by TermoAndes power plant.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:


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forced outages;
exposure to fluctuations of the Argentine peso;
timely collection of FONINVEMEM installments and outstanding receivables (see International Energy Markets and Regulatory Environment below);
natural gas prices and availability for contracted generation at TermoAndes; and
domestic energy demand and exports.

AES Vietnam

Business Description — Mong Duong 2 is a 1,242 MW gross coal-fired plant located in the Quang Ninh Province of Vietnam and was constructed under a BOT service concession agreement expiring in 2040. This is the first 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 November 29, 2023, AES executed an agreement to sell its entire 51% interest in the Mong Duong 2 plant. The sale is expected to close by the end of 2025, 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.

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 September 2019 we received a 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 to continue developing the Son My 2 CCGT project under Vietnam’s Build-Operate-Transfer legal framework. In October 2019, we received formal approval as a government-mandated investor in the Son My LNG terminal project in partnership with PetroVietnam Gas. In September 2021, we signed the joint venture agreement with PetroVietnam Gas and established Son My LNG Terminal LLC in April 2022. In July 2023, Son My LNG Terminal LLC received approval of investment policy and as the government-approved investor from the Binh Thuan Provincial People’s Committee. The Son My 2 CCGT project will utilize the Son My LNG terminal project and will be its anchor customer.

AES Mexico

Business Description — 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. TEG and TEP are in the migration process from the Legacy market to the New Electric Industry law. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Mexico M i g r a t i o n a n d Wheeling Tariffs for further discussion of the migration process.

Merida is a CCGT located on Mexico's Yucatan Peninsula. Merida sells power to the CFE under a capacity and energy based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel fuel under a long-term contract with one of the CFE’s subsidiaries, the cost of which is then passed through to the CFE under the terms of the PPA.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:

contracting levels, providing additional benefits from improved operational performance, including performance incentives and/or excess energy sales;
changes in the methodology to calculate spot energy prices or Locational Marginal Prices, which impacts the excess energy sales to the CFE (see International Energy Markets and Regulatory Environment below) in TEG and TEP under self-supply scheme; and
improved operational performance and plant availability.


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AES Dominicana

Business Description — AES Dominicana has two operating subsidiaries within the Energy Infrastructure SBU, Andres and Los Mina, both of which are owned 65% by AES. With a total of 697 MW of installed capacity, AES provides 12% of the country's capacity and supplies approximately 16% of the country's energy demand via these generation facilities. 668 MW was predominantly contracted until 2022 with government-owned distribution companies and large customers, and have been contracted back with the distribution companies in January 2023.

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 facility with two natural gas turbines and an energy storage facility with combined generation capacity of 368 MW.

AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), two leading Dominican industrial groups that manage a diversified business portfolio. In December 2023, AES completed the sale of an additional 10% ownership interest in AES Dominicana to the existing partners and a 10% interest to Grupo Popular's subsidiary, AFI Popular, selling 20% ownership interest in total. After this transaction, AES' ownership interest in AES Dominicana is 65%.

AES Dominicana has entered into a new long-term LNG purchase contract through the second half of 2034 to cover the expected dispatch for Andres and Los Mina. Andres has long-term contracts to sell regasified LNG to industrial users and third party power plants within the Dominican Republic, thereby capturing demand from industrial and commercial customers and for other power generation companies that had switched their operations to natural gas.

AES partnered with Energas in a joint venture to operate the 50 km Eastern Pipeline from February 2020. The joint venture also developed an expanded LNG facility of 120,000 cubic meters, including additional storage, regasification, and truck loading capacity, which reached COD in the fourth quarter of 2023.

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 Andres and Los Mina);
expiring PPAs, lower 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.

Development Strategy — AES will continue to develop the commercialization of natural gas and incorporate partners directly in gas infrastructure projects.

AES 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 is collecting receivables from NEK in a timely manner. However, NEK's liquidity position is subject to political conditions and regulatory changes in Bulgaria.

The DG Comp is reviewing NEK’s PPA with AES Maritza pursuant to the European Union’s state aid rules. AES Maritza believes that its PPA is legal and in compliance with all applicable laws. For additional details see Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations —Key Trends and Uncertainties—Regulatory of this Form 10-K*.*

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; and
NEK's ability to meet the payment terms of the PPA contract with Maritza.

AES Panama

Business Description — AES owns and operates a natural gas-fired power plant with 381 MW of generation


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capacity. Furthermore, AES operates an LNG regasification facility, a 180,000 cubic meter storage tank, and a truck loading facility. In December 2023, AES completed the sale of 35% ownership interest in Colon to Grupo Linda and Grupo Estrella, our current minority partners in AES Dominicana. After this transaction, AES' ownership interest is 65% in both assets.

Our thermal asset in Panama has PPAs with distribution companies for a total contracted capacity of 350 MW expiring in August 2028, which matches the term of the LNG supply agreement of such thermal assets. The LNG supply contract has enough flexibility to divert volumes to the Dominican Republic, which increases the connectivity of our two onshore terminals and allows to optimize the LNG position of the portfolio. Colon LNG Marketing continues developing the LNG market in Latin America, with clients already established in Panama and Colombia. Additional efforts are being undertaken in Costa Rica, other Central America regions, and Caribbean islands, mainly focusing on small scale LNG logistics.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:

changes in hydrology, which impacts the spot prices and exposes the business to variability in the cost of replacement power;
fluctuations in commodity prices, mainly fuel oil and natural gas, which affect the cost of thermal generation and spot prices;
constraints imposed by the capacity of transmission lines connecting the west side of the country with the load, keeping surplus power trapped during the rainy season; and
country demand as GDP growth is expected to remain strong over the short and medium term.

Development Strategy — Given our LNG facility’s excess capacity in Panama, the company is developing 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 CO2 emissions as a result of using LNG.

AES Jordan

Business Description — In Jordan, AES has a 37% controlling interest in Amman East, a 472 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 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 2024 subject to customary closing conditions, including lender consents and regulatory approvals.


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New Energy Technologies

Our New Energy Technologies SBU includes investments in new and innovative technologies, designed to both strengthen the competitive advantage of AES' core businesses and enable the growth of new green businesses. This segment includes ownership stakes in third-party platforms, as well as new initiatives developed internally. It includes investments in Fluence, Uplight, and 5B, as well as our green hydrogen initiatives. We are a leader in developing green hydrogen and we are pursuing multiple projects across our geographies with total potential installed electrolyzer capacity of up to 1,200 metric tons/day by 2030.

Fluence and Uplight are unconsolidated entities and their results are reported in Net equity in losses of affiliates on our Consolidated Statements of Operations. 5B is accounted for using the measurement alternative and AES will record income or loss only when it receives dividends from 5B or when there is a change in the observable price or an impairment of the investment.

Fluence

Business Description — Fluence, created in 2018 as a joint venture by AES and Siemens AG, is a global energy storage technology and services company aligned with the AES strategy to drive decarbonization of the electric sector. Fluence is a leading global provider of energy storage products and services and artificial intelligence (AI)-enabled digital applications for renewables and storage.

On November 1, 2021, Fluence Energy, Inc. completed its IPO, generating primary proceeds of approximately $936 million, after expenses, and is listed on Nasdaq under the symbol "FLNC". AES owns Class B-1 common stock, entitling AES to five votes per share held, and continues to hold its economic interest in the operating subsidiary of Fluence Energy, Inc. AES' economic interest in Fluence is currently 29%. The Company continues to account for Fluence as an equity method investment.

Key Financial Drivers — Fluence's financial results are driven by the growth in its product revenue, an efficient cost structure that is expected to benefit from increased scale, and profit margins on customer contracts. Fluence’s pipeline of potential projects is global.


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Development Strategy — The grid-connected energy storage sector is expanding rapidly. 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. According to the 2H 2023 Energy Storage Market Outlook published by BloombergNEF in October 2023, the global energy storage market is growing at a 27% compound annual growth rate to 2030, with annual additions reaching 110 GW/372 GWh, or 2.6x expected 2023 gigawatt installations. Additional growth opportunities exist in the provision of operational and maintenance services associated with energy storage products, as well as the provision of digital applications and solutions to improve performance and economic output. Fluence is positioned to be a leading participant in this growth, with 3.6 GW of energy storage assets deployed and 5.1 GW of contracted backlog, with a gross global pipeline of 13.2 GW as of December 31, 2023.

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 70 of the 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.

At December 31, 2023 the Company held a 29.4% ownership interest in Uplight. On February 9, 2024, another shareholder was issued additional shares in Uplight as a result of contributing a business and $40 million in cash to Uplight. The business contributed is AutoGrid, a market leader in the fast-growing Virtual Power Plant ("VPP") space. As a result of the additional shares issued to the other shareholder, AES' interest was diluted to approximately 25%. Uplight continues to be accounted for as an equity method investment.

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. AES Indiana and AES Ohio have implemented Uplight's consumer engagement solutions in support of energy efficiency and demand response programs, as well as piloted new solutions with Uplight.

Business Description — The Company has 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 and can sustain higher wind speeds than traditional solar plants.

Key Financial Drivers — 5B is accounted for under the measurement alternative and AES will record income or loss only when it receives dividends from 5B or when there is a change in the observable price or an impairment of the investment.

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. As of December 31, 2023, 5B has achieved sales orders of over 250 MW. 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 multiple locations in AES for a total of 23 MW across five projects in Panama, Chile, El Salvador, and the U.S., with future deployments expected across markets in the AES portfolio.


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International Energy Markets and Regulatory Environment

Chile

The Chilean electricity industry is divided into three business segments: generation, transmission, and distribution. Private companies operate in all three segments, and generators can enter into PPAs to sell energy to regulated and unregulated customers, as well as to other generators in the spot market.

Chile operates in a single power market, referred to as the SEN, which is managed by the grid operator CEN. The SEN has an installed capacity of 31,466 MW, and represents 99% of the installed generation capacity of the country.

CEN coordinates all generation and transmission companies in the SEN. CEN minimizes the operating costs of the electricity system, while maximizing service quality and reliability requirements. CEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost. In the south-central region of the SEN, thermoelectric generation is required to fulfill demand not satisfied by hydroelectric, solar, and wind output and is critical to provide reliable and dependable electricity supply under dry hydrological conditions in the highest demand area of the SEN. In the northern region of the SEN, which includes the Atacama Desert, thermoelectric capacity represents the majority of installed capacity. The fuels used for thermoelectric generation, mainly coal, diesel, and LNG, are indexed to international prices. In 2023, the installed generation capacity in the Chilean market was composed of 42% thermoelectric, 23% hydroelectric, 21% solar, 13% wind, and 1% other fuel sources.

Hydroelectric plants represent a significant portion of the system's installed capacity. Precipitation and snow melt impact hydrological conditions in Chile. Rain occurs principally from June to August and snow melt occurs from September to December. These factors affect dispatch of the system's hydroelectric and thermoelectric generation plants, thereby influencing spot market prices.

The Ministry of Energy has primary responsibility for the Chilean electricity system directly or through the National Energy Commission and the Superintendency of Electricity and Fuels.

All generators can sell energy through contracts with regulated distribution companies or directly to unregulated customers. Customers whose connected demand capacity is higher than 5 MW are excluded from the regulated market and are referred to as unregulated customers. Customers with connected capacity between 0.5 MW and 5 MW can opt for regulated or unregulated contracts for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all electricity under contracts. Generators may also sell energy to other power generation companies on a short-term basis at negotiated prices outside the spot market. Electricity prices in Chile are denominated in USD, although payments are made in Chilean pesos.

Dominican Republic

The Dominican Republic energy market is a decentralized industry consisting of generation, transmission, and distribution businesses. Generation companies can earn revenue through short- and long-term PPAs, ancillary services, and a competitive wholesale generation market. All generation, transmission, and distribution companies are subject to and regulated by the General Electricity Law.

Two main agencies are responsible for monitoring compliance with the General Electricity Law:

The National Energy Commission drafts and coordinates the legal framework and regulatory legislation. They propose and adopt policies and procedures to implement best practices, support the proper functioning and development of the energy sector, and promote investment.
The Superintendence of Electricity's main responsibilities include monitoring compliance with legal provisions, rules, and technical procedures governing generation, transmission, distribution, and commercialization of electricity. They monitor behavior in the electricity market in order to prevent monopolistic practices.

In addition to the two agencies responsible for monitoring compliance with the General Electricity Law, the Ministry of Industry and Commerce supervises commercial and industrial activities in the Dominican Republic as well as the fuels and natural gas commercialization to end users.

The Dominican Republic has one main interconnected system with 5,640 MW of installed capacity, composed of thermal (70%), hydroelectric (11%), wind (7%), and solar (12%).


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El Salvador

El Salvador's national electric market is composed of generation, distribution, transmission, and marketing businesses, a market and system operator, and regulatory agencies. The operation of the transmission system and the wholesale market is based on production costs with a marginal economic model that rewards efficiency and allows investors to have guaranteed profits, while end users receive affordable rates. The energy sector is governed by the General Electricity Law, which establishes two regulatory entities responsible for monitoring its compliance:

The National Energy and Hydrocarbons Direction 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 2023 until 2027.

AES El Salvador distribution rates are regulated by SIGET and are established through a traditional cost-based rate-setting process. AES El Salvador 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. El Salvador has a national electric grid that interconnects directly with Guatemala and Honduras, allowing transactions with all Central American countries. The sector has approximately 2,459 MW of installed capacity, composed of thermal (55%), hydroelectric (22%), solar (9%), biomass (12%), and wind (2%) generation plants.

Bulgaria

The electricity sector in Bulgaria is regulated by the Bulgarian Energy Act, which has been amended in November 2023 in order to fulfill a commitment by Bulgaria to the European Commission to fully liberalize its electricity market by the end of 2025. The Bulgarian electricity market allows both regulated and competitive segments until the end of 2025. From 2026 onwards, the regulated segment is expected to cease to exist. NEK will retain its capacity as the public provider of electricity until the end of June 2024, under which NEK acts as a single buyer and seller for all regulated transactions on the market. From July 2024 onwards, Bulgarian distribution companies serving the regulated market will source their electricity needs exclusively from the competitive segment of 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’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 southeast European 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%).

Panama

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 backup supply contracts with each other. Outside of PPAs, generators may buy and sell energy in the short-term market. Generators can only contract up to their firm capacity.

Three main agencies are responsible for monitoring compliance with the General Electricity Law:

The National Secretary of Energy in Panama ("SNE") has the responsibilities of planning, supervising, and controlling policies of the energy sector within Panama. The SNE proposes laws and regulations to the executive agencies that regulate the procurement of energy and hydrocarbons for the country.
The National Authority of Public Services ("ASEP") is an autonomous agency of the government. ASEP is responsible for the regulations, control and oversight of public services in Panama, including electricity, the transmission and distribution of natural gas utilities, and the companies that provide such services.
The National Dispatch Center ("CND") is in charge of the operation of the system and the management of the electricity market. They are responsible for implementing 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 as a result of the optimization of the economic dispatch regardless of contractual arrangements.


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Panama's current total installed capacity is 4,134 MW, composed of hydroelectric (45%), thermal (32%), solar (15%), and wind (8%) generation.

Mexico

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 western interconnection; (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 laws and regulations, 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 87 GW with a generation mix composed of thermal (65%), hydroelectric (14%), wind (8%), solar (8%), and other fuel sources (5%).

Brazil

In Brazil, electricity production is predominantly renewable, with emphasis on hydroelectric plants, although there has been a significant advancement in intermittent renewable sources. The National Interconnected System (SIN) consists of four subsystems: South, Southeast/Midwest, Northeast and North regions. The interconnection of the systems through the transmission grid provides for the transfer of energy between subsystems, gaining synergies from the diversity of hydrological regimes of the basins, and allowing the market to be served safely and economically.

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 201 GW, composed of hydroelectric (55%), thermoelectric (23%), renewable (21%), other sources (1%). Operation is centralized and controlled by the national operator, ONS, and regulated by the Brazilian National Electric Energy Agency ("ANEEL"). The ONS dispatches generators based on their marginal cost of production and on the risk of system rationing. Key variables for the dispatch decision are forecasted hydrological conditions, reservoir levels, electricity demand, fuel prices, and thermal generation availability.

In case of unfavorable hydrology, the ONS will reduce hydroelectric dispatch to preserve reservoir levels and increase dispatch of thermal plants to meet demand. The consequences of unfavorable hydrology are (i) higher energy spot prices due to higher energy production costs at 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 (Energy Reallocation Mechanism) was created under ONS to share hydrological risk across MRE hydro generators by using a generation scaling factor ("GSF") to adjust generators' physical guarantee during periods of hydrological scarcity. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may need to purchase energy in the short-term market. When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they may sell the excess energy on the spot market.

Brazil Indirect Tax Reform — On December 20, 2023, Constitutional Amendment 132 was enacted and overhauls the federal, state, and local indirect taxes on consumption and transactions in Brazil. This amendment is


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the fundamental pillar of the broad Tax Reform which also requires a Complementary Law to the Constitution (LC), to be proposed in 2024.

Based on the amendment, the new tax model will eliminate all indirect taxes and create a dual VAT (federal and state/municipal), plus a federal excise tax (no impact is expected in AES Brasil businesses). The combined rate of the dual VAT is expected to be between 25% and 27% and aligns VAT input credits to amounts charged by suppliers and the tax-on-tax cascading effect for the collection at the location of the final consumer. Additionally, the indirect taxes incentive regime for infrastructure development ("REIDI") will be extinguished in 2027, but a new form of exemption for capital goods will be addressed in a Complementary Law.

The transition period to the new tax model will last 7 years (starting in 2026 and ending in 2032), during which two tax systems will coexist, with old and new taxes collected in parallel. Furthermore, the proposal requires the Executive Branch to send to the National Congress the Income Tax Reform bill of law within 90 days after the constitutional amendment takes effect. If this second phase of the tax reform is approved in 2024, it will take effect in 2025.

Argentina

Argentina has one main power system, the SADI, which serves 91% of the country. As of December 31, 2023, the installed capacity of the SADI totaled 43,774 MW. The SADI's installed capacity is composed primarily of thermoelectric generation (59%) and hydroelectric generation (26%), as well as wind (8%), nuclear (4%), and solar (3%).

Thermoelectric generation in the SADI is fueled primarily by natural gas. However, scarcity of natural gas during winter periods (June to August) due to transport constraints results in the use of alternative fuels, such as oil and coal. The SADI is also highly reliant on hydroelectric plants. Hydrological conditions impact reservoir water levels and largely influence the dispatch of the system's hydroelectric and thermoelectric generation plants and, therefore, influence market costs. Precipitation in Argentina occurs principally from May to October.

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 prices for electricity and defines fuel reference prices. For the energy sold in the spot market, generators are compensated for fixed costs and non-fuel variable costs, under prices mainly denominated in Argentine pesos and CAMMESA is in charge of providing the natural gas and liquid fuels required by the generation companies, except for coal. For the energy sold under PPAs (as Energía PLUS from TermoAndes) the generators buy their required fuel at a reference price established by the regulator. As a result, our businesses are particularly sensitive to changes in regulation.

The expansion of renewable capacity in the system is promoted by allowing the new power plants to sign contracts either with CAMMESA through the RenovAr program or directly by trading energy in the private market.

During 2023, although the government increased prices to the end user, subsidies and the system deficit also increased. By December 2023, distribution companies recovered an average 47% of the total cost of the system.

In past years, AES Argentina contributed certain accounts receivable to fund the construction of three power plants under FONINVEMEM agreements. These receivables accrue interest and are collected in monthly installments over 10 years after commercial operation date of the related plant takes place. In 2020, FONINVEMEM I and II installments were fully repaid and in 2021 the ownership interests in Termoeléctrica San Martín and Termoeléctrica Manuel Belgrano were defined after the incorporation of the National Government as majority shareholder. The transfer of the power plants to these companies has not yet occurred. FONINVEMEM III is related to Termoeléctrica Guillermo Brown, which began operations in April 2016, and the installments are still being collected. AES Argentina will receive a pro rata ownership interest in this plant, which shall not be greater than 30%, once the accounts receivables have been fully repaid. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Long-Term Receivables and Note 7.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of receivables in Argentina.

In 2022 and 2023, the Argentine peso devalued against the USD by approximately 42% and 78%, respectively, and Argentina’s economy continued to be highly inflationary. Since September 2019, currency controls


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have been established to govern the devaluation of the Argentine peso and keep Argentine central bank reserves at acceptable levels.

Colombia

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 (66%), thermal (30%) and other renewables (4%), totaled 19,942 MW as of December 31, 2023. The marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2023, 74% of total energy demand was supplied by hydroelectric plants.

The electricity sector in Colombia operates under a competitive market framework for the generation and sale of electricity, and a regulated framework for transmission and distribution of electricity. The distinct activities of the electricity sector are governed by Colombian laws and CREG, the Colombian regulating entity for energy and gas. Other government entities have a role in the electricity industry, including the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the Public Utility Superintendency of Colombia, which is in charge of overseeing utility companies; and the Mining and Energy Planning Unit, which is in charge of expansion planning 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.

The expansion of the system is supported by two schemes: i) reliability charge auctions where firm energy commitments are focused on conventional technology power plants, and ii) auctions of long-term energy contracts assigned for periods of 15 years aimed at non-conventional renewable resources.

Vietnam

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 80 GW. The fuel mix in Vietnam is composed primarily of coal (33%), hydropower (28%) and renewables, including solar, wind, and biomass (27%). EVN, the national utility, owns 37% 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. The reforms are currently in development. 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.

Puerto Rico

Puerto Rico has a single electric grid managed by PREPA, a state-owned entity that provides virtually all of the electric power consumed in Puerto Rico and generates, transmits, and distributes electricity to 1.5 million customers. Since June 2021, PREPA has contracted LUMA Energy to manage the transmission, distribution and commercialization activities. 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 93% produced by thermal plants (51% from petroleum, 33% from natural gas, and 9% from coal), while the remaining 7% is supplied by renewable resources (wind and solar).

Jordan

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.


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Environmental and Land-Use Regulations

The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion residuals), and certain air emissions, such as SO2, NOX, particulate matter, mercury, and other hazardous air pollutants. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries, and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors—Our operations are subject to significant government regulation and could be adversely affected by changes in the law or regulatory schemes; Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR; Our businesses are subject to stringent environmental laws, rules and regulations; and Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses in this Form 10-K. For a discussion of the laws and regulations of individual countries within each SBU where our subsidiaries operate, see discussion within Item 1.—Business of this Form 10-K under the applicable SBUs.

Many of the countries in which the Company does business have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from electric power generation or distribution assets. In addition, international projects funded by the International Finance Corporation, the private sector lending arm of the World Bank, or many other international lenders are subject to World Bank environmental standards or similar standards, which tend to be more stringent than local country standards. The Company often has used advanced generation technologies in order to minimize environmental impacts, such as combined fluidized bed boilers and advanced gas turbines, and environmental 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 SO2, NOX, particulate matter, GHGs, mercury, and other hazardous air pollutants. Certain applicable rules are discussed in further detail below.

CSAPR — CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment of, 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 currently required to comply with the CSAPR in certain states, including in Indiana and Maryland. The CSAPR is implemented in part through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. The Company complies with CSAPR through operation of existing controls and purchases of allowances on the open market, as needed.

In October 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS ("CSAPR Update Rule"). Following legal challenges related to the CSAPR Update Rule, on April 30, 2021, the EPA issued the Revised CSAPR Update Rule. The Revised CSAPR Update Rule required affected electric generating units ("EGUs") within certain states (including Indiana and Maryland) to participate in a new trading program, the


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CSAPR NOx Ozone Season Group 3 trading program. These affected EGUs received fewer NOx Ozone Season allowances beginning in 2021.

On June 5, 2023, the EPA published a final Federal Implementation Plan ("FIP") to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule establishes a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and Maryland and became effective during 2023. The FIP also includes enhancements to the revised Group 3 trading program, which include a dynamic budget setting process beginning in 2026, annual recalibration of the allowance bank to reflect changes to affected sources, a daily backstop emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels. It is too early to determine the impact of this final rule, but it may result in the need to purchase additional allowances or make operational adjustments.

While the Company's additional CSAPR compliance costs to date have been immaterial, the future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time, but it could be material.

New Source Review ("NSR") — The NSR requirements under the CAA impose certain requirements on major emission sources, such as electric generating stations, if changes are made to the sources that result in a significant increase in air emissions. Certain projects, including power plant modifications, are excluded from these NSR requirements if they meet the routine maintenance, repair, and replacement ("RMRR") exclusion of the CAA. There is ongoing uncertainty and significant litigation regarding which projects fall within the RMRR exclusion. Over the past several years, the EPA has filed suits against coal-fired power plant owners and issued NOVs to a number of power plant owners alleging NSR violations. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action, including an NOV issued by the EPA against AES Indiana concerning NSR and prevention of significant deterioration issues under the CAA. If NSR requirements are imposed on any of the power plants owned by the Company's subsidiaries, the results could have a material adverse impact on the Company's business, financial condition, and results of operations.

Regional Haze Rule — The EPA's "Regional Haze Rule" established timelines for states to improve visibility in national parks and wilderness areas throughout the United States by establishing reasonable progress goals toward meeting a national goal of natural visibility conditions in Class I areas by the year 2064 through a series of state implementation plans (SIPs), which may result in additional emissions control requirements for electric generating units. SIPs for the first planning period (through 2018) did not result in material impact to AES facilities. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. The deadline for submittal of the SIP covering the second planning period was July 31, 2021. To date, none of the states in which we operate have submitted plans identifying potential impacts to Company facilities. However, we cannot predict the possible outcome or potential impacts of this matter at this time.

NAAQS — Under the CAA, the EPA sets NAAQS for six principal pollutants considered harmful to public health and the environment, including ozone, particulate matter, NOX, and SO2, which result from fossil-fuel 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 SIPs to detail how the states will attain or maintain their attainment status. As part of this process, it is possible that the applicable state environmental regulatory agency or the EPA may require reductions of emissions from our generating stations to reach attainment status for ozone, fine particulate matter, NOX, or SO2. The compliance costs of the Company's U.S. subsidiaries could be material.

Mercury and Air Toxics Standard — In April 2012, the EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective and AES facilities implemented measures to comply, as applicable.

In June 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the CAA and subsequently remanded MATS to


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the EPA without vacatur. On March 6, 2023, the EPA published a final rule reaffirming its 2016 finding that it is appropriate and necessary to regulate emissions under MATS. On April 24, 2023, the EPA published the proposed MATS Residual Risk and Technology Review rule which would lower certain emissions limits and revise certain other aspects of MATS. It is too early to determine the potential impacts of this proposal rule.

Further rulemakings and/or proceedings are possible; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of the regulatory or judicial process, or its impact, if any, on our MATS compliance planning or ultimate costs.

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 Prevention of Significant Deterioration ("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 ("EGUs") became effective, establishing CO2 emissions standards for newly constructed coal-fueled electric generating plants, which reflects the partial capture and storage of CO2 emissions from the plants. The EPA also promulgated NSPS applicable to modified and reconstructed electric generating units, which will serve as a floor for future BACT determinations for such units. The NSPS could have an impact on the Company's plans to construct and/or modify or reconstruct electric generating units in some locations. On December 20, 2018, the EPA published proposed revisions to the final NSPS for new, modified, and reconstructed coal-fired electric utility steam generating units proposing that the best system of emissions reduction for these units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration, as was finalized in the 2015 final NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal. Legal challenges to the GHG NSPS are being held in abeyance at this time. On May 23, 2023, the EPA published a proposed rule that would establish CO2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023.

On July 8, 2019, the EPA published the final Affordable Clean Energy ("ACE") Rule which would have established CO2 emission rules for existing power plants under CAA Section 111(d) and would have replaced the EPA's 2015 Clean Power Plan Rule ("CPP"). However, on January 19, 2021, the D.C. Circuit vacated and remanded the ACE Rule. Subsequently, on June 30, 2022, the Supreme Court reversed the judgment of the D.C. Circuit Court and remanded for further proceedings consistent with its opinion, holding that the “generation shifting” approach in the CPP exceeded the authority granted to the EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate, holding pending challenges to the ACE Rule in abeyance. On May 23, 2023, the EPA published a proposed rule that would vacate the ACE Rule, establish emissions guidelines in the form of CO2 emissions limitations for certain existing EGUs and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as the EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operation to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s. It is too early to determine the potential impact of the proposed rule and the results of further proceedings and potential future greenhouse gas emissions regulations remain uncertain, but could be material.

On January 20, 2021, President Biden signed and submitted an instrument for the U.S. to rejoin the Paris Agreement effective February 19, 2021. In addition, in November 2023, the international community gathered at the 28th Conference to the Parties on the UN Framework Convention on Climate Change ("COP28"). The Parties agreed to non-binding language calling on countries to transition away from fossil fuels in energy systems to achieve net zero emissions by 2050.

As such, there is some uncertainty with respect to the impact of GHG rules. 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 for new EGUs 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.


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Due to the future uncertainty of these regulations and associated litigation, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with a new Section 111(d) Rule, should it be implemented in a prior or a substantially similar form, could be material. The GHG NSPS for new EGUs 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 effective in 2014 that seeks to protect fish and other aquatic organisms drawn into cooling water systems at power plants and other facilities. These standards require affected facilities to choose among seven best technology available ("BTA") options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible that this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility to increase generation capacity are required to reduce both impingement and entrainment. It is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.

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. Certain OTC units were required to be retired in 2019 to provide interconnection capacity and/or emissions credits prior to startup of the new generating units at AES Alamitos and AES Huntington Beach. AES Southland's current plan is to comply with the SWRCB OTC Policy by shutting down and permanently retiring all remaining generating units that utilize OTC by the compliance dates included in the OTC Policy. Following earlier extensions, in 2021, the AES Redondo Beach compliance date was extended to December 31, 2023 and there is currently no plan to replace the OTC generating units at AES Redondo Beach following their retirement effective January 1, 2024. Following earlier extensions, on August 15, 2023, the State Water Board considered the SACCWIS recommendation and adopted an amendment to the OTC Policy that established a final compliance date of December 31, 2026 for AES Alamitos and AES Huntington Beach. These extensions are contingent upon the facilities participating in the Strategic Reserve established by California Assembly Bill, AB 205, which addresses grid reliability risks from extreme events.

Water Discharges — In June 2015, the EPA and the U.S. Army Corps of Engineers ("the Agencies") published a rule defining federal jurisdiction over waters of the U.S., known as the "Waters of the U.S." (“WOTUS”) rule. WOTUS defines the geographic reach and authority of the Agencies to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the appropriate standard for how to properly determine whether a wetland or stream that is not navigable is considered a WOTUS. On May 25, 2023, the U.S. Supreme Court rendered a decision (“Decision”) in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. This decision provides a standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not federally jurisdictional.

On September 8, 2023, the Agencies published final rule amendments in the Federal Register to amend the final “Revised Definition of ‘Waters of the United States’” rule. This final rule amendment conforms the definition to the definition adopted in the Decision. The Agencies have amended key aspects of the regulatory text to conform the rule to the Decision. It is too early to determine whether the outcome of litigation or current or future revisions to rules interpreting federal jurisdiction over WOTUS may have a material impact on our business, financial condition, or results of operations.

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of the U.S. by steam-electric power plants through technology applications. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash, and more stringent effluent limitations for flue gas desulfurization wastewater. Operational practices and/or wastewater treatment technologies already installed and operated at U.S. businesses met the requirements of these rules. Following the 2019 U.S. Court of Appeals vacatur and remand of portions of the 2015 ELG rule related to leachate and legacy water, on


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March 29, 2023, the EPA published a proposed rule revising the 2020 Reconsideration Rule. The proposed rule would establish new best available technology economically achievable effluent limits for flue gas desulfurization wastewater, bottom ash treatment water, and combustion residual leachate. It is too early to determine whether any outcome of litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition, and results of operations.

On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source, such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases relevant to determination of "functional equivalent" are ongoing in various jurisdictions. On November 27, 2023, the EPA issued a draft guidance addressing how the Supreme Court decision would be applied to the NPDES permit program as it relates to functional equivalent discharge. It is too early to determine whether the Supreme Court decision or the result of litigation to "functional equivalent" may have a material impact on our business, financial condition, or results of operations.

Waste Management — On October 19, 2015, an EPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and currently operating CCR landfills and CCR surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. 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. On February 20, 2020, the EPA published a proposed rule to establish a federal CCR permit program that would operate in states without approved CCR permit programs. 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 the EPA. The EPA has indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. On January 11, 2022, the EPA released the first in a series of proposed and final determinations regarding CCR Part A Rule demonstrations and compliance-related letters notifying certain facilities of their compliance obligations under the federal CCR regulations. The determinations and letters include interpretations regarding implementation of the CCR Rule. On April 8, 2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

On May 18, 2023, the EPA published a proposed rule that would expand the scope of CCR units regulated by the CCR Rule to include inactive surface impoundments at inactive generating facilities as well as additional inactive and closed landfills and certain other accumulations of CCR. It is too early to determine the outcome of this proposed rule and any potential impact.

The CCR rule, current or proposed amendments to the federal CCR rule or state/territory CCR regulations, the results of groundwater monitoring data, or the outcome of CCR-related litigation could have a material impact on our business, financial condition, and results of operations. AES Indiana would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard.

International Environmental Regulations

Chile

Chilean law requires all electricity generators to supply a certain portion of their total contractual obligations with NCRE. 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 Andes currently fulfills the NCRE requirements by utilizing AES Andes' solar, wind, and biomass power plants.

Since 2017, emissions of particulate matter, SO2, NOX, and CO2 are monitored for plants with an installed capacity over 50 MW; these emissions are taxed. In the case of CO2, the tax is equivalent to $5 per ton emitted. Certain PPAs have clauses allowing the Company to pass the green tax costs to unregulated customers, while some distribution PPAs do not allow for the pass through of these costs. During 2021, the Chilean General Water Direction, as part of the Ministry of Public Works, established the obligation to install and maintain effective


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monitoring systems for water withdrawal. The Company is currently implementing these systems in the power plants for which they are required.

During 2022, new regulations associated with enviromental monitoring requirements were published, including Law 21,455, which is the framework on climate change; the Ventanas power plant new Operational Plan; emission standards for back up generators; and recently enacted Law 21,505, which promotes electric energy storage and electromobility.

During 2023, increasingly demanding environmental regulations have been issued, which will require adjustments in controls throughout the life cycle of any investment project, that is, in the development, construction and operation phase. Environmental prevention and management models must be adjusted to prevent behaviors that could be considered environmental crimes, as well as investments performed to comply with new regulatory standards.

In this context, the following regulations were enacted:

Law No 21.595: Economic and Environmental Crimes Law, which includes the regulation of crimes of attacks against the environment, establishing effective prison sentences in addition to the financial responsibility of companies.
Law No. 21,600 creates the Biodiversity and Protected Areas Service; and
Decree No. 1/2022 Establishes the Emission Standard for Artificial Lighting generated by outdoor lighting, which changes the level of applicability of its requirements, expanding its scope of application at the national level and contemplating some stricter limits for protected areas.

In the coming months the following regulations are expected to be published:

New emission standards for thermoelectric power plants (standard under review since 2020);
New noise emission standard for fixed sources (under review since 2019); and
A modification to the System Regulations.

AES Andes and its subsidiaries are undergoing administrative environmental sanctions processes. The compliance program associated with the Ventanas power plant is being executed. The Angamos power plant is currently undergoing an environmental review process of its Environmental permit (RCA in Chile). See Item 3.—Legal Proceedings in this Form 10-K for further discussion.

Bulgaria

In July 2020, the EU approved the Next Generation EU ("NGEU") recovery instrument, which aims at mitigating the economic and social impact of the COVID-19 pandemic and making European economies and societies more sustainable. The main funding component of NGEU is the EU’s Recovery and Resilience Facility ("RRF"). In November 2023, the European Commission approved an amended version of Bulgaria's Recovery and Resilience Plan ("RRP") that describes the reforms and investments which Bulgaria wishes to make with the support of the RRF. In its RRP, Bulgaria commits to designing a coal phase-out plan aiming at retiring coal-fired power plants by 2038.

The plan includes a 40% reduction in carbon emissions by the end of 2025 and a ceiling on carbon emissions from 2026 onwards. The mechanism to achieve the target is undefined and the potential impact to Maritza's revenues is expected to be limited.

Brazil

In Brazil, the National Environmental Council ("CONAMA") is responsible for environmental licensing procedures. Inspections are performed by authorities at federal, state and municipal levels. The programs developed by AES Brasil are designed to restore and preserve biodiversity and are in compliance with local procedures and the obligations assumed in AES Brasil's concession with the state government. AES Brasil's main environmental projects include a flora management program which guarantees the production of 1 million seedlings of native tree species, a reservoir repopulation program that aims to maintain the ichthyofauna biodiversity and guarantee continuity of fishing activity by riverside communities, a land fauna monitoring and conservation program, and a water quality monitoring program designed to further understand the structure and functioning of aquatic ecosystems.


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In addition, the monitoring and control of reservoir edges is carried out through continuous inspections by the technical team of the Center of Monitoring of Reservoirs ("CMR") through a system of detection of changes, satellite images, aerophotogrammetric surveys, and field inspections.

Argentina

Argentina has agreed to commitments made by the international community ratified in the Paris Agreement and in Law 27,270 passed in September 2016.

In October 2015, Law 27,191 was passed, seeking to create a successful framework for the development of renewable energy. This law set an objective of 8% renewable energy by 2017 and 20% by 2025 and also introduced tax exemptions for importing equipment used in the construction of renewable energy projects in addition to other tax benefits. This framework fostered AES Argentina's construction of Vientos Bonaerenses and Vientos Neuquinos power plants, which are fully contracted with public and private customers in the long term.

In December 2019, Law 27,520 established a minimum budget to grant adequate actions, instruments, and strategies to mitigate and adapt to global climate change effects in all national territories and created the National Office of Climate Change to designate private and public actors to design policies aiming to reduce greenhouse gases and to provide coordinated responses in sectors that are vulnerable to climate change impacts.

All AES Argentina plants are certified under international standards of Quality (ISO 9001), Safety and Health (ISO 45.001) and Environment (ISO 14001).

Colombia

Decree 1076 of 2015 established the current Environmental Licensing Scheme that defines the scope of the National Environmental Licensing Authority ("ANLA") for granting environmental licenses. In recent years, the Ministry of the Environment has generated regulations in connection with licenses, such as the biotic compensation methodology and guidance for presentation of environmental studies in 2018, and the regulation of minor changes to environmental licenses in 2022.

In 2023, the ANLA begun the review of the reference terms for environmental impact studies and is working on a reform to the procedure for licensing process for non-conventional renewable energy projects. The following is highlighted in the regulatory proposal, which is expected to be processed during the first half of 2024:

All renewable energy projects would be licensed by ANLA.
The implementation of a new instrument called the Environmental Baseline, which would be used for decision-making regarding the development of Renewable Energy Projects.
Photovoltaic electricity generation projects that are developed on land classified as suburban, according to municipal planning plans, would not request an environmental license.

At the end of 2023, AES Colombia obtained the environmental license, issued by the ANLA, for the 500 kV line to connect the Guajira pipeline projects. Currently, AES Colombia has obtained environmental licenses for 406 MW of wind projects in Guajira.

Customers

We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2023 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. 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, 2023, the Company and its subsidiaries had approximately 9,600 full time/permanent employees.


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571

As of December 31, 2023, approximately 30% 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 2024 to 2026. In addition, certain employees in non-U.S. locations were subject to collective bargaining agreements, representing approximately 50% 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 2023 approximately 58% 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 2023, there was an 82% increase in LTI cases. In 2023, AES’ LTI Rate was 0.120 for AES People, 0.118 for operational contractors, and 0.076 for construction contractors. In 2023, the Company had one contractor work-related fatality.

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 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


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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:

Stephen Coughlin, 52 years old, has served as Executive Vice President and Chief Financial Officer since October 2021. Prior to assuming his current position, he led AES’ Corporate Strategy and Financial Planning teams, and served as the Chair of the Company’s Investment Committee. Prior to that role, he served as the Chief Executive Officer of Fluence. Mr. Coughlin joined AES in 2007 and spent his early years with the company leading Financial Planning & Analysis for AES’s renewables portfolio. Mr. Coughlin is a member of the boards of AES Clean Energy Development Holdings, LLC, AES U.S. Investments, Inc., AES U.S. Generation, LLC, and IPALCO. Mr. Coughlin received a bachelor's degree in commerce and finance from the University of Virginia and a Master of Business Administration degree from the University of California at Berkeley.

Bernerd Da Santos*,* 60 years old, has served as Executive Vice President and President of the Renewables SBU since June 2023. Previously, Mr. Da Santos held several positions at AES, including Chief Operating Officer and Executive Vice President from December 2017 to July 2023, Chief Operating Officer and Senior Vice President from 2014 to 2017, Chief Financial Officer, Global Finance Operations from 2012 to 2014, Chief Financial Officer of Global Utilities from 2011 to 2012, Chief Financial Officer of Latin America and Africa from 2009 to 2011, Chief Financial Officer of Latin America from 2007 to 2009, Managing Director of Finance for Latin America from 2005 to 2007, and VP and Controller of La Electricidad de Caracas (“EDC”) (Venezuela). Prior to joining AES in 2000, Mr. Da Santos held a number of financial leadership positions at EDC. Mr. Da Santos is a member of the boards of AES Brasil Energia S.A., AES Mong Duong Power Co. Ltd., IPALCO, and Son My LNG Terminal LLC. 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.

Ricardo Manuel Falú, 44 years old, has served as Executive Vice President and Chief Operating Officer since February 2024. Prior to assuming his current position, Mr. Falú was Senior Vice President and Chief Operating Officer since July 2023 and Senior Vice President and Chief Strategy and Commercial Officer since August 2022. Since March 2023, Mr. Falú has also served as President of the New Energy Technologies SBU. Mr. Falú joined AES in 2003 and, prior to his current roles, served as President of the Andes region from January 2022 to August 2022 and Chief Executive Officer of AES Andes from April 2018 to August 2022, which includes AES Chile, AES Colombia, and AES Argentina. Before that, Mr. Falú served as the Chief Financial Officer for the Company's businesses in the Andes region from 2014 to April 2018 and as Chief Financial Officer for the Company's businesses in the Mexico, Central American, and Caribbean region from 2012 to 2014. He is a member of the boards of Fluence Energy, Inc., AES Andes, IPALCO, AES Ohio, and AES Colombia. Prior to joining AES, Mr. Falú worked as an external auditor, accounting analyst, and financial consultant in Argentina. He holds a Certified Public Accountant degree from the Universidad Nacional de Salta in Argentina and an Executive MBA, graduating Summa Cum Laude from the IAE Business School. He also holds a diploma from the Wharton Advanced Management Program, a Certificate in Management from Darden, and has completed other executive financial and management studies at Darden, Wharton, and Harvard.

Paul L. Freedman, 53 years old, has served as Executive Vice President, General Counsel, and Corporate Secretary since February 2021. Prior to assuming his current position, Mr. Freedman was Senior Vice President and General Counsel from February 2018, Corporate Secretary from October 2018, Chief of Staff to the Chief Executive Officer from April 2016 to February 2018, Assistant General Counsel from 2014 to 2016, and from 2007 to 2014 he held a variety of other positions in the AES legal group. Mr. Freedman is a member of the Boards of, AES U.S. Investments, Inc., IPALCO, AES Ohio, and AES Southland Energy Holdings, LLC. Additionally, Mr Freedman is a member of the Boards of the Business Council for International Understanding and the Coalition for Integrity. Prior to joining AES, Mr. Freedman was Chief Counsel for credit programs at the U.S. Agency for International


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Development and he previously worked as an associate at the law firms of White & Case and Freshfields. Mr. Freedman received a B.A. from Columbia University and a J.D. from the Georgetown University Law Center.

Andrés R. Gluski*,* 66 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. Under his leadership, AES has become a world leader in implementing clean technologies, including energy storage and renewable power. Prior to assuming his current position, Mr. Gluski served as Executive Vice President and Chief Operating Officer of the Company from 2007 to 2011. Prior to that role, he served in a number of senior roles at AES, including as Regional President of Latin America and was Senior Vice President for the Caribbean and Central America. He is a member of the Board of Waste Management and serves as Chairman of the Americas Society/Council of the Americas. Mr. Gluski is a magna cum laude graduate of Wake Forest University and holds an M.A. and a Ph.D. in Economics from the University of Virginia.

Tish Mendoza, 48 years old, has served as Executive Vice President and Chief Human Resources Officer since February 2021. Prior to assuming her current position, Ms. Mendoza was Senior Vice President, Global Human Resources and Internal Communications and Chief Human Resources Officer from 2012, Vice President of Human Resources, Global Utilities from 2011 to 2012, Vice President of Global Compensation, Benefits and HRIS, including Executive Compensation, from 2008 to 2011, and acted in the same capacity as the Director of the function from 2006 to 2008. Ms. Mendoza is a member of the boards of IPALCO, Fluence Energy, Inc. and AES Ohio, and sits on AES’ compensation and benefits committees. Prior to joining AES, Ms. Mendoza was Vice President of Human Resources for a product company in the Treasury Services division of JP Morgan Chase and Vice President of Human Resources and Compensation and Benefits at Vastera, Inc, a former technology and managed services company. Ms. Mendoza earned certificates in Leadership and Human Resource Management, and a bachelor’s degree in Business Administration and Human Resources.

Juan Ignacio Rubiolo*,* 47 years old, has served as Executive Vice President and President of the Energy Infrastructure SBU since March 2023. Prior to assuming his current position, Mr. Rubiolo served as Executive Vice President and President of International Businesses from January 2022 to March 2023, Senior Vice President and President of the MCAC SBU from March 2018 to January 2022, as the Chief Executive Officer of AES Mexico from 2014 to March 2018, and as a Vice President of 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 Andes, AES Brasil Energia, and AES Colombia & Cia S.C.A. E.S.P. 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 April 27, 2023.

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


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associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to, or waivers from, the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.

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