AES CORP (AES) Business

ITEM 1. BUSINESS

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

Executive Summary

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

Our Strategy

AES is the next-generation energy company with over four decades of experience developing, operating, and owning electric generation and utilities.

The focus of our strategy is to partner with large corporations to deliver the electricity they need when they need it. We are very well-positioned as a leading provider of renewable energy to data center companies, particularly in the U.S., and to large mining companies outside the U.S. These customers want to work with AES due to our track record of providing customized solutions that best serve their specific needs and delivering our projects on time and on budget.

In 2025, we signed long-term contracts for 4.0 GW of renewables, bringing our backlog of projects — those with signed contracts, but which are not yet in operation — to 12.0 GW. Our backlog serves as one of the core components of our future growth. As a result of our successful execution of our strategy, 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.

At the same time, we have embarked on the most ambitious investment growth in the history of our U.S. utilities, which will improve the reliability and quality of service for our customers, while maintaining some of the lowest rates in both states where our utilities operate. AES Indiana and AES Ohio are now two of the fastest growth U.S. utilities, with projected double-digit rate base growth through 2027, based on necessary investments for our

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customers.

We are also seeing additional investment opportunities from data center growth in our utility service areas, above and beyond existing rate base projections. Our utilities have many natural advantages that are attractive to large technology companies, such as proximity to fiber networks and the presence of ample land and water. We have worked to proactively identify sites that are well-positioned to support new data centers, capitalizing on our deep relationships with technology companies.

2025 Strategic Highlights

•Our backlog, which consists of projects with signed contracts, but which are not yet operational, is 12.0 GW, including 5.7 GW under construction. In full year 2025, we:

◦Completed the construction of 3.2 GW of solar, energy storage, and wind; and

◦Signed or were awarded new long-term PPAs for 4.0 GW of renewables.

•At AES Indiana, filed with the IURC a partial settlement agreement for current rate review, as well as a 20-year IRP.

•At AES Ohio, received PUCO approval for its distribution rate case and filed for new multi-year base distribution rates for 2027 through 2029.

•With the sale of a minority interest in AGIC for $450 million in the first quarter of 2025, we achieved our full year 2025 asset sale proceeds target of $400 to $500 million.

Overview

Generation

We currently own and/or operate a generation portfolio of 34,740 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 and associated generation attributes under medium- or long-term contracts ("PPAs") 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. These contract sales and short-term sales may also include RECs, as discussed below.

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.

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

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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.

Our renewable energy generation businesses may also sell RECs under short-term contracts, either through bilateral sales or over commodity exchanges.

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 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.

54% of the capacity of our generation plants is fueled by renewables, including solar, hydro, wind, energy storage, and landfill gas, which do not have significant fuel costs.

29% of the capacity of our generation plants is 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.

15% 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 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.

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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 2.7 million customers and AES' two utilities in the U.S. also include generation capacity totaling 4,056 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 businesses in El Salvador face limited competition due to significant barriers to enter the market. According to El Salvador's regulation, large regulated customers have the option of becoming unregulated users and requesting service directly from generation or commercialization agents.

In general, our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers directly. Key performance drivers for utilities include the regulated rate of return and tariff, seasonality, weather variations, economic activity, and reliability of service. Revenue from utilities is classified as regulated on the Consolidated Statements of Operations.

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

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

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

The regulated tariff generally recognizes that our utility businesses should recover certain operating and fixed costs, as well as manage uncollectible amounts, quality of service, and technical and non-technical losses. Utilities,

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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 businesses, 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, such as the U.S. and Chile, 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. For some development projects, rather than advancing them through construction and maintaining long-term ownership of an operating facility, AES may monetize project value by entering into Develop-Transfer Agreements ("DTAs") in which we transfer assets to a third party prior to construction in exchange for appropriate compensation. AES also provides development services, where we enter into contracts to fully develop customized assets to meet customers' needs. These DTAs and development service contracts may be entered into for new generation facilities or other potential uses of our development assets, including for data centers.

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 New Energy Technologies (investments in Fluence, Maximo and other new and innovative energy technology businesses) — 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, transmit, distribute, 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, 2025 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,

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2025. 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.

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 19—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure.

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

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Renewables

Our Renewables SBU is well-positioned to take advantage of the growth in data centers driven by the increase in power demand for generative artificial intelligence. In 2025, our assets in operation grew to 17.8 GW, and we added an incremental 3.7 GW to our backlog of contracted projects.

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

Generation — Total operating installed capacity of the Renewables SBU is 17,836 MW. The following table lists our Renewables SBU generation facilities:

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

(2)Operated by AES under a concession contract granted for a term of 30 years. On January 9, 2026, upon expiration of the contract, ownership and possession of the power plant equipment was transferred by full right to a new operator, awarded with the new concession contract through an international bidding process carried out by the Argentine State in its capacity as grantor.

(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, which 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 on the Consolidated Balance Sheets, depending on the partnership rights of the specific project.

(4)The Cordillera Hydro Complex includes the Alfalfal, Queltehues, and Volcan hydroelectric plants.

(5)AES Andes acquired the remaining preferred shares in Cochrane ES in February 2026, increasing AES' equity interest in the plant to 100%.

(6)In January 2026, AES Andes sent a letter to the ISO requesting permanent disconnection as of April 30, 2026.

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

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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:

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 46 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' time to power, while delivering green attributes. The generation capacity of the systems owned and/or operated under AES Clean Energy is 10,961 MW across the U.S., with another 3,031 MW under construction, including 1,542 MW of wind, 939 MW of solar, and 550 MW of energy storage. AES Clean Energy has a 7.6 GW backlog of projects, the majority of which are expected to come online through 2029. 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, AES Clean Energy Development, and other renewables assets as part of its broader investments in the U.S. AES Clean Energy Development serves as the development vehicle for all future renewables projects in the U.S. AES Clean Energy Development is a leader in the U.S. renewables industry, and, in 2025, it added over 2.1 GW of high-quality projects to its backlog.

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 (including long-term REC contracts), 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 Inflation Reduction Act ("IRA"). In 2025, AES recognized $1.5 billion related to the monetization of tax attributes to tax equity investors and transferability tax credit buyers relating to U.S. renewables projects, $166 million of which relates to solar projects owned by our utility at AES Indiana. The financial results of U.S. renewables assets are primarily driven by the amount of wind or solar resource at the facilities, availability of facilities, growth in projects, the profitable development and sale of energy, RECs, and other generation attributes to customers, and by tax credit recognition once placed in service.

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The majority of solar projects under AES Clean Energy have been financed with tax equity structures, in which tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, which 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 2025, AES Clean Energy largely generated investment tax credits ("ITCs") from its renewable assets. ITCs and production tax credits ("PTCs"), as well as higher credits available for projects that satisfy wage and apprenticeship requirements under the IRA, increased demand for our renewables products in recent years. Also, in 2023, AES Clean Energy began monetizing tax credits under the transferability provisions of the IRA. These tax credit sales reduce our tax rate under U.S. GAAP.

AES Clean Energy's contracted and advanced stage development backlog is resilient to recent changes in the IRA. Recent guidance revising start of construction safe harbor thresholds is not expected to affect a substantial majority of AES Clean Energy projects already safe harbored, and, taking into account current project schedules, we do not currently expect any material impact to our backlog.

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. For corporate customers, this includes advanced 24/7 carbon‑free energy offerings tailored to support large energy‑intensive operations, such as hyperscale data centers, by combining renewables, storage, and load‑siting solutions. Concurrently, AES develops and delivers ready‑to‑build renewable energy projects and powered land for regulated utilities and corporate customers through Develop-Transfer Agreements, in which AES manages the full greenfield development process (including permitting, engineering, and procurement) and transfers the project once it reaches construction‑ready status. AES has worked with several major technology companies to provide clean energy solutions to power their networks of data centers, and we expect these relationships to expand as the rapid adoption of generative artificial intelligence drives significant growth in data center electricity demand.

In 2025, AES Clean Energy signed or was awarded 2,776 MW of PPAs. As of December 31, 2025, AES Clean Energy's renewables project backlog includes 7.6 GW of projects for which long-term PPAs have been signed or, as applicable, contracts have been assigned through a regulatory process. The budget for construction of the projects currently under construction and the contracted projects is over $12 billion. U.S. federal legislation includes tax credits for onshore wind, solar, and storage. These tax credits are supportive of our strategy to grow the AES Clean Energy business through the development of our 46 GW U.S. pipeline.

AES Chile

Business Description — AES Chile is engaged in the generation and supply of electricity (energy and capacity) in the SEN—see Energy Markets and Regulatory Environment below— through AES Andes, AES Pacifico Chile, and their subsidiaries. In total, AES operates 2,195 MW of renewable installed capacity in Chile, excluding energy storage, and has a market share of approximately 6% as of December 31, 2025. In addition, AES Chile has 768 MW of energy storage systems in operation.

AES Andes' Green Blend strategy aims to reduce carbon intensity and to incorporate renewable energy to extend our previous conventional PPAs by de-linking our PPAs from legacy fossil resources while growing our renewable energy portfolio. This strategy delivers a competitive and reliable energy solution for customers, AES Chile has committed 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 14 years with unregulated customers, such as mining and industrial companies, mainly with pricing indexed to CPI.

Key Financial Drivers — Hedging strategies at AES Chile 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 hydrological scenarios, forced outages, and international fuel prices);

•changes in current regulatory rulings, tax policies; and

•fluctuations of the Chilean peso.

Development Strategy — In Chile, AES is building wind, solar, and storage to supply AES Andes' agreements with its main mining customers. In total, the pipeline in Chile currently includes 5.5 GW under development at

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different stages and geographical locations.

AES Argentina

Business Description — In Argentina, AES owns and operates two fully contracted wind power plants totaling 200 MW and operates 157 MW of hydroelectric power plants. In addition, AES Argentina previously operated the 1,050 MW Alicura hydroelectric plant under a concession contract which ended on January 9, 2026. The total 1,407 MW represents 3% of the country's total installed capacity. 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 2025, approximately 70% of the energy sold was produced by the hydroelectric power plants and sold in the wholesale electricity market and the remaining 30% was 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;

•changes in hydrology and wind resources; and

•domestic energy demand and exports.

Development Strategy — In 2025, a subsidiary of AES Argentina began construction on the Vientos Bonaerenses 3 and 4 projects, two wind facilities totaling 102 MW. This new capacity is intended to be used in future private auctions for renewable PPAs.

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 Castilla, Brisas, and San Fernando solar facilities with capacity of 21 MW, 26 MW, and 61 MW, respectively. AES Colombia’s installed capacity accounted for approximately 5% of system capacity at the end of 2025. 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, and in 2025, all relevant permits for 259 MW were obtained. In 2025, AES Colombia executed an investment agreement for a partnership structure with Ecopetrol S.A. in connection with these projects. Under the terms of the partnership, the projects will be contributed to two trusts, which will own, construct, operate, and maintain the projects and sell the energy generated to Ecopetrol under a PPA.

AES Panama

Business Description — AES owns and operates five hydroelectric plants totaling 705 MW of generation capacity, a wind farm of 55 MW, and eight solar plants totaling 77 MW, which collectively represent 16% of the total installed capacity in Panama.

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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 regulating 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 renewables assets in the system and contribute to the reduction of hydrological risk in Panama.

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. In addition, in 2024, AES began construction on 485 MW of new renewables projects. 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, operational performance and plant availability.

Development Strategy — Development in Puerto Rico is primarily through the Marahu Project, which is 70% owned by AES and is currently constructing the Salinas and Jobos renewables projects, which include both solar and energy storage facilities.

AES Dominicana

Business Description — AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), two leading Dominican industrial groups that manage a diversified business portfolio, and with AFI Popular, a subsidiary of Grupo Popular. AES' ownership interest in AES Dominicana is 65%.

AES Dominicana has partnered with Total Energies Renewable Iberica S.L.U., in AES DR Renewables Holdings, S.L., a joint venture accounted for as an equity method investment, to operate four solar farms totaling 340 MW and a wind farm of 50 MW. AES' effective ownership interest in AES DR Renewables Holdings, S.L. and its subsidiaries is 33%.

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 renewables plants.

AES Mexico

Business Description — Mesa La Paz is a 306 MW wind project developed under a joint venture with Grupo Bal, located in Llera, Tamaulipas. Mesa La Paz sells its power under long-term PPAs with expiration dates up to

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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 is actively working to develop new renewable energy projects that may increase its market share in the Mexican National Energy System, with a strong commitment to provide energy support for the economic growth of the country.

AES Bulgaria

Business Description — AES owns an 89% economic interest in the St. Nikola wind farm ("Kavarna"), which has 156 MW of installed capacity. The power output of St. Nikola is sold to customers operating on the liberalized electricity market. In addition, the plant received additional revenue per the terms of an October 2018 Contract for Premium with the state-owned Electricity System Security Fund until the expiration of the agreement on March 15, 2025.

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.

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.

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 of this business as we have a controlling interest.

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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. at our two utilities: AES Indiana and AES Ohio. The expansion of advanced manufacturing and data centers has the potential to significantly accelerate the demand for electricity in the U.S. power markets. AES Indiana and AES Ohio have an obligation to serve customers who are located in our service territory and are working with several companies to provide solutions for the electric service needs of data centers and advanced manufacturing facilities. We see these relationships growing with the expansion of their use within our service territory. As part of this process, AES Indiana and AES Ohio are working to ensure that the costs of any required infrastructure upgrades benefit all customers, are fairly allocated, and follow regulatory principles that protect our customers.

In the Utilities segment, AES operates four utilities in El Salvador with installed operating capacity of 143 MW, as well as an integrated utility in Indiana, with installed operating capacity of 4,056 MW. IPALCO (the parent of AES Indiana), AES Ohio, and DPL LLC (formerly DPL Inc.) are all SEC registrants and therefore comply with the public filing requirements of the Securities Exchange Act of 1934.

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

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(1)AES Ohio's GWh sold in 2025 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 2,740 GWh in 2025. 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 nameplate generation capacity of approximately 2,390 MW. AES Ohio’s share of this generation is approximately 117 MW. On April 4, 2025, DPL sold an indirect equity interest in AES Ohio of approximately 30% to a wholly-owned subsidiary of CDPQ.

(2)CDPQ owns direct and indirect interests in IPALCO (AES Indiana's parent) which total approximately 30%. AES owns 85% of AES U.S. Investments and AES U.S. Investments owns 82.35% of IPALCO. AES Indiana plants: Georgetown, Harding Street, Petersburg, Eagle Valley, Hoosier Wind, Hardy Hills Solar, Pike County BESS, and Petersburg Energy Center. 20 MW of AES Indiana total is considered a transmission asset.

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.

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(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:

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 982,000 people.

AES Indiana owns and operates four generating stations, all within the state of Indiana. The first station, Petersburg, consists of two coal-fired units; however, AES Indiana is in the process of converting these remaining two coal-fired units to natural gas in 2026 (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. AES Indiana also 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 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 200 MW of wind-generated electricity and 94 MW of solar-generated electricity.

AES Indiana also owns four renewable energy facilities currently in operations, all within the state of Indiana. The first is a 195 MW solar project ("Hardy Hills Solar"). The second is a 106 MW wind facility ("Hoosier Wind"). The third is a 200 MW (800 MWh) battery energy storage project ("Pike County BESS"). The fourth is a 250 MW solar and 45 MW (180 MWh) energy storage facility ("Petersburg Energy Center").

On May 16, 2025, AES Indiana completed the acquisition of Crossvine Solar 1, LLC ("Crossvine"), including the development of 85 MW of solar and 85 MW (340 MWh) of energy storage which is expected to be placed in service in mid-2027.

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 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 (including a return) to comply with environmental laws and regulations and investments in renewable energy projects, and recovery of costs related to generation consumables and environmental allowance expenses, referred to as the ECCRA, (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 the timely recovery of costs (including a return) incurred 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

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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.

On April 17, 2024, the IURC issued an order (the “2024 Base Rate Order”) approving the Stipulation and Settlement Agreement that AES Indiana entered into on November 22, 2023, with the Indiana Office of Utility Consumer Counselor and the other intervening parties in AES Indiana’s base rate case filing. Among other matters and consistent with the Stipulation and Settlement Agreement, the 2024 Base Rate Order approves an increase in AES Indiana's total annual operating revenue of $71 million for AES Indiana’s electric service and provides a return on common equity of 9.9% and cost of long-term debt of 4.9% on a rate base of approximately $3.5 billion. Updated customer rates and charges became effective on May 9, 2024.

On June 3, 2025, AES Indiana filed a petition with the IURC 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 base rate increase request include inflationary impacts on O&M expenses and continued investments in generation, transmission, and distribution assets. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, storm restoration costs, and technology to enhance resiliency and reliability. On October 15, 2025, AES Indiana entered into a Stipulation and Settlement Agreement (the "Settlement") with most parties in AES Indiana's pending regulatory rate review at the IURC. This Settlement provides for updated base rates for electric services in AES Indiana's territory and is subject, and conditioned upon, approval by the IURC. Among other things, the Settlement proposes an increase in AES Indiana's revenue of $90.7 million and provides a return on common equity of 9.75% and cost of long-term debt of 5.34%, on a rate base of approximately $5.5 billion for AES Indiana's 2027 electric service base rates. The partial settlement agreement also includes a commitment to not implement additional base rate increases, following the implementation of new base rates under the Settlement, until at least January of 2030 and to not start a second TDSIC Plan before January of 2028. An evidentiary hearing with the IURC was held on January 28 and 29, 2026, and AES Indiana anticipates a final order from the IURC in the second quarter of 2026.

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. The first 80% 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, investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered with the TDSIC rider rate filings by six months as ordered by the IURC and are filed each December.

Integrated Resource Plan — In January 2025, AES Indiana initiated its 2025 Integrated Resource Plan ("IRP") process with external stakeholders. Public advisory meetings for the 2025 IRP took place in January, July, September, and October of 2025. On October 31, 2025, AES Indiana filed its 2025 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES

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Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a reliable and flexible generation mix for customers.

AES Indiana filed its 2022 IRP with the IURC in December 2022. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. Resulting from this IRP, AES Indiana also added three renewables projects to its generation portfolio: Pike County BESS, Hoosier Wind, and Crossvine.

On March 11, 2024, AES Indiana filed for regulatory approval from the IURC to convert Petersburg Units 3 and 4 from coal to natural gas and to recover costs through future rates. On November 6, 2024, the IURC issued an order approving the Petersburg repowering. Petersburg Unit 3 was taken offline in February 2026, and Petersburg Unit 4 is expected to be taken offline in June 2026. Construction activities are ongoing, with the units as converted expected to come back online for commissioning by May 2026 and October 2026, respectively.

AES Indiana expects to spend an estimated $4.2 billion on capital projects from 2026 through 2028. This total includes spending on 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. The estimated spending includes projects that are subject to regulatory approval, as well as estimated spending under AES Indiana's 2025 IRP.

AES Ohio

Business Description — DPL is a holding company whose principal indirect subsidiary is AES Ohio. AES Ohio is a utility company that transmits and distributes electricity to approximately 541,000 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.

The costs associated with providing wholesale transmission service, wholesale electric sales, and ancillary services are subject to FERC jurisdiction. AES Ohio uses a formula-based rate for its transmission service.

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.

AES Ohio ESP Appeal — From November 1, 2017 through December 18, 2019, AES Ohio operated pursuant

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to an approved ESP plan, which was initially approved on October 20, 2017 (ESP 3). On December 18, 2019, the PUCO approved AES Ohio's Notice of Withdrawal of ESP 3 and reversion to its prior rate plan (ESP 1). Among other items, the PUCO Order approving the ESP 1 rate plan included reinstating the non-bypassable RSC Rider, which provided annual revenue of approximately $79.0 million. The OCC has appealed to the Ohio Supreme Court the PUCO’s decision approving the reversion to ESP 1 as well as argued for a refund of the RSC revenue dating back to August 2021. Oral arguments regarding this appeal were held on April 22, 2025, and a court decision is pending.

Smart Grid Comprehensive Settlement — On October 23, 2020, AES Ohio entered into a Stipulation and Recommendation (the Settlement) with the staff of the PUCO, various customers and organizations representing customers of AES Ohio and certain other parties with respect to, among other matters, AES Ohio's applications for (i) approval of AES Ohio's plan to modernize its distribution grid (Smart Grid Phase 1), (ii) findings that AES Ohio passed the SEET for 2018 and 2019, and (iii) findings that AES Ohio's ESP 1 satisfies the SEET and the more favorable in the aggregate (MFA) regulatory test. On June 16, 2021, the PUCO issued their opinion and order accepting the stipulation as filed. The OCC appealed the final PUCO order with respect to the 2018 and 2019 SEET to the Ohio Supreme Court on December 6, 2021. Oral arguments regarding this appeal were held on April 2, 2025. The Ohio Supreme Court reversed the PUCO's opinion and order with respect to the methodology used by the PUCO to support its findings related to the 2018 and 2019 SEET, and remanded the case to the PUCO to conduct further analysis of the SEET for those years. AES Ohio filed testimony with the PUCO proposing a refund of $1.6 million based on analysis by its external financial consultant. The PUCO commenced an evidentiary hearing on this issue on October 28, 2025, and a PUCO decision is pending.

Smart Grid Phase 2 Plan — In February 2024, AES Ohio filed a Smart Grid Phase 2 with the PUCO proposing a ten-year investment plan to begin after Smart Grid Phase 1 ends. On September 13, 2024, AES Ohio reached a settlement with the PUCO staff and other parties on the pending Smart Grid Phase 2 application and an evidentiary hearing was held on October 29, 2024. A fundamental premise of the Application was the continued availability of rider recovery of Smart Grid investments through the plan period. However, with the recent enactment of House Bill 15 described above, which prohibits AES Ohio from applying for a new electric security plan which includes certain rider recovery mechanisms, as well as the near-term financial uncertainty created by the statute, AES Ohio withdrew its Smart Grid Phase 2 Application on May 23, 2025. On July 9, 2025, the PUCO approved the withdrawal and closed the case. This withdrawal will provide AES Ohio flexibility as to the timing and scope of Smart Grid investments to continue to deliver benefits to customers.

ESP 4 — 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 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 "ESP 4 Settlement") with respect to AES Ohio’s ESP 4 application, and, in August 2023, the PUCO issued their opinion and order accepting the ESP 4 Settlement as filed. AES Ohio is currently operating under this ESP 4 until its expiration, which was extended to May 31, 2027 based on House Bill 15, unless superseded by a Commission-approved Three-Year Rate Plan and MRO.

2024 Distribution Rate Case — On November 29, 2024, AES Ohio filed a distribution rate case with the PUCO. The investments reflected in this distribution rate case include investments to enhance the safety, reliability, and resilience of the distribution system. The application was based on a date certain of September 30, 2024 and a test period of June 1, 2024 - May 31, 2025. On June 27, 2025, the PUCO Staff submitted their Report and Recommendations. On August 13, 2025, AES Ohio entered into an unopposed Stipulation and Recommendation (the “2024 DRC Settlement”) with various intervening parties and the Staff of the PUCO and on November 5, 2025, the PUCO issued their opinion and order accepting the 2024 DRC Settlement as filed. The 2024 DRC Settlement provides for updated base rates for electric distribution service customers in AES Ohio’s service territory and among other matters includes: (i) An increase to its annual distribution revenue requirement of $167.9 million, which incorporates certain investments that are currently recovered through the Distribution Investment Rider; (ii) a return on equity of 9.999% and a cost of long-term debt of 4.49% on a distribution rate base of $1.25 billion and based on a capital structure of 53.87% equity and 46.13% long-term debt; and (iii) the net recovery of certain expenditures by AES Ohio, primarily related to one-time costs supporting the implementation of AES Ohio’s customer billing system upgrade.

Ohio Energy Legislation and Three-Year Rate Plan — On April 30, 2025, the Ohio legislature passed new energy legislation (House Bill 15) that was signed by the Governor and became effective August 14, 2025. The legislation allows Ohio’s electric utilities to file three-year forecasted base distribution rate cases, which would

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replace ESPs and associated recovery riders. AES Ohio currently anticipates that remaining recovery rider balances would be included in future base rates. Among other provisions, the legislation eliminates, as of its effective date, the LGR, which previously allowed for recovery of net OVEC costs and revenues. Changes to the regulatory framework from this legislation, including the recovery of future net OVEC costs and revenues or remaining recovery rider balances, could be material to our results of operations, financial condition, and cash flows.

To comply with House Bill 15, AES Ohio filed an application with the PUCO on November 10, 2025 to establish a Three-Year Rate Plan. This plan describes the investments necessary to strengthen and modernize AES Ohio's infrastructure and expand support for its customers. To enable these ongoing investments, the application also proposes rates for future electric distribution service in 2027, 2028, and 2029. The PUCO has set the evidentiary hearing to begin August 4, 2026, and a Commission Order is anticipated by the end of 2026.

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 $1.6 billion on capital projects from 2026 through 2028, which includes expected spending under AES Ohio's Smart Grid Phase 1 described above, as well as other transmission and distribution additions and improvements. AES Ohio's spending programs are contingent on, among other events, successful regulatory outcome in pending proceedings.

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 4,744 GWh of the market energy sales during 2025. 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, and Meanguera del Golfo, a solar and battery storage facility with 1 MW capacity; as well as AES Nejapa, a biomass power plant with 6 MW capacity; and 50% of Bosforo and Cuscatlan, 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. Electromobility 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 solar farm, 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.

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Energy Infrastructure

Our Energy Infrastructure SBU aims to provide energy security to enable the integration of new renewables and maximize the value of our gas generation and LNG business through flexible operations that support the energy transition. 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.

Generation — Operating installed capacity of our Energy Infrastructure segment totals 12,705 MW. The following table lists our Energy Infrastructure segment generation facilities:

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

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

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

(4)AES Andes acquired the remaining preferred shares in Cochrane in February 2026, increasing AES' equity interest in the plant to 100%.

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

(6)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. Enadom is an unconsolidated entity, accounted for as an equity affiliate.

U.S. Conventional Generation

Business Description — In the U.S., we own a conventional generation portfolio. The principal markets and

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locations where we are engaged in the generation and supply of electricity (energy and capacity) are the California Independent System Operator ("CAISO") and Puerto Rico. AES Southland, operating in the CAISO, is our most significant generation business. In 2023, the Company closed on an agreement to terminate the PPA for the Warrior Run coal-fired power plant, which continued providing capacity through May 2024 before ending commercial operations.

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 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.

Our non-qualifying facility ("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 2,823 MW at the end of 2025. The four 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 two once-through cooling ("OTC") power plants and two combined cycle gas-fired generation facilities. This critical infrastructure is uniquely situated to support California in its transition to renewables with baseload gas-fired generation sited at high-demand points of interconnection within the Los Angeles Basin.

Southland — Southland comprises AES Huntington Beach, LLC and AES Alamitos, LLC ("Southland OTC units"). Commencing on January 1, 2024, the Southland OTC units 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 Resource Adequacy Purchase Agreements (“RAPAs”) with annual energy tolling put options. If Southland Energy exercises the annual put option, all capacity, energy, and ancillary services will be sold

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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 9% 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 2025, approximately 86% of the energy was sold in the wholesale electricity market and 14% was sold under contract by the TermoAndes power plant.

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 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. Given that the sale did not close by the deadline specified in the agreement, AES exercised its right to terminate the agreement and remains the owner of its entire 51% interest.

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.

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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 a joint venture agreement with PetroVietnam Gas, and in April 2022, established Son My LNG Terminal LLC, in which AES has a 39% interest. 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 Chile

Business Description — In Chile, AES owns and operates Cochrane and Angamos, two coal-fired power plants with a total combined installed capacity of 1,108 MW, representing a market share of approximately 3% as of December 31, 2025.

Cochrane currently has long-term contracts with an average remaining term of approximately 10 years with mining customers, mainly with pricing indexed to CPI.

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

•spot market prices (largely impacted by dry hydrological 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 — 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, disposal, or shutdown of the following coal-fired plants:

•Ventanas 1 and Ventanas 2 coal-fired units were disconnected from the SEN as of June 30, 2022 and December 31, 2023, respectively.

•Norgener 1 and Norgener 2, with an installed capacity of 276 MW, were disconnected from the SEN on April 15, 2024.

•Ventanas 3 and Ventanas 4, with an installed capacity of 537 MW, were sold on January 13, 2025.

•The Angamos units have an installed capacity of 558 MW and have publicly announced phase-out plans, once the safety, sufficiency, and competitiveness of the system allows it, which has not yet occurred.

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 have successfully migrated from the legacy market to the new energy regime established by the Electric Industry Law of 2021 and both are operating according to ISO instructions.

Merida is a CCGT located on Mexico's Yucatan Peninsula that sold power to CFE under a PPA until December 8, 2025, when the plant successfully migrated to the Wholesale Electricity Market ("WHEM") under the new Electricity Sector Law ("LESE"). The LESE permit allows Merida to sell power in the WHEM for one year, until December 8, 2026, and to trade energy and capacity contracts with third parties, while securing natural gas and diesel under flexible contracts to ensure reliable and continuous operation. The permit term is subject to negotiations with authorities for a possible extension.

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;

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•changes in the methodology to calculate spot energy prices or Locational Marginal Prices, which impacts the excess energy sales to the CFE (see Energy Markets and Regulatory Environment below) in TEG and TEP under self-supply scheme; and

•improved operational performance and plant availability.

AES Panama

Business Description — In Panama, AES owns and operates Colon, a 381 MW combined cycle power plant fueled by natural gas. In partnership with InterEnergy, AES also entered into a joint venture to build and operate the Gatun facility, a 670 MW combined cycle gas power plant. The Gatun plant began commercial operations in open cycle mode in October 2024 and commenced combined cycle operations in May 2025. Furthermore, AES owns and operates an LNG regasification facility, a 180,000 cubic meter net storage tank, and a truck loading facility.

Colon 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 us 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 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 679 MW of installed thermal capacity, AES provides 9% of the country's capacity and supplies approximately 16% of the country's energy demand via these generation facilities. 575 MW are contracted with government-owned distribution companies.

AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), two leading Dominican industrial groups that manage a diversified business portfolio, and also with AFI Popular, a subsidiary of Grupo Popular. AES' ownership interest in AES Dominicana is 65%.

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 Dominicana has a 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 and an LNG facility of 120,000 cubic meters, including additional storage, regasification, and truck loading capacity.

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

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•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 Jordan

Business Description — In Jordan, AES has a 10% ownership 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 10% ownership interest in the IPP4 plant, a 250 MW oil/gas-fired peaker plant fully contracted with the national utility until 2039. Following the sale of approximately 26% ownership interest in both plants in March 2024, Amman East and IPP4 were deconsolidated and are accounted for as equity method investments.

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New Energy Technologies

Our New Energy Technologies SBU encompasses AES' efforts to incubate innovative solutions and invest in businesses that leverage cutting-edge technology to provide greener and smarter energy solutions, accelerating the energy transition. These activities enhance AES' competitive advantages in its businesses while enabling the growth of new business platforms. This segment includes ownership stakes in third-party platforms and internally developed initiatives, such as investments in Fluence, Maximo, the AI Fund, Uplight, and 5B.

Fluence, the AI Fund, 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. AES has a 100% ownership interest in Maximo, a consolidated entity.

In 2025, AES furthered its partnership with the AI Fund to combine its power sector expertise with the fund's artificial intelligence capabilities, leveraging generative AI technology to address bottlenecks in the energy transition. At the same time, AES made significant advancements with Maximo, an AI-powered robot designed to enhance the speed, efficiency, and safety of solar installations.

Fluence

Business Description — Fluence, created in 2018 as a joint venture by AES and Siemens AG, is a leading global provider of energy storage and services and AI-enabled digital applications for renewables and storage.

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On November 1, 2021, Fluence Energy, Inc. completed its IPO and is listed on Nasdaq under the symbol "FLNC". AES holds Class B-1 common stock, granting five votes per share held, and continues to hold its economic interest in the operating subsidiary of Fluence Energy, Inc. As of December 31, 2025, AES holds a 28.19% economic interest in Fluence and the Company accounts 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.

Development Strategy — The grid-connected energy storage sector is undergoing rapid expansion. 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. The global utility scale market, excluding China, will add approximately 3,201 GWh of energy storage capacity between 2024 and 2035, according to the Bloomberg NEF 2H 2025 Energy Storage Market Outlook, published in October 2025. Additional growth opportunities exist in providing 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 7.2 GW of energy storage assets deployed and 9.7 GW of contracted backlog, with a gross global pipeline of 41.8 GW as of December 31, 2025.

Maximo

Business Description — Maximo is an AI-enabled robot that enhances solar module installation speed, efficiency, and safety. Maximo enhances the safety and scalability of solar installation by automating the heavy lifting for placing and attaching solar modules. It accelerates project timelines and creates new high-tech jobs on solar construction sites. As of December 31, 2025, AES had a fleet of five Maximo units in operation that assisted with construction at the 2 GW Bellefield solar-plus-storage facility in California. The Company expects to expand its fleet to serve a growing backlog of installation contracts in 2026.

Key Financial Drivers — Maximo’s financial results are driven by the growth in its module installation service revenue, an efficient cost structure that is expected to benefit from increased robotic automation of field operations, and profit margins on customer contracts with solar EPC companies.

Development Strategy — Maximo serves the growing demand for grid scale solar project construction from AES and other leading owners by enabling the EPC companies to deliver projects faster and more efficiently. The Maximo team leverages AES’ knowledge and relationships with EPCs, proprietary AI and robotics expertise, and field operations capabilities to offer a compelling solution for solar module installation at grid scale utility projects.

AI Fund

Business Description — In 2024, AES formed a partnership with the AI Fund, an AI-focused venture studio, to co-develop AI-based businesses. In 2025, AES made its first equity investments in two co-built companies.

Key Financial Drivers — Each of the companies co-built by AES and the AI Fund follows a software-as-a-service business model. These companies’ financial results are driven by the rate of growth of new customers and the extension of additional services to existing customers.

Development Strategy — AES' collaboration with the AI Fund is designed to create new businesses that support AES' core business operations. In 2025, two co-built companies developed commercial products, and AES was the first company to test and use the first versions of these products.

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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 Coordinador Electrico Nacional ("CEN"). The SEN has an installed capacity of 34,931 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, solar capacity represents the majority of installed capacity. The fuels used for thermoelectric generation, mainly coal, diesel, and LNG, are indexed to international prices. In 2025, the installed capacity in the Chilean market was composed of thermoelectric (36%), solar (30%), hydroelectric (21%) and wind (13%) generation.

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 0.3 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.

In addition to energy payments, generators also receive capacity payments to compensate for availability during periods of peak demand. 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.

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-term 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.

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The Dominican Republic has one main interconnected system with 7,480 MW of installed capacity, composed of thermal (64%), solar (21%), hydroelectric (8%), and wind (7%) generation.

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 originally applicable from 2023 until 2027.

AES El Salvador distribution rates are regulated by the General Superintendence of Electricity and Telecommunications and are established through a traditional cost-based rate-setting process. AES El Salvador is permitted to recover its costs of providing distribution services 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 2,563 MW of installed capacity, composed of thermal (53%), hydroelectric (24%), biomass (11%), solar (10%), and wind (2%) generation.

Bulgaria

The electricity sector in Bulgaria is regulated by the Bulgarian Energy Act. The Bulgarian electricity market allows both regulated and competitive segments. NEK ceased to be the public provider of electricity at the end of June 2025. From July 2025 onwards, Bulgarian distribution companies serving the regulated market are sourcing their electricity needs exclusively from a special segment of the market where NEK is the main supplier through their energy mix (consisting of NEK-owned HPPs, NPP Kozlodui, state owned TPP Maritza East 2, and AES Maritza). 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 17 GW of installed capacity enabling the country to meet and exceed domestic demand and export energy. Installed capacity is primarily composed of solar (34%), thermal (31%), hydro (19%), and nuclear (12%) generation.

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

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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.

Panama's current total installed capacity is 5,077 MW, composed of thermal (43%), hydroelectric (36%), solar (14%), and wind (7%) generation.

Mexico

Mexico's main electrical system is called the National Interconnected System, 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. 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.

Mexico’s new Electricity Sector Law (LSE) and its Regulations (RLSE), enacted in 2025, replaced the previous framework to centralize control under the state-owned CFE. The reform reinforces the State’s leading role in the electricity industry, preserving transmission and distribution as exclusive state services, while redefining the conditions for private participation in generation and commercialization. The new regulations establish sector planning guidelines, introduce rules for private investment, and implement binding planning mechanisms that condition the approval and development of new projects.

In addition to the Ministry of Energy, three main agencies are responsible for regulating market agents and their activities, monitoring compliance with laws and regulations, and 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 of 92 GW, composed of thermal (64%), hydroelectric (14%), solar (8%), wind (8%), and other fuel (6%) generation.

Argentina

Argentina has one main power system, the SADI, which serves 92% of the country. As of December 31, 2025, the installed capacity of the SADI totaled 44,177 MW. The SADI's installed capacity is composed of thermoelectric (57%), hydroelectric (23%), wind (10%), nuclear (4%), and solar (6%) generation.

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.

The Argentine electricity market operated under a tolling scheme up to and including October 2025. In this structure, the regulator established both electricity prices and reference fuel prices. For energy sold to the spot market, generators received compensation for fixed costs and non-fuel variable costs, typically denominated in Argentine pesos. CAMMESA was in charge of providing the natural gas and liquid fuels required by the generation

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companies, except for coal. Energy sold through specific PPAs, such as Energía PLUS by TermoAndes, required generators to procure their necessary fuel at a reference price established by the regulator.

The regulatory landscape underwent a significant transformation with SE Resolution 400/25, effective November 2025, which instituted new rules for the wholesale energy market and its progressive adaptation. The new remuneration framework requires generators to manage their fuel supply and declare their variable production cost based on established reference values, while allowing the contracting of energy and/or capacity based on bilaterally negotiated terms. This transition also involved defining prices for demand and the implementation of marginal cost signals for energy traded in the spot market.

During 2025, despite the tariff increase to the end-user implemented by the government, subsidies remain a necessary component to cover the system's operating deficit. While the proportion of the total cost recovered by distribution companies increased to 70%, these funds are still essential for the system's sustainability.

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 the commercial operations date of the related plant. 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, not to exceed 30%, once the accounts receivable have been fully repaid.

In 2024 and 2025, the Argentine peso devalued against the USD by approximately 22% and 29%, respectively, and Argentina’s economy continued to be highly inflationary. Since September 2019, currency controls have been established to govern the devaluation of the Argentine peso and keep Argentine central bank reserves at acceptable levels.

Colombia

Electricity supply in Colombia is concentrated in one main system, the SIN, which encompasses one-third of Colombia's territory and provides electricity to 99% of the country's population. As of December 31, 2025, the SIN's installed capacity was 21,040 MW, composed of hydroelectric (63%), thermal (30%), and other renewables (7%) generation. The marked seasonal variations in Colombia's hydrology result in price volatility in the short-term market. In 2025, 81% 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.

In addition to the reliability charge, the Colombian electricity sector has an additional reliability mechanism known as the risk of shortage statute, established by CREG resolution 026 of 2014. This mechanism is triggered under specific critical hydrological conditions, during which certain reservoirs are utilized to conserve water, thereby increasing thermal dispatch. It was first triggered during late September 2024 until late November 2024.

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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 82 GW. The fuel mix in Vietnam is composed primarily of coal (32%), hydroelectric (29%) and renewables generation, including solar, wind, and biomass (26%). EVN, the national utility, owns 38% of installed generation capacity.

Vietnam is implementing a multi-step process to create a competitive electricity market. The first step taken in 2012 was to separate the generation segment of EVN into different joint-stock companies and to create a Competitive Power Market which was effective until 2019. In this market, all generation companies bid into the market and sell to a single buyer which is also owned by EVN. The next step taken in 2019 was to replace the Competitive Power Market with the Electricity Wholesale Market, in which there are several buyers, called EVN Power Corporations, all of which are subsidiaries of EVN. The final step, which is yet to be implemented, is the creation of the Electricity Retail Market, in which non-EVN-owned buyers would be allowed, and direct sales and purchases between retailers and generators would be feasible. The Mong Duong 2 power plant is a BOT plant and does not directly participate in the electricity market. The offtaker bids Mong Duong 2’s tariff into the market on its behalf.

At the end of November 2024, a new electricity law was passed by the National Assembly. The new law provides for a comprehensive reform of the legal framework in the power and energy sector of Vietnam after two decades under the current electricity law of 2004. It provides an improved legal environment for the energy sector, including but not limited to imported LNG power, green hydrogen and ammonia, offshore wind, nuclear power, low-emission conversion, emergency power projects, minimum long-term contracted electricity output, DPPA, and a fuel cost pass-through mechanism.

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 renewables portfolio standard.

Puerto Rico's electricity is 95% produced by thermal plants (50% from petroleum, 37% from natural gas, and 8% from coal), while the remaining 5% is supplied by renewable sources (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.

U.S. Utilities

See Item 1.—Business—Segments—Utilities for further discussion of the energy markets and regulatory environment of our utilities in the U.S. — AES Indiana and AES Ohio.

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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), species and habitat protections, 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 has often 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, numerous environmental laws and regulations regulate emissions of SO2, NOX, particulate matter, GHGs, mercury, hazardous air pollutants, water discharges, waste management, and species and habitat protections. 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 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.

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 and includes enhancements to the revised Group 3 trading program. On June 27, 2024, the U.S. Supreme Court issued an order granting a stay of the EPA’s 2023 FIP pending resolution of legal challenges to the FIP.

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On November 6, 2024, the EPA published an Interim Final Rule in the Federal Register in response to the U.S. Supreme Court’s stay of its FIP addressing interstate transport for the 2015 ozone national ambient air quality standards. The Interim Final Rule stays the effectiveness of the Good Neighbor FIP and revises the CSAPR regulations to continue application of the states’ respective trading programs. 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.

New Source Performance Standards for Stationary Combustion Turbines — On December 13, 2024, the EPA published a proposed rule that would revise the NSPS regulating NOX and SO2 from certain new, modified, and reconstructed stationary combustion turbines ("CTs"). On January 15, 2026, the EPA issued a final rule establishing more stringent NOX emissions standards for certain CTs while retaining the existing SO2 standards. The final rule establishes NOX emissions limits based on selective catalytic reduction ("SCR") for new, large, high utilization combustion turbines. NOX emissions limits for other new, modified, and reconstructed CTs are based on combustion controls without SCR. The revised standards apply to affected sources that begin construction, modification, or reconstruction after December 13, 2024. We cannot predict the possible outcome or potential impacts of this matter at this time.

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. On October 2, 2025, the EPA published an advanced notice of proposed rulemaking requesting public input on potential future changes to the Regional Haze Rule. On January 6, 2026, the EPA published a final rule extending the deadline for states to submit implementation plans for the third planning period from July 31, 2028 to July 31, 2031. To date, none of the states in which we operate have submitted plans that identify 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 criteria 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.

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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.

On May 7, 2024, the EPA published a final rule to revise MATS for coal and oil-fired electric generating units ("EGUs") which lowers certain emissions limits and revises certain other aspects of MATS. The May 2024 MATS revision rule is subject to legal challenges. On June 17, 2025, the EPA published a proposed rule to repeal the majority of the May 7, 2024 final rule revising MATS. On February 20, 2026, the EPA released a pre-publication version of a final rule repealing the majority of the May 7, 2024 MATS revision rule. We are still reviewing the final rule, and it is too early to determine the potential impacts.

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 — On May 9, 2024, the EPA published the final NSPS requiring carbon capture and sequestration for new and reconstructed baseload stationary combustion turbines, among other requirements. The EPA did not finalize revisions to the NSPS for newly constructed or reconstructed coal-fired electric utility steam generating units as proposed in 2018.

Following prior rulemakings and litigation related to regulations for GHG emissions from EGUs, on May 9, 2024, the EPA published the final rule regulating GHGs from existing EGUs pursuant to Section 111(d) of the Clean Air Act and effective on July 8, 2024. Existing EGUs are those that were constructed prior to January 8, 2014. Depending on various EGU-specific factors, the bases of emissions guidelines for natural gas-fired units include the use of uniform fuels and routine methods of operation and maintenance and the bases of emissions guidelines for coal-fired units include 40% natural gas co-firing or carbon capture and sequestration with 90% capture of CO2 depending on the date that coal operations cease. Specific standards for performance for EGUs will be established through a State Plan (or a Federal Plan if a state were to not submit an approvable plan). The May 2024 rule is subject to legal challenges.

On June 17, 2025, the EPA published a proposed rule to repeal the May 9, 2024 final rules for new and existing EGUs in addition to 2015 greenhouse gas new source performance standards for certain new EGUs. In this proposed rule, the EPA also offered an alternative proposal to repeal a narrower set of greenhouse gas requirements which would include the repeal of requirements for existing EGUs and requirements based on carbon capture and sequestration for new EGUs. On September 16, 2025, the EPA published a proposed rule to remove certain greenhouse gas emissions reporting obligations from source categories, including electricity generation and electrical transmission and distribution equipment use. On February 18, 2026, the EPA published the final rule to rescind the 2009 greenhouse gas endangerment finding (which had concluded that greenhouse gases endanger public health and welfare). It is too early to determine the potential impact of these rules, and the results of further proceedings and potential future greenhouse gas emissions regulations remain uncertain, but could be material.

Following prior withdrawal and rejoining, in January 20, 2025, President Trump issued an Executive Order titled “Putting America First in International Environmental Agreements” directing the U.S. Ambassador to the United Nations to formally withdraw from the Paris Agreement. The international community has and continues to gather annually for the Conference to the Parties on the UN Framework Convention on Climate.

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

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.

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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.

Certain AES Southland OTC units were required to be retired to provide interconnection capacity and/or emissions credits prior to startup of new (air cooled) generating units, and the remaining AES OTC generating units in California have been or will be shut down and permanently retired by the applicable OTC Policy compliance dates for the respective units. The SWRCB OTC Policy currently requires the shutdown and permanent retirement of the remaining OTC generating units at AES Huntington Beach, LLC and AES Alamitos, LLC by December 31, 2026, as extended in support of grid reliability. This extension compliance date is contingent upon the facilities participating in the Strategic Reserve established by AB 205.

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. The Company anticipates that compliance with CWA Section 316(b) regulations and associated costs could have a material impact on our consolidated financial condition or results of operations.

Water Discharges — The concept of Waters of the United States ("WOTUS") defines the geographic reach and authority of the U.S. Army Corps of Engineers and the EPA (together, 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 the “Revised Definition of ‘Waters of the United States’” rule. This final rule amendment conforms the definition to the definition adopted in the Decision. On March 12, 2025, the Agencies issued a joint guidance memorandum for implementing the “continuous surface connection” consistent with the Decision and related issues. On March 24, 2025, the Agencies published notice outlining a process to gather recommendations for implementation of WOTUS. On November 20, 2025, the Agencies proposed revisions to align the definition of WOTUS with the Decision to clarify federal jurisdiction under CWA. 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. AES Indiana Petersburg has installed a dry bottom ash handling system in response to the CCR rule and wastewater treatment systems in response to the NPDES permits in advance of the ELG compliance date. Other U.S. businesses already include dry handling of fly ash and bottom ash and do not generate flue gas desulfurization wastewater. 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 March 29, 2023, the EPA published a proposed rule revising the 2020 Reconsideration Rule. On May 9, 2024, the EPA published a final rule which became effective on July 8, 2024. The final rule established more stringent best available technology limits for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate and established a new set of definitions and new limits for combustion residual leachate and legacy wastewater. The May 2024 rule

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is subject to legal challenges. On October 10, 2024, the Eighth Circuit Court denied stay applications. On October 2, 2025, the EPA published a proposed rule that, if finalized, would extend certain ELG deadlines and allow facilities to choose between compliance alternatives. On the same date, the EPA also published a direct final rule to extend the deadline for power plants to file a notice of planned participation for the permanent cessation of coal from December 31, 2025, to December 31, 2031 pending any significant adverse comments. On November 28, 2025, the EPA withdrew the direct final rule due to receipt of adverse comments. On December 31, 2025, EPA published a final rule that extended ELG deadlines for bottom ash transport water, flue gas desulfurization wastewater, and combustion residual leachate, allowed facilities to choose between compliance alternatives, and extended the deadline for power plants to file a notice of planned participation for the permanent cessation of coal from December 31, 2025, to December 31, 2031. The rule is subject to legal challenges. 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. However, in February 2025, the EPA pulled back the guidance before it cleared the Office of Management and Budget. 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 existing CCR landfills and CCR surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. The 2016 Water Infrastructure Improvements for the Nation Act ("WIN Act") 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. Following prior rulemaking development and comment periods, on December 18, 2025, the Indiana Environmental Rules Board adopted a final CCR rule that includes regulation of CCR through a state permitting program. The rule and permitting program would become effective upon approval by the EPA. The EPA has indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

On May 8, 2024, the EPA published final revisions to the CCR rule which expand the scope of CCR units regulated by the CCR Rule to include legacy surface impoundments, inactive surface impoundments, and CCR management units. The May 8, 2024 revisions to the CCR Rule are currently subject to legal challenges. On February 10, 2026, the EPA published a final rule extending certain deadlines for coal combustion residual management units associated with its May 8, 2024 revisions to the CCR Rule. It is too early to determine the potential impact from these revisions to the CCR Rule.

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.

Trump Administration Actions Affecting Environmental Regulations — On January 20, 2025, President Trump issued an Executive Order titled “Unleashing American Energy” directing Agencies to, among other tasks, review regulations issued under the prior Administration to determine whether they should be suspended, revised, or rescinded. The Trump Administration also issued a Memorandum titled “Regulatory Freeze Pending Review” directing Agencies to refrain from proposing or issuing any rules until the Trump Administration has reviewed and approved those rules. In accordance with these and other Trump Administration Executive Orders, on March 12,

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2025, the EPA released a list of environmental regulations that will be targeted for reconsideration and other deregulatory action. These and other actions, including other Executive Orders and directives from the Trump Administration, may have an impact on regulations and permitting processes that may affect our business, financial condition, or results of operations.

International Environmental Regulations

Chile

During the 2020s, Chile developed a decarbonization and climate adaptation framework that requires a reorientation of the planning of the electricity sector: the Framework Law on Climate Change (published in June 2022) sets long-term objectives, including emissions neutrality, and creates instruments to integrate mitigation and adaptation into sectoral policies that condition permits, planning, and technical requirements in generation and transmission.

In 2023, increasingly demanding environmental regulations were issued, which require adjustments in controls throughout the life cycle of any investment project in the development, construction, and operation phase. Environmental prevention and management models were adjusted to prevent behaviors that could be considered environmental crimes, and investments were undertaken to comply with new regulatory standards.

In February 2024, Supreme Decree No. 30/2023 came into effect, amending the Regulations of the Environmental Impact Assessment System to align them with obligations arising from the Framework Law on Climate Change (Law 21.455) and the Escazú Agreement. The new regulations introduce more stringent criteria for environmental assessment.

In September 2025, Law No. 21.770, the Framework Law on Sectoral Authorizations, was enacted and published in the Official Gazette. This law establishes a general framework for sectoral permitting processes for regulated projects with the aim of simplifying, standardizing, and coordinating the various administrative procedures across different government agencies. The legislation seeks to reduce processing times for sectoral permits by an estimated 30% to 70%.

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.

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).

See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Argentina for further discussion on regulations impacting energy matters.

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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. As a result of the introduction of non-conventional renewable energy projects, various regulations were issued regarding the environmental permits applicable to these types of projects and the participation of indigenous communities in environmental licensing processes.

The following is a summary of the environmental regulatory issues that were formalized in 2024 and 2025:

•Renewable energy projects with an installed capacity equal to or greater than 50 MW will be licensed by ANLA. Previously, the limit was 100 MW.

•Decree 1275 of 2024 was issued, which establishes the environmental authority powers of indigenous communities in their territories.

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. During 2025, ANLA issued an environmental license modification for the connection line to cover the complete infrastructure of the project and started the environmental licensing process for the Jemeiwaa Ka’I 4 wind project.

Customers

We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2025 total revenue. In our generation business, we own and/or operate power plants to sell power to wholesale customers such as utilities and other intermediaries, as well as to large corporations. 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 Global Leadership Team with the guidance and oversight of our Board of Directors. Governance and standards for AES people are guided by the Chief Human Resources Officer, with input from members of the Global Leadership Team.

As of December 31, 2025, the Company and its subsidiaries had 8,336 full time/permanent employees.

As of December 31, 2025, approximately 31% 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

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from 2026 to 2027. In addition, certain employees in non-U.S. locations were subject to collective bargaining agreements, representing approximately 48% of the non-U.S. workforce. As of December 31, 2025, approximately 25% of our U.S. and non-U.S. workforce is part of bargaining agreements expiring on or before December 31, 2026. 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 ISO 45001 standard, and during 2025 approximately 48% of our locations (excluding renewable assets in the United States, more than 80% of which are smaller than 20 MW) have elected to formally certify their SMS to the 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 2025, there was an 11% decrease in AES' LTI cases. In 2025, AES’ LTI Rate was 0.086 for AES People, 0.118 for operational contractors, and 0.000 for construction contractors. In 2025, the Company did not have any work-related fatalities.

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.

Compensation

AES’ executive compensation philosophy emphasizes pay-for-performance. Our incentive plans are designed to reward strong performance, with greater compensation paid when performance exceeds expectations and less compensation paid when performance falls below expectations. We invest significant time and resources to ensure our compensation programs are competitive and reward the performance of our people. Every year, AES people who are not part of a collective bargaining agreement are eligible for an annual merit-based salary increase. In addition, individuals are eligible for a salary increase if they receive a significant promotion. For non-collectively bargained employees at certain levels in the organization, we offer annual incentives (bonus) and long-term compensation to reinforce the alignment between AES' employees and AES.

Executive Officers

The following individuals are our executive officers:

Stephen Coughlin, 54 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’ renewables portfolio. Mr. Coughlin is a member of the boards of AES Clean Energy Development Holdings, LLC, AES U.S. Investments, Inc., and IPALCO. Mr. Coughlin received a bachelor's

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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, 62 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 President and Chief Executive Officer of AES Clean Energy Development, and a member of the boards of IPALCO, AES Andes, AES Mong Duong Power Co. Ltd., 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, 46 years old, was appointed President effective March 2, 2026. Prior to assuming his current position, Mr. Falú served as Executive Vice President and Chief Operating Officer since February 2024, Senior Vice President and Chief Operating Officer from July 2023 to February 2024 and Senior Vice President and Chief Strategy and Commercial Officer from August 2022 to July 2023. From March 2023 to March 2026, Mr. Falú 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 IPALCO, Fluence Energy, Inc., AES Andes, DPL, 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, 56 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, 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 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, 68 years old, has been Chief Executive Officer and a member of our Board of Directors since September 2011 and is a member of the Innovation and Technology Committee. He also served as President from September 2011 to March 2026. 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, 50 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

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function from 2006 to 2008. Ms. Mendoza is a member of the boards of IPALCO, and Fluence Energy, Inc., 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, 49 years old, was appointed as Executive Vice President, Chief Operating Officer and President of the Energy Infrastructure SBU effective March 2, 2026. Prior to assuming his current position, Mr. Rubiolo served as Executive Vice President and President of the Energy Infrastructure SBU since March 2023, 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, and AES Colombia. Mr. Rubiolo has a Science Degree in Business from the Universidad Austral of Argentina, a Master of Project Management from the Quebec University in Canada and has completed the executive business and leadership program at the University of Virginia.

How to Contact AES and Sources of Other Information

Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is (703) 522-1315. Our website address is http://www.aes.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 (the "Exchange Act") are posted on our website. After the reports are filed with, or furnished to the SEC, they are available from us free of charge. Material contained on our website is not part of and is not incorporated by reference in this Form 10-K. The SEC maintains an internet website that contains the reports, proxy and information statements and other information that we file electronically with the SEC at www.sec.gov.

Our CEO and our CFO have provided certifications to the SEC as required by Section 302 of the Sarbanes-Oxley Act of 2002. These certifications are included as exhibits to this Annual Report on Form 10-K.

Our CEO provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on May 20, 2025.

Our Code of Business Conduct ("Code of Conduct") and Corporate Governance Guidelines have been adopted by our Board of Directors. The Code of Conduct is intended to govern, as a requirement of employment, the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. Our Ethics and Compliance Department provides training, information, and certification programs for AES employees related to the Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering, and associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to, or waivers from, the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.