2025 Annual Report Annual Report

2025

Annua report

Accelerating the

future of energy, together

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2025

-OR-

• TRANSITION REPORT FILED PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12291

(Exact name of registrant as specified in its charter)

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

(Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (703) 522-1315

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered

Common Stock, par value $0.01 per share AES New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange

Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been

subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ Accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ Non-accelerated filer ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2025, the last business day of the Registrant's most recently completed second fiscal quarter (based on the closing sale price of $10.52 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $7.49 billion.

The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 26, 2026 was 712,558,860.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant's Proxy Statement for its 2026 annual meeting of stockholders are incorporated by reference in Parts II and III

The AES Corporation Fiscal Year 2025 Form 10-K

Table of Contents

Glossary of Terms 1

PART I 3

ITEM 1. BUSINESS 4

ITEM 1A. RISK FACTORS 51

ITEM 1B. UNRESOLVED STAFF COMMENTS 69

ITEM 1C. CYBERSECURITY 69

ITEM 2. PROPERTIES 70

ITEM 3. LEGAL PROCEEDINGS 71

ITEM 4. MINE SAFETY DISCLOSURES 75

PART II 76

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 76

ITEM 6. [RESERVED] 77

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 78

Executive Summary 78

Review of Consolidated Results of Operations 79

SBU Performance Analysis 85

Key Trends and Uncertainties 92

Capital Resources and Liquidity 100

Critical Accounting Policies and Estimates 109

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 114

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 117

Consolidated Balance Sheets 120

Consolidated Statements of Operations 121

Consolidated Statements of Comprehensive Income (Loss) 122

Consolidated Statements of Changes in Equity 123

Consolidated Statements of Cash Flows 125

Note 1 - General and Summary of Significant Accounting Policies 127

Note 2 - Inventory 140

Note 3 - Property, Plant, and Equipment 140

Note 4 - Asset Retirement Obligations 141

Note 5 - Fair Value 141

Note 6 - Derivative Instruments and Hedging Activities 147

Note 7 - Financing Receivables 148

Note 8 - Allowance for Credit Losses 149

Note 9 - Investments in and Advances to Affiliates 150

Note 10 - Goodwill and Other Intangible Assets 151

Note 11 - Regulatory Assets and Liabilities 153

Note 12 - Obligations 154

Note 13 - Commitments 160

Note 14 - Contingencies 160

Note 15 - Leases 162

Note 16 - Benefit Plans 164

Note 17 - Redeemable Stock of Subsidiaries 167

Note 18 - Equity 170

Note 19 - Segments and Geographic Information 175

Note 20 - Share-Based Compensation 180

Note 21 - Revenue 182

Note 22 - Other Income and Expense 183

Note 23 - Asset Impairment Expense 185

Note 24 - Income Taxes 187

Note 25 - Held-for-Sale and Dispositions 192

Note 26 - Acquisitions 194

Note 27 - Earnings Per Share 196

Note 28 - Risks and Uncertainties 198

Note 29 - Related Party Transactions 199

Note 30 - Restructuring 200

Note 31 - Discontinued Operations 200

Note 32 - Subsequent Events 201

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 202

ITEM 9A. CONTROLS AND PROCEDURES 202

ITEM 9B. OTHER INFORMATION 205

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 205

PART III 206

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 206

ITEM 11. EXECUTIVE COMPENSATION 206

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 206

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 206

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 207

PART IV - ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE 208

SIGNATURES 211

‌Glossary of Terms

The following is a list of frequently used terms and abbreviations that appear in the text of this report and have the definitions indicated below:

2024 Base Rate Order

The order issued in April 2024 by the IURC authorizing AES Indiana to, among other things, increase its basic rates and charges by $71 million annually

2024 DRC Settlement

The order issued in November 2025 by the PUCO authorizing AES Ohio to, among other things, increase its basic rates and charges by $168 million annually

Adjusted EBITDA

Adjusted earnings before interest income and expense, taxes, depreciation, amortization, and accretion of AROs, a non-GAAP measure of operating performance

Adjusted earnings before interest income and expense, taxes, depreciation, amortization, and accretion of AROs,

Adjusted EBITDA with Tax Attributes

adding back the pre-tax effect of Production Tax Credits, Investment Tax Credits, and depreciation tax deductions allocated to tax equity investors, as well as the tax benefit recorded from tax credits retained or transferred to third parties, a non-GAAP measure

Adjusted EPS Adjusted Earnings Per Share, a non-GAAP measure

Adjusted PTC Adjusted Pre-tax Contribution, a non-GAAP measure of operating performance AES The Parent Company and its subsidiaries and affiliates

AES Andes AES Andes S.A., formerly AES Gener

AES Brasil AES Brasil Energia S.A.

AES Indiana Indianapolis Power & Light Company, formerly branded as IPL. AES Indiana is wholly-owned by IPALCO

The Dayton Power & Light Company, formerly branded as DP&L. For the periods covered by this report, AES Ohio

AES Ohio

AES Renewable Holdings

was wholly-owned by DPL. Beginning in April 2025, CDPQ owns an aggregate indirect equity interest in AES Ohio of approximately 30%.

AES Renewable Holdings, LLC, formerly branded as AES Distributed Energy

AFUDC Allowance for Funds Used During Construction

ANEEL Brazilian National Electric Energy Agency

AOCL Accumulated Other Comprehensive Loss

ARO Asset Retirement Obligations

ASC Accounting Standards Codification

BESS Battery Energy Storage System

BOT Build, Operate and Transfer

CAA U.S. Clean Air Act

CAMMESA Wholesale Electric Market Administrator in Argentina CCGT Combined Cycle Gas Turbine

CCR Coal Combustion Residuals, which include bottom ash, fly ash, and air pollution control wastes generated at coal-fired generation plant sites

CDPQ La Caisse de dépôt et placement du Québec

CECL Current Expected Credit Loss

CEO Chief Executive Officer

CFE Federal Electricity Commission in Mexico

CFO Chief Financial Officer

CO2Carbon Dioxide

CPI U.S. Consumer Price Index

CSAPR U.S. Cross-State Air Pollution Rule

CWA U.S. Clean Water Act

CWIP Construction Work In Progress

DG Comp Directorate-General for Competition of the European Commission

DPL LLC and its consolidated subsidiaries. On April 3, 2025, DPL Inc. converted its form of business organization from

DPL

an Ohio corporation to an Ohio limited liability company. Upon the conversion, DPL Inc. changed its name to DPL LLC. References to DPL are to DPL Inc. before April 3, 2025, and DPL LLC on and after April 3, 2025.

DPP Dominican Power Partners

EBITDA

Earnings before interest income and expense, taxes, depreciation, amortization, and accretion of AROs, a non-GAAP measure of operating performance

EPA U.S. Environmental Protection Agency

EPC Engineering, Procurement, and Construction

ESP Electric Security Plan

EU European Union

EVN Electricity of Vietnam

FERC U.S. Federal Energy Regulatory Commission

Fluence Fluence Energy, Inc and its subsidiaries, including Fluence Energy, LLC, which was previously our joint venture with Siemens AG (Nasdaq: FLNC)

FONINVEMEM Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market in Argentina FPA U.S. Federal Power Act

GAAP Generally Accepted Accounting Principles in the United States

GHG Greenhouse Gas

GILTI Global Intangible Low-Taxed Income

GW Gigawatts

GWh Gigawatt Hours

HLBV Hypothetical Liquidation Book Value

IPALCO IPALCO Enterprises, Inc. CDPQ owns direct and indirect interests in IPALCO of approximately 30%. IPP Independent Power Producers

ISO Independent System Operator

ITC Investment Tax Credit

IURC Indiana Utility Regulatory Commission

LGR Legacy Generation Resource Rider

LNG Liquefied Natural Gas

MISO Midcontinent Independent System Operator, Inc.

MMBtu Million British Thermal Units

MRO Market Rate Option, a market-based plan that a utility may file with PUCO to establish SSO rates pursuant to Ohio law MW Megawatts

MWh Megawatt Hours

NAAQS U.S. National Ambient Air Quality Standards

NCI Noncontrolling Interest

NCTI Net Controlled Foreign Corporation Tested Income

NEK Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria) NERC North American Electric Reliability Corporation

NM Not Meaningful

NOV Notice of Violation

NOXNitrogen Dioxide

NPDES National Pollutant Discharge Elimination System

NSPS New Source Performance Standards

O&M Operations and Maintenance

OCC

Ohio Consumers' Counsel (statewide legal representative for Ohio's residential consumers and advocates on their behalf in PUCO and Ohio Supreme Court proceedings)

OTC Policy Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling OVEC Ohio Valley Electric Corporation, an electric generating company in which AES Ohio has a 4.9% interest Parent Company The AES Corporation

PCU Performance Cash Units

Pet Coke Petroleum Coke

PJM PJM Interconnection, LLC

PM Particulate Matter

PPA Power Purchase Agreement

PREPA Puerto Rico Electric Power Authority

PSU Performance Stock Unit

PUCO The Public Utilities Commission of Ohio

PURPA U.S. Public Utility Regulatory Policies Act

REC Renewable Energy Credit

RSU Restricted Stock Unit

RTO Regional Transmission Organization

SADI Argentine Interconnected System

SBU Strategic Business Unit

SEC U.S. Securities and Exchange Commission

SEET Significantly Excessive Earnings Test

SEN Sistema Electrico Nacional in Chile

SIN National Interconnected System in Colombia

SIP State Implementation Plan

SO2Sulfur Dioxide

SWRCB California State Water Resources Board

TDSIC Transmission, Distribution, and Storage System Improvement Charge

U.S. United States

USD United States Dollar

VIE Variable Interest Entity

Vinacomin Vietnam National Coal and Mineral Industries Holding Corporation Limited

In this Annual Report the terms "AES," "the Company," "us," or "we" refer to The AES Corporation and all of its subsidiaries and affiliates, collectively. The terms "The AES Corporation" and "Parent Company" refer only to the parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates.

Forward-Looking Information and Risk Factor Summary

In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.

Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:

• the economic climate, particularly the state of the economy in the areas in which we operate, which impacts demand for electricity in many of our key markets, including the fact that the global economy faces considerable uncertainty for the foreseeable future, which further increases many of the risks discussed in this Form 10-K;

• changes in the price of electricity at which our generation businesses sell into the wholesale market and our utility businesses purchase to distribute to their customers, and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk;

• changes in the prices and availability of coal, gas, and other fuels (including our ability to have fuel transported to our facilities) and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts;

• changes in and access to the financial markets, particularly changes affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments, and other corporate purposes;

• changes in inflation, demand for power, interest rates, and foreign currency exchange rates, including our ability to hedge our interest rate and foreign currency risk;

• our ability to fulfill our obligations, manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our revolving credit facilities and other existing financing obligations;

• our ability to receive funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise;

• changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria;

• our ability to purchase and sell assets at attractive prices and on other attractive terms;

• our ability to compete in markets where we do business;

• our ability to operate power generation, transmission and distribution facilities, including managing availability, outages, and equipment failures;

• our ability to manage our operational and maintenance costs and the performance and reliability of our generating plants, including our ability to reduce unscheduled down times;

• our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these agreements;

• variations in weather, especially mild winters and cooler summers in the areas in which we operate, the occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other storms and disasters, wildfires and low levels of wind or sunlight for our wind and solar facilities;

• pandemics, or the future outbreak of any other highly infectious or contagious disease;

• the performance of our contracts by our contract counterparties, including suppliers or customers;

• severe weather and natural disasters;

• ‌our ability to manage global supply chain disruptions;

• our ability to raise sufficient capital to fund development projects or to successfully execute our development projects;

• the success of our initiatives in renewable energy projects and energy storage projects;

• the availability of government incentives or policies that support the development of renewable energy generation projects;

• our ability to execute on our strategies or achieve expectations related to environmental, social, and governance matters;

• our ability to keep up with advances in technology;

• changes in number of customers or in customer usage;

• the operations of our joint ventures and equity method investments that we do not control;

• our ability to achieve reasonable rate treatment in our utility businesses;

• changes in laws, rules and regulations affecting our international businesses, particularly in developing countries;

• changes in laws, rules and regulations affecting our utilities businesses, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities;

• changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business and solar projects, our other renewables projects, and our initiatives in GHG reductions and energy storage, including government policies or tax incentives;

• changes in environmental laws, including requirements for reduced emissions, GHG legislation, regulation, and/or treaties and CCR regulation and remediation;

• changes in tax laws, including U.S. tax reform, and challenges to our tax positions;

• the effects of litigation and government and regulatory investigations;

• the performance of our acquisitions;

• our ability to maintain adequate insurance;

• decreases in the value of pension plan assets, increases in pension plan expenses, and our ability to fund defined benefit pension and other postretirement plans at our subsidiaries;

• losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets;

• changes in accounting standards, corporate governance, and securities law requirements;

• our ability to maintain effective internal control over financial reporting;

• our ability to remediate the material weakness described in Item 9A;

• our ability to attract and retain talented directors, management, and other personnel;

• cyber-attacks and information security breaches; and

• data privacy.

These factors, in addition to others described elsewhere in this Form 10-K, including those described under Item 1A.-Risk Factors and in subsequent securities filings, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward-looking information.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

ITEM 1. BUSINESS

Item 1.-Business is an outline of our strategy and our businesses by SBU, including key financial drivers.

Additional items that may have an impact on our businesses are discussed in Item 1A.-Risk Factors and Item 3.-

Legal Proceedings.

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

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

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.

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,

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,

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.

Operating Margin Adjusted EBITDA

Renewables 25%

Renewables 32%

Energy Infrastructure 44%

Utilities 31%

Energy Infrastructure 39%

Utilities 29%

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.

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

Renewables

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:

Laurel Mountain ES (OpCo E) (3) US-WV Energy

Storage

16 100 % 2011

(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.

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.

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

  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.

  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

  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.

(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.

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:

AES Ohio (1) US-OH Transmission

& Distribution

70 % 541,000 14,729 2011

AES Indiana (2) US-IN

Integrated

70 %

533,000

15,579

Coal/Gas/ Oil/Solar/ Energy Storage/

Wind

4,056

2001

United States Subtotal 1,074,000 30,308 4,056

2,741,000 35,052

(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.

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

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

  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

  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

  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

  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.

(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.

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:

(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

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

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 longterm 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.

  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;

• 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 CO2emissions 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:

• 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.

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.

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.